UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Form 10-K/A

(Amendment No. 1)



|x | ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ------------------------------------------------------------------------------

For the fiscal year ended December 31, 2008

Commission file number 001-32977

GMX RESOURCES INC.

(Exact name of
registrant as specified in its charter)



|                                                              |  |                                    
|------------------------------------------------------------- |  | -----------------------------------
|Oklahoma                                                      |  | 73-1534474                         
|(State or other jurisdiction ofincorporation or organization) |  | (I.R.S. EmployerIdentification No.)
|                                                              | 
|9400 North Broadway,Suite 600, Oklahoma City, Oklahoma        |  | 73114                              
|(Address of principal executive offices)                      |  | (Zip Code)                         

(Registrants telephone number, including area code) (405) 600-0711

Securities registered under Section 12(b) of the Exchange Act:



|                                                      |  |                                     
|----------------------------------------------------- |  | ------------------------------------
|Title of Class                                        |  | Name of Exchange on Which Registered
|Common Stock, $0.001 par value                        |  | NASDAQ Global Select Market         
|Series B Cumulative Preferred Stock, $0.001 par value |  | NASDAQ Global Select Market         
|Series A Preferred Stock Purchase Rights              |  | NASDAQ Global Select Market         

Securities registered under Section 12(g) of the Exchange Act: None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act.    Yes   ̈    No  x

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ̈    No  x

Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days.    Yes  x    No   ̈

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained,
to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K   ̈.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.
See definition of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. Check one:



|                           |  |                             
|-------------------------- |  | ----------------------------
|Large accelerated filer  x |  | Accelerated filer   ̈        
|Non-accelerated filer   ̈   |  | Smaller reporting company   ̈

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act)      Yes   ̈    No  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked prices of
such common equity, as of the last business day of the registrants most recently completed second fiscal quarter. As of June 30, 2008 aggregate market value was $1,109,107,978.

Indicate the number of shares outstanding of each of the registrants classes of common stock, as of the latest practicable date: As of
February 26, 2009, there were 18,794,691 shares of Common Stock, par value $.001 per share, outstanding, which included 3,440,000 shares under a share loan which will be returned to the registrant upon conversion or maturity of certain
outstanding convertible notes.

DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Companys definitive proxy statement for its 2009
annual meeting of shareholders are incorporated into Part III of this Form 10-K by reference.









---

EXPLANATORY NOTE

This Amendment on Form 10-K/A constitutes Amendment No. 1 to the Companys Annual Report on Form 10-K for the period ended December 31, 2008, which was filed with the SEC on March 2, 2009 (Original Filing).
This Amendment No. 1 to Form 10-K is filed solely for purposes of correcting the following typographical or clerical errors:



| | 1. | The table showing estimated net quantities of proved reserves and the Estimated Future Net Revenues and Present Values attributable to total proved reserves at such dates in
Item 1 is amended to change the Estimated Future Net Revenues for December 31, 2008 from $2,586.6 to $1,012.3.
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 2. | The table showing the unaudited summary of certain operating and oil and natural gas reserve data in Item 7 is amended to change the Estimated Future Net Revenues for
December 31, 2008 from $2,586.6 to $1,012.3.
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Pursuant to the rules of the Securities and Exchange Commission,
the full text of each Item as amended is included in this report, even though there are no other amendments to such Items.

Except as described herein, no
other changes have been made to the Original Filing. The Original Filing continues to speak as of the date of the Original Filing, and we have not updated the disclosures contained therein to reflect any events which occurred at a date subsequent to
the filing of the Original Filing.



---

PART I



|Item 1. | Business
|------- | --------

General

GMX Resources Inc.(the Company, we or us) is a pure play independent oil and natural gas
exploration and production company focused on development of unconventional Haynesville/Bossier Shale and Cotton Valley Sands in the Sabine Uplift of the Carthage, North Field of Harrison and Panola counties of East Texas (our core
area). We state that we are a pure play company because materially all of our business is devoted to drilling for and producing oil and natural gas in one core area.

We have two subsidiaries, Diamond Blue Drilling Co. (Diamond Blue), which owns and operates three drilling rigs in our core area, and
Endeavor Pipeline Inc. (Endeavor), which owns and operates our gathering system in our core area.

Our principal executive
office is located at 9400 North Broadway, Suite 600, Oklahoma City, Oklahoma, 73114 and our telephone number is (405) 600-0711.

History

We were incorporated in 1998 and acquired producing and undeveloped oil and natural gas properties located primarily in our core area,
Kansas and southeastern New Mexico from a bankruptcy reorganization of a small, privately-held company. We have leased more undeveloped acreage and drilled wells in our core area since 1998. We have since sold the Kansas properties and concentrated
our efforts in our core area, primarily since 2003 when we entered into a joint development agreement with Penn Virginia Oil & Gas, L.P. (PVOG), a wholly-owned subsidiary of Penn Virginia Corporation (NYSE: PVA). Although this
joint development agreement has expired, we continue to own acreage in our core area jointly with PVOG.

Strategy

Our strategy is to grow shareholder value through Haynesville/Bossier Shale horizontal well development as well as Cotton Valley Sand vertical wells, to
continue acreage acquisitions, to focus on operational growth in and around our core area, and to convert our unproved natural gas reserves to proved reserves, while maintaining balanced prudent financial management. To date, we have experienced a
100% success rate and have maintained low finding and development costs while primarily drilling Cotton Valley Sand vertical wells. Late in the second quarter of 2008, we switched our strategy from developing the Cotton Valley Sands with vertical
wells to the development of Haynesville/Bossier Shale with horizontal wells due to the strong economic profile estimated to be associated with this play.

Develop Haynesville/Bossier acreage. As of December 31, 2008, we had approximately
57,700 gross (38,600 net) acres in the Haynesville/Bossier areas, representing an estimated 480 net unproved drilling locations based on 80-acre well spacing. Initial estimates indicate that the economics of a Haynesville/Bossier Shale well may be
significantly better than economics associated with a single Cotton Valley or Travis Peak well. Therefore, we have begun a development program in this formation to prove up potential resources of the play, as well as to enhance cash flow and
shareholder value. As of December 31, 2008, we had drilled and completed one Haynesville/Bossier horizontal well and two horizontal wells were drilled and waiting on completion. We were in the process of drilling three Haynesville/Bossier
horizontal wells at year-end 2008. The first completed well, Callison 9H (100% working interest), located in Harrison County, Texas and with our shortest planned lateral of 2,000 feet, held an initial production rate of 7.7 Mmcf per day. In 2009, we
estimate that we will drill approximately 25 net Haynesville/Bossier horizontal wells using primarily four Helmerich & Payne (H&P) FlexRigs.

Expand and maintain production infrastructure. We have built a significant amount of production infrastructure in our core area, which allows us
to control marketing, processing and delivery options for the sale



1



---

of our natural gas and oil. We plan to continue pursuing the best markets for sale of our production and prudently expanding our infrastructure to keep pace
with increasing production volumes as we develop our Haynesville/Bossier Shale play.

Fit for purpose drilling rigs. We own and operate three rigs, two of which have the capacity to drill Haynesville/Bossier horizontal wells, and we are currently using two H&P FlexRigsunder well to well
contracts, which allow us the flexibility to pursue our Haynesville/Bossier horizontal drilling plan while having the ability to scale back, if necessary, in a declining commodity price environment. During 2008, we contracted with H&P for four
new FlexRigsfor three year terms to be delivered during 2009, which will be focused exclusively on horizontal development of the Haynesville/Bossier gas shale in our operated acreage. As a result of declining commodity prices,
we laid down one of our owned rigs prior to year end 2008 and plan to lay down our other two owned rigs in the first quarter of 2009 when our first two long-term FlexRigsarrive. We plan to bring our owned rigs back into
operation upon an improvement in natural gas prices. The two FlexRigsthat are on well to well contracts are currently planned to be released in the second half of 2009.

Expand acreage position. We plan to continue expansion of our acreage position in our core area beyond our current 10-15 year drilling inventory
based on current rig utilization and commodity prices, focusing on acreage we will operate. We also intend to review and pursue acquisitions of other properties in our core area, our region or possibly other areas that complement our goal of
building shareholder value. From December 31, 2007, to December 31, 2008, we increased our net Haynesville/Bossier acreage position from 18,000 to 38,600 acres, an increase of approximately 114%.

Use leverage and hedging prudently. We expect to fund our drilling activities by maintaining leverage at or near levels equal to
shareholders equity and accessing equity-based funding when market conditions warrant with the goal of limiting dilution to our existing shareholders. We have hedging instruments in place for 2009 for 20,600 Mcfe/day or approximately 67% of
our current daily natural gas and crude oil production as of December 31, 2008, and additional hedges exist for production in 2010 and 2011. We plan to continue to use hedging to mitigate commodity price risks and as required by agreements with
our lenders.

Company Strengths

Large, continuous acreage position in the heart of the East Texas Haynesville/Bossier Shale and Cotton Valley natural gas plays. The Haynesville/Bossier Shale has only recently received recognition of its potential, with multiple
operators entering the play with intentions to contribute significant amounts of capital to development of this resource. We believe that early successful results associated with nearby and offsetting Haynesville/Bossier Shale wells provide further
support for our development strategy. We acquired the vast majority of our Haynesville/Bossier Shale position prior to 2008, and have yet to tap the potential available through this play. In 2006, 19 vertical test wells were drilled across our
properties. These delineation wells confirmed a consistent 350 foot layer of Haynesville/Bossier Shale present. These wells have substantially reduced the risk associated with our Haynesville/Bossier acreage, which allowed us to begin drilling
horizontally in 2008. A significant portion of our Haynesville/Bossier Shale acreage is held by production from our shallower Cotton Valley, Travis Peak and Hosston wells, which also gives us the ability to drill where we choose without risk of
lease expiration.

The Cotton Valley resource play is mature and well-understood with many large operators producing natural gas from
positions offset to our acreage. As a result of this maturity, drilling results are highly predictable, and we have had a 100% drilling success rate in our seven-year history in the Cotton Valley.

Strong growth profile. Our inventory of nearly 2,000 net proved and unproved Cotton Valley Sand drilling locations and 483 net (721 gross) proved
and unproved Haynesville/Bossier Shale locations as of December 31, 2008 is expected to provide us with the ability to continue to grow production and reserves at a high rate. We have grown production and reserves at 75% and 39%, respectively,
on average per year for 2007 and 2008.



2



---

Favorable economics achieved through investment in infrastructure. We have invested over $101
million in our core area for pipeline gathering systems with approximately 140 miles of gathering and takeaway capacity, compression, salt water disposal and other field infrastructure and in three drilling rigs, two of which we use to drill
horizontal Haynesville/Bossier Shale wells. Our net realized price for natural gas volumes sold, including sales of processed liquids, and excluding the effects of hedging, was 95% of the NYMEX price for calendar year 2008. With our current
production of 31 MMcfe per day and our takeaway capacity of 80 MMcf per day as of December 31, 2008, we believe there is sufficient capacity based on current infrastructure to support material growth in production.

Low finding and development costs. Our finding and development costs have averaged $1.38 per Mcfe over the last three calendar years. Finding and
development costs are calculated by dividing the sum of total exploration and development capital costs by the sum of total additions to estimated proved reserves for the years ended December 31, 2008, 2007 and 2006. Finding and
development costs are defined in Part I, Item 1Certain Technical Terms. The Cotton Valley is considered to be an unconventional natural gas resource that is pervasive throughout large areas, which explains our drilling success in
this formation. As a result, we did not have any exploration capital costs (i.e., finding costs) in 2007 or 2006. However, in 2008, the Company had finding costs of $12.2 million related to exploration activities in the
Haynesville/Bossier Shale formation.

East Texas

As of December 31, 2008, we owned 386 gross (236 net) producing wells. In our East Texas core area 323 gross (186 net) wells are Cotton Valley wells at depths of 8,000 to 12,000 feet and 56 gross (51 net) wells
are productive in the shallower conventional Rodessa, Travis Peak, Hosston and Pettit formations in our core area. In addition we had one Haynesville/Bossier horizontal well producing at year-end 2008. We have grown by developing in our core area
with a 100% success rate with low finding and development costs. At December 31, 2008, we had 464.2 Bcfe of proved reserves, which were 94% natural gas, 34% proved developed and more than 99% located in our core area.

We presently have focused the majority of our development efforts on the Haynesville/Bossier Shale areas. As of December 31, 2008, we have
approximately 57,700 gross and 38,600 net acres in the Haynesville/Bossier Shale areas, representing an estimated 721 gross (483 net) proved and unproved drilling locations based on 80-acre well spacing.

As of December 31, 2008, we have approximately 60,900 gross and 41,300 net acres in the Cotton Valley area, with 342 net undrilled proved
undeveloped Cotton Valley drilling locations based on 20-acre well spacing.

Our core area properties accounted for more than 99% of our
total proved reserves at December 31, 2008, 96% of our total net acreage and 99% of our 2008 production.

We operate 158 wells or 41%
of our core area gross wells that produce 65% of our oil and natural gas production, as of December 31, 2008. Average daily production net to our interest in 2008 was 32,177 Mcf of gas and 520 Bbls of oil. The producing lives of these fields
are generally over 12 to 70 years. Gas sold from the area has a high MMBtu content, which after processing, can result in a net price above average daily Henry Hub natural gas prices. Oil is sold separately at a slight discount to the average Sweet
Crude oil price at Cushing, Oklahoma (the NYMEX delivery point), inclusive of deductions. Most of our future development will be added to existing gathering systems under comparable pricing and contracts. The acreage in East Texas lies on the Sabine
Uplift, a broad positive feature that acts as a structural trap for most reservoirs. Most of the reservoirs are shallow and deep marine sediments that tend to have tremendous aerial extent and substantial thicknesses. Natural gas and oil production
has been produced from 3,000 feet to 11,700 feet in our core area. Prior to shifting our focus to the Haynesville/Bossier, the primary objective of our development was the Cotton Valley Sand, which occurs between 8,200 feet and 10,000 feet and
contains multiple layers of sands containing natural gas. Due to the multiple layers and widespread deposition of these gas saturated layers, we have a very high success rate of finding commercial wells.



3



---

The following table sets forth the gross and net wells drilled in our core area in 2008:



|                            |  |                               |  |     
|--------------------------- |  | ----------------------------- |  | ----
|                            |  | Wells Drilled &Completed 2008
|                            |  | Gross                         |  | Net 
|Cotton Valley Sands         |  |                               |  |     
|Operated                    |  | 38.0                          |  | 37.5
|50% joint venture with PVOG |  | 23.0                          |  | 10.6
|30% joint venture with PVOG |  | 24.0                          |  | 7.2 
|                            |  |                               |  |     
|                            |  | 85.0                          |  | 55.3
|Haynesville/Bossier         |  |                               |  |     
|Horizontal                  |  | 1.0                           |  | 1.0 
|                            |  |                              
|Other                       |  |                               |  |     
|Shallower formations        |  | 4.0                           |  | 3.9 
|                            |  |                               |  |     
|Total                       |  | 90.0                          |  | 60.2
|                            |  |                               |  |     

In early 2006, we drilled and completed 19 vertical Haynesville/Bossier wells across our property
base. The exploratory work found a gas rich unconventional reservoir below the Cotton Valley Sands. We determined from these tests that the reservoirs were very homogenous across all of our acreage in Harrison and Panola counties. We did extensive
open hole logging, coring and a variety of completion methods which determined, in our view, a viable horizontal unconventional candidate. We subsequently joined Core Labs Gas Shale consortiums (with approximately 50 other E&P companies) to
learn from other operators about horizontal shale development. In early 2008 several E&P companies achieved great success in horizontal Haynesville/Bossier exploration near our properties. We determined the Haynesville/Bossier potential on our
properties to be of greater value than the Cotton Valley Sand and gathered the resources necessary to begin Haynesville/Bossier horizontal development. We were also the first company to join Core Labs Haynesville/Bossier Consortium. Currently, we
have successfully drilled and completed three Haynesville/Bossier horizontal wells and are drilling four additional horizontal wells. We plan to drill 25 horizontal wells for 2009 and are spending 98% of our 2009 planned capital expenditures on
Haynesville/Bossier horizontal wells, related infrastructure and acreage.

Our capital expenditures in 2008 were $328.9 million, of which
$39.8 million was expended for tubular and other drilling inventories, $14.4 million for exploratory Haynesville/Bossier drilling in progress at December 31, 2008, $38.2 million was expended on rigs, equipment and gathering systems and the
balance was used for drilling and completion of wells, acreage acquisitions and recompletions. The average Cotton Valley vertical well cost for 2008 was approximately $2.1 million.

In 2008, we funded our drilling and development activity in our core area with proceeds of a $125 million offering of our 5.00% convertible senior notes
due 2013 in February 2008 and a $141 million common stock offering in July 2008, along with proceeds from borrowings on our revolving bank credit facility and cash flow from operations.

The following table sets forth our proved undeveloped locations in our core area as of December 31, 2008:



|                            |  |                             |  |      
|--------------------------- |  | --------------------------- |  | -----
|                            |  | Proved UndevelopedLocations
|                            |  | Gross                       |  | Net  
|Operated                    |  | 243.0                       |  | 243.0
|50% joint venture with PVOG |  | 99.0                        |  | 49.5 
|30% joint venture with PVOG |  | 183.0                       |  | 54.9 
|                            |  |                             |  |      
|Total                       |  | 525.0                       |  | 347.4
|                            |  |                             |  |      

The operated area includes two Haynesville/Bossier Shale proved undeveloped locations at
December 31, 2008.



4



---

The pace of future development of this property will depend on availability of capital, future drilling
and completion results, the general economic conditions of the energy industry and on the price we receive for the natural gas and crude oil produced. Additionally, in certain areas in which we own our interest jointly with PVOG, the pace of future
development will depend on PVOGs level of activity in those areas. Depending on rig availability and funding. We plan on drilling 25 net Haynesville/Bossier Shale horizontal wells in 2009.

If borrowings are not available under our revolving bank credit facility, we may be required to reduce or defer part of our 2009 capital expenditure
program or seek additional capital through the issuance of long-term debt or equity.

The number of wells we drill in 2009 will vary, and
our potential capital expenditures may vary depending on the number of wells drilled, drilling and completion results, rig availability and other factors. We have budgeted $220 million for capital expenditures in 2009, of which $177 million will be
for Haynesville/Bossier horizontal drilling and the balance for acreage acquisitions, developing gathering systems infrastructure and other capital expenditures. We will fund our drilling expenses primarily from internal cash flow and borrowings
under our revolving bank credit facility.

As of December 31, 2008, there were four rigs drilling our acreage, two of which are owned
by our wholly-owned subsidiary, Diamond Blue, and two of which is on a contract without obligation to us for long-term use. There were no rigs under contract to PVOG that were drilling in our jointly-owned areas at year-end 2008.

Other Properties

We have approximately 600 gross
(369 net) acres in the Waskom Field in Clairborne, Caddo, Cataboula and Webster parishes in Louisiana with 5 gross (2.6 net) producing wells, three of which we operate. We also have properties located in Lea and Roosevelt counties, New Mexico,
consisting of approximately 1,920 gross (1,458 net) acres with 9 gross (5.7 net) non-operated producing wells. Total reserves and production from these areas represent less than 1% of our proved reserves and 2008 production. We are not actively
pursuing additional development of the New Mexico properties.

2009 Plans and Recent Developments

We have 57,700 (38,600 net) acres that are prospective for Haynesville/Bossier development, giving
us a total of 721 gross (483 net) 80-acre Haynesville/Bossier horizontal drilling locations. We have recently completed two Haynesville/Bossier horizontal wells and currently have an additional four Haynesville/Bossier horizontal wells drilling. Our
Haynesville/Bossier horizontal development in East Texas/Northwest Louisiana continues to be very successful. Our second Haynesville/Bossier horizontal well, the Bosh #11H (100% working interest), was completed in late January, 2009, and had a 24
hour production rate of 7.6 Mmcf per day on a 30/64thchoke at 4,000 pounds of flowing casing pressure. The lateral length was 3,100 feet. The
well had ten fracture treatment stages. Our third Haynesville/Bossier horizontal well, the Baldwin #17H (100% working interest), was completed in February, 2009 and had a 24 hour production rate of 8.7 Mmcf per day on a 30/64thchoke at 4,200 pounds of flow casing pressure. The lateral length of this well was 4,400 feet in the upper sub-layer of the Haynesville/Bossier Shale. The
well had twelve fracture treatment stages. We are locating the laterals of all four Haynesville/Bossier wells currently drilling in the upper sub-layer of the Haynesville/Bossier Shale. We expect the four horizontal wells currently drilling to be
completed in the second quarter of 2009. We plan to drill 25 net Haynesville/Bossier horizontal wells in 2009, with projected lateral lengths averaging 4,560 feet.

Gas Gathering

We have acquired, constructed and own, through our wholly-owned subsidiary, Endeavor, gas gathering lines and
compression equipment for gathering and delivery of natural gas from our core area that we operate. As of December 31, 2008, we had invested approximately $60 million in this gathering system, including the



5



---

purchase of compressors, which consisted of approximately 140 miles of gathering lines and compressors that collect and compress gas from approximately 99%
of our gas production from wells in our core area. At year end 2008, our gas gathering system had takeaway capacity of 80 MMcf per day compared to our year end production volumes of 31 MMcf per day. In 2009, we expect to build additional miles of
pipeline and purchase necessary compressors. This system enables us to improve the control over our production and enhances our ability to obtain access to pipelines for ultimate sale of our gas. We only gather gas from wells in which we own an
interest. Remaining gas is gathered by unrelated third parties. Endeavor also serves as first purchaser of gas from wells for which we are the operator. See Item 1. BusinessMarketing.

PVOG has installed and operates gathering facilities to each of the wells drilled and operated by PVOG in our jointly-owned areas. PVOG charges us a
gathering fee of $0.10/MMBtu and actual cost of compression plus five percent (5%) for all gas gathered at the wellhead and redelivered to a central sales point. At year end 2008, the PVOG gathering system had takeaway capacity of 80 MMcf per
day compared to production of 32.7 MMcf per day.

Diamond Blue Drilling

Our subsidiary, Diamond Blue, owns three drilling rigs as described below:



|        |  |                      |  |                     |  |                     
|------- |  | -------------------- |  | ------------------- |  | --------------------
|        |  | Depth Capacity(Feet) |  | DrawworksHorsepower |  | HorizontalCapability
|DBD #7  |  | 11,000               |  | 1,000 HP            |  | No                  
|DBD #9  |  | 15,000               |  | 1,200 HP            |  | Yes                 
|DBD #11 |  | 14,000               |  | 1,000 HP            |  | Yes                 

We have approximately $30.5 million invested in these rigs, which are used to drill exclusively on
our 100% owned acreage and two of which are presently deployed exclusively for drilling horizontal Haynesville/Bossier Shale wells. The ownership of rigs enables us to better control drilling costs and protects us from rig availability risks when
rigs are in high demand. Due to the decline in natural gas prices and our long-term drilling contracts for four rigs from H&P, we intend to lay these rigs down in 2009 until natural gas prices increase and capital is available to accelerate our
drilling program.

Reserves

As of
December 31, 2008, MHA Petroleum Consultants, Inc. estimated our proved reserves to be 465.3 Bcfe. An estimated 162.1 Bcfe is expected to be produced from existing wells and another 303.2 Bcfe is classified as proved undeveloped. Substantially
all of our proved reserves relate to our Cotton Valley Sands development. All of our proved undeveloped reserves are on locations that are adjacent to wells productive in the same formations.



6



---

The following table shows the estimated net quantities of our proved reserves as of the dates indicated
and the Estimated Future Net Revenues and Present Values attributable to total proved reserves at December 31:



|                                      |  |      |       |      |   |         |  |   |        
|------------------------------------- |  | ---- | ----- | ---- | - | ------- |  | - | -------
|                                      |  | 2006 |       | 2007 |   | 2008   
|Proved Developed:                     |  |      |       |      |   |         |  |   |        
|Gas (Bcf)                             |  |      | 69.3  |      |   | 144.2   |  |   | 150.6  
|Oil (MMBbls)                          |  |      | .9    |      |   | 1.8     |  |   | 1.9    
|Total (Bcfe)                          |  |      | 74.9  |      |   | 155.0   |  |   | 162.1  
|Proved Undeveloped:                   |  |      |       |      |   |         |  |   |        
|Gas (Bcf)                             |  |      | 167.6 |      |   | 262.1   |  |   | 284.7  
|Oil (MMBbls)                          |  |      | 1.8   |      |   | 2.9     |  |   | 3.1    
|Total (Bcfe)                          |  |      | 178.1 |      |   | 279.5   |  |   | 303.2  
|Total Proved:                         |  |      |       |      |   |         |  |   |        
|Gas (Bcf)                             |  |      | 236.9 |      |   | 406.3   |  |   | 435.3  
|Oil (MMBbls)                          |  |      | 2.7   |      |   | 4.7     |  |   | 5.0    
|Total (Bcfe)                          |  |      | 253.0 |      |   | 434.5   |  |   | 465.3  
|Estimated Future Net Revenues1($000s) |  | $    | 519.5 |      | $ | 1,896.3 |  | $ | 1,012.3
|Present Value1($000s)                 |  | $    | 173.3 |      | $ | 592.8   |  | $ | 280.7  
|Standardized Measure1($000s)          |  | $    | 134.4 |      | $ | 427.7   |  | $ | 228.8  



|1 | The prices used in calculating Estimated Future Net Revenues and the Present Value are determined using prices as of
period end. Estimated Future Net Revenues and the Present Value give no effect to federal or state income taxes attributable to estimated future net revenues. See Note LSupplemental Information on Oil and Natural Gas Operations in
our consolidated financial statements for information about the standardized measure of discounted future net cash flows. We believe that the Estimated Future Net Revenue and Present Value are useful measures in addition to the standardized measure
as it assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The standardized measure is dependent on the unique tax situation of each individual company,
while the pre-tax Present Value is based on prices and discount factors that are consistent from company to company. We also understand that securities analysts use this measure in similar ways.
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The increases in proved reserves, Present Value and Standardized Measure in 2008 are primarily attributable to extensions, discoveries and revisions of
prior estimates resulting from our core area drilling results.

Approximately 65% of our proved reserves are undeveloped. The quantity and
value of our proved undeveloped reserves are dependent upon our ability to fund the associated development costs, which were an estimated $559.8 million in the aggregate as of December 31, 2008, of which approximately $190 million is scheduled
to be expended in 2009. We have examined all sources of available funding, including our expected operating cash flows, availability under our revolving bank credit facility, and potential future debt and equity issuances, and we are reasonably
certain that we will be able to fund the necessary development costs for our proved undeveloped reserves.

Estimated Future Net Revenues
and Present Value are highly sensitive to commodity price changes, and commodity prices have recently been highly volatile. Period end prices are not necessarily the prices we expect to receive for our production, but we are required by the SEC to
use them for disclosure purposes. We estimate that if all other factors (including the estimated quantities of economically recoverable reserves) were held constant, a $1.00 per Bbl change in oil prices and a $0.10 per Mcf change in gas prices from
those used in calculating the Present Value would change such Present Value by approximately $2 million and $15.8 million, respectively, as of December 31, 2008.



7



---

The estimates of proved reserves at December 31, 2007 and 2008 were prepared by MHA Petroleum
Consultants, Inc. The estimates of proved reserves at December 31, 2006 were prepared by MHA Petroleum Consultants, Inc., in association with Sproule Associates, Inc.

No estimates of our proved reserves comparable to those included in this report have been included in reports to any federal agency other than the SEC.

Costs Incurred

The following table shows certain information regarding the costs incurred by us in
our acquisition, exploration, and development activities during the periods indicated.



|                                       |  |                |         |      |   |         |  |   |        
|-------------------------------------- |  | -------------- | ------- | ---- | - | ------- |  | - | -------
|                                       |  | 2006           |         | 2007 |   | 2008   
|                                       |  | (in thousands)
|Development and exploration costs:     |  |                |         |      |   |         |  |   |        
|Development drilling                   |  | $              | 99,778  |      | $ | 168,246 |  | $ | 183,081
|Exploratory drilling                   |  |                |        |      |   |        |  |   | 15,943 
|Tubular and other drilling inventories |  |                |        |      |   |        |  |   | 39,773 
|Asset retirement obligation            |  |                | 337     |      |   | 1,463   |  |   | 2,407  
|                                       |  |                |         |      |   |         |  |   |        
|                                       |  |                | 100,115 |      |   | 169,709 |  |   | 241,204
|Acquisition:                           |  |                |         |      |   |         |  |   |        
|Proved                                 |  |                | 4,542   |      |   | 7,814   |  |   | 23,246 
|Unproved                               |  |                | 598     |      |   | 1,018   |  |   | 26,236 
|                                       |  |                |         |      |   |         |  |   |        
|                                       |  |                | 5,140   |      |   | 8,832   |  |   | 49,482 
|                                       |  |                |         |      |   |         |  |   |        
|Total                                  |  | $              | 105,255 |      | $ | 178,541 |  | $ | 290,686
|                                       |  |                |         |      |   |         |  |   |        

Drilling Results

We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling commenced. We did not acquire any wells or conduct any
exploratory drilling during 2006 and 2007. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of
productive wells drilled and the oil and natural gas reserves generated by those wells.



|                   |  |                         |  |      |  |       |  |      |  |       |  |     
|------------------ |  | ----------------------- |  | ---- |  | ----- |  | ---- |  | ----- |  | ----
|                   |  | Year Ended December 31,
|                   |  | 2006                    |  | 2007 |  | 2008 
|                   |  | Gross                   |  | Net  |  | Gross |  | Net  |  | Gross |  | Net 
|Development wells: |  |                         |  |      |  |       |  |      |  |       |  |     
|Gas                |  | 67.0                    |  | 35.3 |  | 127.0 |  | 76.5 |  | 89.0  |  | 59.2
|Oil                |  |                        |  |     |  |      |  |     |  |      |  |    
|Dry                |  |                        |  |     |  |      |  |     |  |      |  |    
|Exploratory wells: |  |                         |  |      |  |       |  |      |  |       |  |     
|Gas                |  |                        |  |     |  |      |  |     |  | 1.0   |  | 1.0 
|                   |  |                         |  |      |  |       |  |      |  |       |  |     
|Total              |  | 67.0                    |  | 35.3 |  | 127.0 |  | 76.5 |  | 90.0  |  | 60.2
|                   |  |                         |  |      |  |       |  |      |  |       |  |     

As of December 31, 2008, we had three Haynesville/Bossier horizontal wells drilling that are
not included in the table above.



8



---

Acreage

The following table shows our developed and undeveloped oil and natural gas lease and mineral acreage as of December 31, 2008. Excluded is acreage in which our interest is limited to royalty, overriding royalty and other similar
interests.



|           |  |           |  |             |  |        |  |        |  |        |  |       
|---------- |  | --------- |  | ----------- |  | ------ |  | ------ |  | ------ |  | ------
|           |  | Developed |  | Undeveloped |  | Total 
|           |  | Gross     |  | Net         |  | Gross  |  | Net    |  | Gross  |  | Net   
|East Texas |  | 38,852    |  | 22,859      |  | 24,154 |  | 20,323 |  | 63,006 |  | 43,182
|Other      |  | 2,520     |  | 1,827       |  |       |  |       |  | 2,520  |  | 1,827 
|           |  |           |  |             |  |        |  |        |  |        |  |       
|Total      |  | 41,372    |  | 24,686      |  | 24,154 |  | 20,323 |  | 65,526 |  | 45,009
|           |  |           |  |             |  |        |  |        |  |        |  |       

Within the total gross and net East Texas acres is 57,700 gross and 38,600 net acres which we
believe to be prospective Haynesville/Bossier acreage.

Title to oil and natural gas acreage is often complex. Landowners may have
subdivided interests in the mineral estate. Oil and natural gas companies frequently subdivide the leasehold estate to spread drilling risk and often create overriding royalties. When we purchased the properties, the purchase included title opinions
prepared by counsel analyzing mineral ownership in each well drilled. Further, for each producing well there is a division order signed by the current recipients of payments from production stipulating their assent to the fraction of the revenues
they receive. We obtain similar title opinions with respect to each new well drilled. While these practices, which are common in the industry, do not assure that there will be no claims against title to the wells or the associated revenues, we
believe that we are within normal and prudent industry practices. Because many of the properties in our current portfolio were purchased out of bankruptcy in 1998, we have the advantage that any known or unknown liens against the properties were
cleared in the bankruptcy.

Productive Well Summary

The following table shows our ownership in productive wells as of December 31, 2008. Gross oil and natural gas wells include one well with multiple completions. Wells with multiple completions are counted only
once for purposes of the following table.



|            |  |                  |  |      
|----------- |  | ---------------- |  | -----
|            |  | Productive Wells
|            |  | Gross            |  | Net  
|Natural gas |  | 361.0            |  | 216.3
|Oil         |  | 25.0             |  | 19.7 
|            |  |                  |  |      
|Total       |  | 386.0            |  | 236.0
|            |  |                  |  |      

Substantially all of our productive wells are related to our Cotton Valley Sands development.

Facilities

As of December 31,
2008, we leased 15,902 square feet in Oklahoma City, Oklahoma for our corporate headquarters. The annual rental cost is approximately $252,000. We also lease 5,000 square feet of office space in Marshall, Texas used primarily for land field
operations. The annual rent is approximately $24,000.

We own a 50-acre operations field yard approximately seven miles southeast of
Marshall, Texas that has 10,800 square feet of office and warehouse space. We also own 48 acres on which our gas gathering sales point is located. In addition, we own 100 acres for expansion of our field operations near Marshall, Texas. In 2008, we
opened a second field office of approximately 2,000 square feet dedicated to land operations situated on 14 acres approximately two miles from the operations field yard.



9



---

Employees

As of December 31, 2008, we had 149 full-time employees, including 60 employees of Diamond Blue. This compares to 115 full-time employees at December 31, 2007, including 74 employees of Diamond Blue. We also use a number of
independent contractors to assist in land and field operations. We believe our relations with our employees are satisfactory. Our employees are not covered by a collective bargaining agreement.

Marketing

Our ability to market oil and natural gas
often depends on factors beyond our control. The potential effects of governmental regulation and market factors, including alternative domestic and imported energy sources, available pipeline capacity, and general market conditions are not entirely
predictable.

Natural Gas.Natural gas is generally sold pursuant to individually negotiated gas purchase contracts, which vary in
length from spot market sales of a single day to term agreements that may extend several years. Customers who purchase natural gas include marketing affiliates of the major pipeline companies, natural gas marketing companies, and a variety of
commercial and public authorities, industrial, and institutional end-users who ultimately consume the gas. Gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot
market may vary daily, reflecting changing market conditions. The deliverability and price of natural gas are subject to both governmental regulation and supply and demand forces.

Substantially all of our gas from our East Texas company-operated wells is initially sold to our wholly owned subsidiary, Endeavor, which in turn sells
gas to unrelated third parties. All of our gas is currently sold under contracts providing for market sensitive terms that are terminable with 30-60 day notice by either party without penalty. This means that we both enjoy the benefits of high
prices in increasing price markets and suffer the impact of low prices when gas prices decline. In addition, PVOG markets 100% of the gas produced from wells operated by PVOG in areas we jointly own. A subsidiary of PVOG charges us a marketing fee
of 1% of the sales proceeds subject to certain price caps for oil and natural gas sold on our behalf in areas we jointly own.

Crude
Oil.Oil produced from our properties is sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30 days notice. The price
paid by these purchasers is an established market or posted price that is offered to all producers.

We do not currently have
any long-term contracts to sell natural gas or crude oil.

In 2008, our largest purchasers of oil and natural gas were various purchases
through PVOG and Crosstex Energy Services, Inc. which accounted for 42% and 22% of total oil and natural gas sales, respectively. We do not believe that the loss of any of our purchasers would have a material adverse affect on our operations as
there are other purchasers active in the market.

Competition

We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and
labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state
and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more



10



---

rapidly 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, most of our competitors have operated for a much longer time than we have and have demonstrated the
ability to operate through industry cycles.

Recent increased oil and natural gas drilling activity in East Texas has resulted in increased
demand for drilling rigs and other oilfield equipment and services. At various times, we have and may continue to experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and natural
gas drilling. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

Regulation

Exploration and Production.The exploration, production and sale of oil and
natural gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface
areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements. These include the regulation of the size and shape of drilling and spacing units or proration
units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. All of these regulations may adversely affect the rate at which wells produce oil and natural gas and the number of wells we may drill. All statements in this report about the number of locations or wells reflect current
laws and regulations.

Laws and regulations relating to our business frequently change, and future laws and regulations, including changes
to existing laws and regulations, could adversely affect our business.

Environmental Matters.The discharge of oil, gas or other
pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in
many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of
oil and natural gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event
of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and natural gas exploration,
development and production, although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to
substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the superfund law, imposes liability, regardless of fault or the legality of the original conduct, on some classes of
persons that are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose
or arrange for disposal of the hazardous substances found at the time. Persons who



11



---

are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable 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. We could be subject to the liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to
classification as hazardous substances under CERCLA.

The Resource Conservation and Recovery Act of 1976, as amended (RCRA), is
the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a generator or
transporter of hazardous waste or an owner or operator of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration
and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRAs requirements because our
operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as
hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage
and dispose of and would cause us to incur increased operating expenses.

There are numerous state laws and regulations in the states in
which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and natural gas activities, the conduct
of salt water disposal operations, and the methods of plugging and abandonment of oil and natural gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and natural gas industry. We
believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material
increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks
generally are not fully insurable.

In addition, because we have acquired and may acquire interests in properties that have been operated
in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our
assessment of the acquired properties.

Marketing and Transportation. Our sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the
Federal Energy Regulatory Commission (FERC) that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules affecting segments of the natural gas
industry, most notably interstate natural gas transmission companies, that remain subject to FERCs jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.



12



---

The ultimate impact of the complex rules and regulations issued by FERC since 1985 cannot be predicted.
We cannot predict what further action FERC will take on these matters. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.

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

Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to
transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently
than other crude oil producers.

Certain Technical Terms

The terms whose meanings are explained in this section are used throughout this document:

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

Bcf.Billion
cubic feet.

Bcfe.Billion cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six
Mcf of natural gas.

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

BBtu.Billion Btus.

Developed Acreage.The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Location.A location on which a development well can be drilled.

Development Well.A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive
in an attempt to recover proved undeveloped reserves.

Drilling Unit.An area specified by governmental regulations or orders or by
voluntary agreement for the drilling of a well to a specified formation or formations which may combine several smaller tracts or subdivides a large tract, and within which there is usually some right to share in production or expense by agreement
or by operation of law.

Dry Hole.A well found to be incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.

Estimated Future Net Revenues.Estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production, future development costs, and future abandonment 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.



13



---

Exploratory Well.A well drilled to find and produce oil or gas in an unproved area, 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. The total costs incurred for exploration and development activities (excluding exploratory drilling in progress and drilling inventories), divided by total proved reserve additions. To the extent any portion of the proved
reserve additions consist of proved undeveloped reserves, additional costs would have to be incurred in order for such proved undeveloped reserves to be produced. This measure may differ from the measure used by other oil and natural gas companies.

Gross Acre.An acre in which a working interest is owned.

Gross Well.A well in which a working interest is owned.

Infill Drilling.Drilling for the development and production of proved undeveloped reserves that lie within an area bounded by producing wells.

Injection Well.A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in
maintaining reservoir pressure and enhancing recoveries from the field or productive horizons.

Lease Operating Expense.All direct
costs associated with and necessary to operate a producing property.

MBbls.Thousand barrels.

MBtu.Thousand Btus.

Mcf.Thousand cubic feet.

Mcfpd. Thousand cubic feet per day.

Mcfe.Thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

MMBbls.Million barrels.

MMBtu.Million Btus.

MMcf.Million cubic feet.

MMcfe.Million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

Natural Gas Liquids.Liquid hydrocarbons which have been extracted from natural gas (e.g., ethane, propane, butane and natural
gasoline).

Net Acres or Net Wells.The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX.New York Mercantile Exchange.

Operator.The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease, usually pursuant to the terms of a joint operating agreement among the various parties owning
the working interest in the well.



14



---

Present Value.When used with respect to oil and natural gas reserves, present value means the
Estimated Future Net Revenues discounted using an annual discount rate of 10%.

Productive Well.A well that is producing oil or gas
or that is capable of production.

Proved Developed Reserves.Proved reserves are expected to be recovered through existing wells
with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary
recovery are included as proved developed reserves only after testing by pilot project or after the operation of an installed program as confirmed through production response that increased recovery will be achieved.

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; i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the
immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved
classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled
units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances can estimates for proved undeveloped reserves be attributable to any acreage
for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion.The completion for production of an existing wellbore in another formation from that in which the well has previously been
completed.

Royalty.An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion
of the production from the leased acreage (or of the proceeds of the sale), but generally does not require the owners to pay any portion of the costs of drilling or operating wells on the leased acreage. Royalties may be either landowners
royalties, which are reserved by the owner of a leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with the transfer to a subsequent owner.

Secondary Recovery.An artificial method or process used to restore or increase production from a reservoir after the primary production by the
natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and water flooding are examples of this technique.

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 oil and natural gas regardless of whether such
acreage contains proved reserves.



15



---

Waterflood. A secondary recovery operation in which water is injected into the producing formation
in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working Interest.An interest in an oil
and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

Workover.To carry out remedial operations on a productive well with the intention of restoring or increasing production.

Availability of Information

We file periodic reports
and proxy statements with the Securities and Exchange Commission (SEC). The public may read and copy any materials we file with the SEC at the SECs Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may
obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an Internet site that contains reports, proxy and information statements,
and other information regarding issuers that file electronically with the SEC. The address of this site is http://www.sec.gov.

Our
internet address is www.gmxresources.com. We make available on our website free of charge copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) of the Exchange Act as soon as reasonably possible after we electronically file or furnish such material with the SEC.



16



---

|Item 7. | Managements Discussion and Analysis of Financial Condition and Results of Operation.
|------- | -------------------------------------------------------------------------------------

Summary Operating and Reserve Data

The following table presents an unaudited summary of certain
operating and oil and natural gas reserve data for the periods indicated.



|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|----------------------------------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | ---- | ----- |  | ---- | ------- | - |  | - | ------- | -
|                                                                        |  | Year Ended December 31, |      
|                                                                        |  | 2004                    |       | 2005 |   | 2006  |  | 2007 |       |  | 2008 |        
|Production:                                                             |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Oil (MBbls)                                                             |  |                         | 30    |      |   | 48    |  |      | 69    |  |      | 127     |   |  |   | 190     |  
|Natural gas (MMcf)                                                      |  |                         | 1,049 |      |   | 1,930 |  |      | 3,915 |  |      | 7,974   |   |  |   | 11,777  |  
|Gas equivalent (MMcfe)                                                  |  |                         | 1,231 |      |   | 2,220 |  |      | 4,327 |  |      | 8,735   |   |  |   | 12,918  |  
|Average daily (MMcfe)                                                   |  |                         | 3.37  |      |   | 6.08  |  |      | 11.9  |  |      | 23.9    |   |  |   | 35.3    |  
|                                                                        |  |                         |       |      |  
|Average Sales Price:                                                    |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Oil (per Bbl)                                                           |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Wellhead price                                                          |  | $                       | 40.83 |      | $ | 53.35 |  | $    | 63.22 |  | $    | 71.08   |   |  | $ | 99.16   |  
|Effect of hedges                                                        |  |                         |      |      |   |      |  |      |      |  |      | (1.97   | ) |  |   | (10.19  | )
|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Total                                                                   |  | $                       | 40.83 |      | $ | 53.35 |  | $    | 63.22 |  | $    | 69.11   |   |  | $ | 88.97   |  
|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Natural gas (per Mcf)                                                   |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Wellhead price                                                          |  | $                       | 6.15  |      | $ | 8.52  |  | $    | 6.79  |  | $    | 7.00    |   |  | $ | 9.50    |  
|Effect of hedges                                                        |  |                         |      |      |   |      |  |      | 0.24  |  |      | 0.41    |   |  |   | (0.26   | )
|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Total                                                                   |  | $                       | 6.15  |      | $ | 8.52  |  | $    | 7.03  |  | $    | 7.41    |   |  | $ | 9.24    |  
|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Average sales price (per Mcfe)                                          |  | $                       | 6.25  |      | $ | 8.57  |  | $    | 7.37  |  | $    | 7.77    |   |  | $ | 9.73    |  
|                                                                        |  |                         |       |      |  
|Operating and Overhead Costs (per Mcfe):                                |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Lease operating expenses                                                |  | $                       | 1.03  |      | $ | .93   |  | $    | 1.04  |  | $    | 1.03    |   |  | $ | 1.17    |  
|Production and severance taxes                                          |  |                         | .42   |      |   | .56   |  |      | .11   |  |      | .31     |   |  |   | .41     |  
|General and administrative                                              |  |                         | 1.61  |      |   | 1.53  |  |      | 1.35  |  |      | 1.00    |   |  |   | 1.31    |  
|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Total                                                                   |  | $                       | 3.06  |      | $ | 3.02  |  | $    | 2.50  |  | $    | 2.34    |   |  | $ | 2.89    |  
|                                                                        |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Cash Operating Margin (per Mcfe)                                        |  | $                       | 3.19  |      | $ | 5.55  |  | $    | 4.87  |  | $    | 5.43    |   |  | $ | 6.84    |  
|                                                                        |  |                         |       |      |  
|Other (per Mcfe):                                                       |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Depreciation, depletion and amortizationoil and natural gas production |  | $                       | 1.28  |      | $ | 1.58  |  | $    | 1.59  |  | $    | 1.88    |   |  | $ | 2.08    |  
|                                                                        |  |                         |       |      |  
|Estimated Net Proved Reserves (as of period-end):                       |  |                         |       |      |   |       |  |      |       |  |      |         |   |  |   |         |  
|Natural gas (Bcf)                                                       |  |                         | 56.9  |      |   | 150.0 |  |      | 236.9 |  |      | 406.3   |   |  |   | 435.3   |  
|Oil (MMbls)                                                             |  |                         | 1.2   |      |   | 2.0   |  |      | 2.7   |  |      | 4.7     |   |  |   | 5.0     |  
|Total (Bcfe)                                                            |  |                         | 64.3  |      |   | 161.7 |  |      | 253.0 |  |      | 434.5   |   |  |   | 465.3   |  
|Estimated Future Net Revenues ($MM)(1)(2)                               |  | $                       | 211.3 |      | $ | 692.9 |  | $    | 519.5 |  | $    | 1,896.3 |   |  | $ | 1,012.3 |  
|Present Value ($MM)(1)(2)                                               |  | $                       | 82.0  |      | $ | 245.0 |  | $    | 173.3 |  | $    | 592.8   |   |  | $ | 280.7   |  
|Standardized measure of discounted future net cash flows ($MM)(3)       |  | $                       | 63.3  |      | $ | 185.5 |  | $    | 134.4 |  | $    | 427.7   |   |  | $ | 228.8   |  



|(1) | See Item 1 BusinessCertain Technical Terms.
|--- | ----------------------------------------------

|(2) | The prices used in calculating Estimated Future Net Revenues and the Present Value are determined using prices as of
period end. Estimated Future Net Revenues and the Present Value give no effect to federal or state income taxes attributable to estimated future net revenues. See Item 1 BusinessReserves.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | The standardized measure of discounted future net cash flows give effect to federal and state income taxes attributable
to estimated future net revenues. See Note LSupplemental Information on Oil and Natural Gas Operations.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



31



---

Overview

We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas from the Haynesville/Bossier Shale and Cotton Valley Sands in our core area, the Sabine Uplift of the Carthage, North
Field of Harrison and Panola counties of East Texas. We consider and report all of our operations as one segment because our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined in Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 131, Disclosures about Segments of an Enterprise and Related Information.

Our strategy is to grow shareholder value through Haynesville/Bossier Shale horizontal well development as well as Cotton Valley Sand vertical wells, to
continue acreage acquisitions, to focus on operational growth in and around our core area, and to convert our natural gas reserves to proved reserves, while maintaining balanced prudent financial management. To date, we have experienced a 100%
success rate and have maintained low finding and development costs while primarily drilling Cotton Valley Sand vertical wells. Late in the second quarter of 2008, we switched our strategy from developing the Cotton Valley Sands with vertical wells
to the development of the Haynesville/Bossier Shale with horizontal wells due to the strong economic profile estimated to be associated with this play.

Results of OperationsYear ended December 31, 2008 Compared to Year ended December 31, 2007

Oil and
Natural Gas Sales.Oil and natural gas sales in the year ended December 31, 2008 increased 85% to $125.7 million compared to the year ended December 31, 2007. Of the increase, 48% is due to higher natural gas and oil production and 25%
to an increase in natural gas and oil prices. The average prices per barrel of oil and mcf of natural gas received in the year ended December 31, 2008 were $88.97 and $9.24, respectively, compared to $69.11 and $7.41, respectively, in the year
ended December 31, 2007. Production of oil increased to 190 MBbls compared to 127 MBbls for 2007. Natural gas production increased to 11,777 MMcf for 2008 compared to 7,974 MMcf for the year ended December 31, 2007, an increase of 48%.

In the year ended December 31, 2008, as a result of hedging activities, we recognized a decrease in oil and natural gas sales of $5
million, compared to an increase in oil and natural gas sales of $3 million in the year ended December 31, 2007. In the year ended December 31, 2008, hedging reduced the average natural gas and oil sales price by $0.26 per Mcf and $10.19
per Bbl compared to an increase in natural gas sales price of $0.41 per Mcf and a decrease in oil sales price by $1.97 per Bbl in the year ended December 31, 2007.

Lease Operations. Lease operations expense increased $6.1 million in the year ended December 31, 2008 to $15.1 million , a 68% increase compared to the year ended December 31, 2007. Increased expense
resulted from a greater number of producing wells in addition to maintenance expenses for the Companys growing field operations. Lease operations expense on an equivalent unit of production basis was $1.17 per Mcfe in the year ended
December 31, 2008 compared to $1.03 per Mcfe for the year ended December 31, 2007.

Production and Severance Taxes.Production and severance taxes increased 93% to $5.3 million in the year ended December 31, 2008 compared to $2.7 million in the year ended December 31, 2007. Production and severance taxes are assessed on the value of the oil and
natural gas produced. The above increase resulted from higher oil and natural gas sales described above offset by severance tax refunds of approximately $1.2 million recorded in 2008. A growing number of wells with natural gas production are exempt
from severance taxes or have reduced severance tax rates. We recognized severance tax refunds of approximately $518,000 in 2007. Upon approval from the State of Texas, certain wells are exempt from severance taxes or eligible for a reduced severance
tax rate for a period of ten years.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense
increased $13 million to $31.7 million in the year ended December 31, 2008, up 70% from the year ended December 31, 2007. This increase is due to higher production levels and higher costs. The oil and gas properties depreciation,



32



---

depletion and amortization rate per equivalent unit of production was $2.08 per Mcfe in the year ended December 31, 2008 compared to $1.88 per Mcfe in
the year ended December 31, 2007. The depletion rate increase was largely the result of lower oil and natural gas prices reducing the economic lives and reserves on our wells which resulted in our oil and natural gas properties being amortized
over a smaller reserve base than if reserves were calculated at higher prices. As a result of lower oil and gas prices, the Company recognized an impairment charge on oil and gas properties of $151.6 million. The Company may be required to
recognize additional impairment charges in future reporting periods if market prices for oil and gas continue to decline.

General and
Administrative Expense.General and administrative expense for the year ended December 31, 2008 was $16.9 million compared to $8.7 million for the year ended December 31, 2007, an increase of 94%. The increase of $8.2 million was
largely the result of hiring additional administrative and supervisory personnel to manage our growth and compensation increases implemented on July 1, 2008 to align our compensation more closely with our peers. Approximately $3.1 million of
the general and administrative expenses was related to non-cash compensation expense compared to $1.6 million in 2007. Additionally, we recorded a $748,000 charge to bad debt expense related to our estimated exposure from a bankruptcy filed by one
of our oil purchasers. General and administrative expense per equivalent unit of production was $1.31 per Mcfe for the year ended December 31, 2008 compared to $1.00 per Mcfe for the comparable period in 2007. Excluding the charge to bad debt
expense, general and administrative expense on a per unit of production would have been $1.11 per Mcfe for the year-ended 2008. Longer term, general and administrative costs should decline on a per unit basis as our production increases from the
Haynesville/Bossier development.

Interest.Interest expense for the year ended December 31, 2008 was $11,681,000 compared to
$4,088,000 for the year ended December 31, 2007. This increase is due to a greater amount of outstanding debt during 2008.

Income
Taxes. Income tax for 2008 was a benefit of $25 million as compared to an expense of $8 million in 2007. The effective tax rates for 2007 and 2008 were 32% and 23%, respectively. The decrease in the effective tax rate in 2008 was due to $11.5
million of deferred tax expense relating to a valuation allowance established for Federal net operating loss carryforwards that reduced our tax benefit. Excluding the deferred tax expense for the valuation allowance, our effective income tax would
have been approximately 34%.

Results of Operations for the Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

Oil and Natural Gas Sales. Oil and natural gas sales in the year ended December 31, 2007 increased 113% to $67.9 million
compared to the year ended December 31, 2006, due to an increase of 102% in production and a 5% increase in the average oil and natural gas price. The average price per barrel of oil and mcf of gas received in 2007 was $69.11 and $7.41,
respectively, compared to $63.22 and $7.03 in the year of 2006. Oil production for 2007 increased 58 MBbls to 127 MBbls compared to 2006. Gas production increased to 7,974 MMcf compared to 3,915 MMcf for the year of 2006, an increase of 104%.
Increased production in 2007 resulted from drilling and completing new wells during the year. As a result of hedging activities, additional oil and natural gas sales of $3.0 million and $940,000 were recognized for 2007 and 2006, respectively. The
hedging activities increased the average Mcfe sales price by $0.35 per Mcfe and $0.22 per Mcfe for the year ended 2007 and 2006, respectively.

Lease Operations. Lease operations expense increased $4.5 million in 2007 to $9.0 million, a 101% increase compared to 2006. Increased expenses resulted from re-works of wells and additional costs to operate new wells. Lease
operations expense on an equivalent unit of production basis was $1.03 per Mcfe in 2007 compared to $1.04 per Mcfe for 2006.

Production
and Severance Taxes. Production and severance taxes increased 490% to $2.7 million in 2007 compared to $465,000 in 2006. Production and severance taxes are assessed on the value of the oil and natural gas produced. The increase in production and
severance taxes in 2007 is due to severance tax refunds of $1.4



33



---

million that were received or accrued during 2006. During 2006, severance tax refunds of $518,000 were received or accrued during the year. Upon approval by
the State of Texas, certain wells are exempt from severance taxes for a period of ten years and this will reduce our expense going forward.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $10.6 million to $18.7 million in 2007, up 132% from 2006. This increase is due primarily to an increase in production for 2007. The
oil and natural gas depreciation, depletion and amortization rate per equivalent unit of production was $1.88 per Mcfe in 2007 compared to $1.59 per Mcfe in 2006. An increase in drilling and completion costs in the field were the primary reason for
increase.

Interest. Interest expense for 2007 was $4.1 million compared to $824,000 for 2006. This increase is primarily
attributable to the increased amount of debt outstanding during 2007.

General and Administrative Expense. General and
administrative expense for 2007 was $8.7 million compared to $5.8 million for 2006, an increase of 50%. This increase of $2.9 million was the result of increases in staff and related expenses necessary to operate at higher levels of drilling and
production. Non-cash stock compensation expense increased $910,000 from $662,000 in 2006 to $1.6 million in 2007. General and administrative expense per equivalent unit of production was $1.00 per Mcfe for 2007 compared to $1.35 per Mcfe for 2006,
reflecting improved efficiency levels.

Income Taxes. Income tax for 2007 was $8.0 million as compared to $3.4 million in 2006. The
effective tax rates for 2006 and 2007 were 28% and 32%, respectively. The increase in the effective tax rate in 2007 is due primarily to the increase in the deferred tax liability associated with the difference between the financial carrying value
of oil and natural gas properties and other property and equipment and the associated tax basis.

Net Income and Net Income per Share

Net Income and Net Income Per ShareYear Ended December 31, 2008 Compared to Year Ended December 31, 2007.For the year ended
December 31, 2008 and 2007, we reported net loss of $81.7 million and net income of $16.9 million, respectively. Excluding the impairment charge of $151.6 million ($100.1 million after income taxes) related to our oil and natural gas properties
and a non-cash charge to deferred income taxes for a valuation allowance on our net operating loss carryforward of $11.5 million, we would have reported net income of $29.9 million for the year ended December 31, 2008, an increase of 77%
compared to the year ended December 31, 2007. Net loss per basic and fully diluted share was $6.07 and $5.66 respectively, year ended 2008 compared to net income per basic and fully diluted share of $0.94 and $0.93 per basic and fully diluted
share for 2007. Excluding the impairment charge related to our oil and natural gas properties and the valuation allowance on our net operating loss carryforward, net income per basic and fully diluted share would have been $1.77 and $1.65. Weighted
average fully-diluted shares outstanding increased by 15% from 13,208,746 shares in 2007 to 15,255,239 shares in 2008.

We recognized
additional dilutive shares of 873,870 for the year ended December 31, 2008, respectively, from the February 2008 issuance of net share settlement 5.00% Convertible Senior Notes due 2013. The dilutive effect of the convertible notes varies based
on our stock price and for purposes of computing dilutive shares outstanding was based on the average stock price for the year ended December 31, 2008 of $42.06. The number of shares issuable increases as our common stock price increases and is
finally determined based on the volume weighted average stock price for a specified 60-day measurement period ending on or about the actual conversion date.

Net Income and Net Income Per ShareYear Ended December 31, 2007 Compared to Year Ended December 31, 2006.For 2007, we reported net income after preferred stock dividends of $12.3 million
compared to $7.2 million for 2006. Net income per basic and fully diluted share was $0.94 and $0.93, respectively, in 2007 compared to $0.65 and $0.64 in 2006, respectively. Weighted average fully-diluted shares outstanding increased by 17% from
11,283,265 in 2006 to 13,208,746 in 2007.



34



---

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our drilling and capital
expenditures. Our cash flows from operating activities are substantially dependent upon oil and natural gas prices, and significant decreases in market prices of oil or natural gas could result in reductions of cash flow and affect our drilling and
capital expenditure plan. To mitigate a portion of our exposure to fluctuations in commodity prices, we have entered into oil and natural gas swaps, collars, and puts.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry conditions and the availability of capital. We believe our cash flow from operating activities and
our availability under our revolving bank credit facility ($110 million at December 31, 2008) are sufficient to fund our 2009 planned oil and gas capital expenditure program of $220 million. In the event natural gas prices remain at their
current depressed levels or our capital expenditures exceed $220 million, we may not be able to increase our borrowing base under our revolving bank credit facility to fund a potential shortfall. While the annual increase in the available borrowing
base we received during 2008 was $100 million, there can be no assurance that we will continue to successfully grow the available borrowing base in 2009 due to a number of potential risk factors that could adversely affect future borrowing base
availability including, among other factors, a continued decline in commodity prices, and/or diminished credit availability from commercial banks.

In that event, we may be required to reduce or defer part of our 2009 capital expenditure program or seek additional capital through the issuance of additional long-term debt or equity. During 2008, we were successful in raising $266
million in additional capital by issuing $125 million of 5.00% Convertible Senior Notes due 2013 and 2,000,000 shares of common stock. However, the recent worldwide financial and credit crisis has adversely affected the ability of many companies to
access the debt and equity markets. To the extent we determine to raise additional funds through the issuance of additional long-term debt or equity, any such decreased ability to obtain financing could adversely affect our capability to continue
with our expected business plan.

Cash FlowYear Ended December 31, 2008 Compared to Year Ended December 31, 2007.In
2008, we had a positive cash flow from operating activities of $87.8 million as a result of increased production volume and higher oil and natural gas prices during 2008. Our cash flow from operating activities in 2007 was $52.4 million. Cash flow
from operating activities before changes in operating assets and liabilities and after preferred stock dividends was $75.6 million compared to $40.8 million in 2007. This resulted from an 85% increase in oil and natural gas sales in 2008. We
received a net $235.9 million in cash from financing activities in 2008 compared to 2007 amounts of $143.5 million. The cash flow from financing activities in 2008 was primarily from the sale of common stock of $134.7 million, issuance of 5.00%
Convertible Senior Notes of $125.0 million and additional debt under our revolving bank credit facility. The cash inflow in 2007 from financing activities primarily resulted from the sale of common stock, private placement of Senior Secured
Subordinated Notes and additional debt under our revolving bank credit facility.

Cash FlowYear Ended December 31, 2007
Compared to Year Ended December 31, 2006.In 2007, we had a positive cash flow from operating activities of $52.4 million as a result of increased production volume during 2007. Our cash flow from operating activities in 2006 was $38.3
million. Cash flow from operating activities before changes in operating assets and liabilities was $45.4 million compared to $21.1 million in 2006. This resulted from a 113% increase in oil and natural gas sales in 2007. We received a net $143.5
million in cash from financing activities in 2007 compared to 2006 amounts of $94.8 million. The cash flow from financing activities in 2007 was primarily from the sale of common stock of $65.7 million, private placement of Senior Secured
Subordinated notes of $30 million and additional debt under our revolving bank credit facility. The cash inflow in 2006 from financing activities primarily resulted from the sale of preferred stock, common stock and additional debt under our
revolving bank credit facility.

Revolving Bank Credit Facility and Other Debt

Revolving Bank Credit Facility.We have a secured revolving bank credit facility, which matures on July 15, 2011 and provides for a line of
credit of up to $250 million (the commitment), subject to a borrowing base



35



---

which is based on a periodic evaluation of oil and gas reserves (borrowing base). The amount of credit available at any one time under the credit
facility is the lesser of the borrowing base or the amount of the commitment.

The loan bears interest at the rate elected by us of either
the prime rate as published in The Wall Street Journal (payable monthly) or the LIBO rate plus a margin ranging from 1.75% to 2.25% based on the amount of the loan outstanding in relation to the borrowing base for a period of one, two or
three months (payable at the end of such period). Principal is payable voluntarily by us or is required to be paid (i) if the loan amount exceeds the borrowing base; (ii) if the Lender elects to require periodic payments as a part of a
borrowing base re-determination; and (iii) at the maturity date of July 15, 2011. We are obligated to pay a facility fee equal to 0.25% per year of the unused portion of the borrowing base payable quarterly.

The regular borrowing base has been adjusted from time to time and was $190 million at December 31, 2008. The loan is secured by a first mortgage on
substantially all of our oil and natural gas properties, a pledge of our ownership of the stock of our subsidiaries, a guaranty from our subsidiaries and a security interest in all of the assets of our subsidiaries. The loan agreement was amended in
February 2008 to permit the sale of our 5.00% Convertible Senior Notes due 2013.

In addition to customary reporting and compliance
requirements, the principal covenants, as amended as of December 31, 2008, under the revolving bank credit facility are:



| |  |  | Maintain a current ratio (as defined in the loan agreement) of not less than 1 to 1;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | Maintain a minimum net worth of $210 million as of June 12, 2008 adjusted quarterly to add 50% of our positive net income for each quarter and 100% of net
proceeds of equity offerings. For purposes of this covenant, the non-cash effects, if any, of hedging agreements pursuant to Financial Accounting Standards Board Rule No. 133 (Accounting for Derivative Instruments and Hedging Activities), and of
ceiling test write-downs pursuant to Regulation S-X 4-10 of the SEC will not be included;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Maintain on a quarterly basis a rolling four quarter ratio of EBITDA to cash interest expense and preferred dividends of not less than 3 to 1;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the borrowing base;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------



| |  |  | Pay all accounts payable within 60 days of the due date other than those being contested in good faith;
| | - |  | -------------------------------------------------------------------------------------------------------



| |  |  | Not incur any other debt other than up to $30 million of our Secured Notes, our Series B Preferred Stock and our $125 million of 5.00% Convertible Senior Notes, due
2013;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Not permit any liens other than those permitted by the loan agreement;
| | - |  | ----------------------------------------------------------------------



| |  |  | Not make any investments, loans or advances other than as permitted by the loan agreement, which includes permitted investment in Diamond Blue Drilling for no more
than three drilling rigs;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Not engage in any mergers or consolidations or sales of all or substantially all of our assets;
| | - |  | -----------------------------------------------------------------------------------------------



| |  |  | Not pay any dividends on common stock or make any other distributions with respect to our stock, including stock repurchases;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | Not permit Ken L. Kenworthy Jr. to cease being our chief executive officer, other than by reason of his death or disability if we name a successor acceptable to the
lenders within four months;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Not permit a person or group (other than existing management) to acquire more than 50% of the outstanding common stock or otherwise suffer a change in control; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Not to make any cash payments in respect of interest or on account of the conversion, purchase, acquisition or termination of our 5.00% Convertible Senior Notes due
2013 unless no event of default under the loan agreement exists or the payment would not result in such a default and the borrowing base has not been exceeded.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



36



---

As of December 31, 2008, we were in compliance with all financial covenants under the revolving bank
credit facility. The minimum net worth financial covenant for which the bank credit facility was amended effective December 31, 2008 to amend the calculation to exclude the non-cash effects of ceiling test write-downs pursuant to regulations S-X
Rule 4-10 of the Securities and Exchange Commission.

In December 2007, we entered into an agreement to grant a temporary increase in the
borrowing base of $30 million (the Bridge Loan) from the existing $90 million to $120 million until the earlier of the completion of additional financing or June 30, 2008. The Bridge Loan bore interest at a rate that was 2.25%
higher per annum than our other borrowings under the normal borrowing base, and the unused facility fee was 0.25% higher than the 0.25% fee for the normal borrowing base. In connection with the amendment, the Company paid an upfront commitment and
arrangement fee of 2.5% of the Bridge Loan, or $750,000. Upon closing of the issuance of our $125 million 5.00% Convertible Senior Notes in February 2008, we repaid the Bridge Loan.

As of December 31, 2008, we had $80.0 million outstanding under the revolving bank credit facility. We will borrow under the revolving bank credit
facility up to the current borrowing base, $190 million, to fund planned capital expenditures and for other general corporate purposes. Our lending bank group consists of Capital One, N.A., BNP Paribas, Union Bank of California, N.A., Compass Bank,
and Fortis Capital Corp.

Senior Subordinated Secured Notes.In July 2007, we entered into a Note Purchase Agreement (Note
Agreement) with The Prudential Insurance Company of America (Prudential) providing for the issuance and sale from time to time of up to $100 million in Senior Subordinated Secured Notes (the Secured Notes) and sold to
Prudential an initial tranche of $30 million of 7.58% Series A fixed rate notes due July 31, 2012 with interest payable quarterly. Proceeds from the sale of the Secured Notes were used for general corporate purposes including additional funding
of drilling and development costs in the Cotton Valley Sands in East Texas. The Secured Notes are secured by a second lien on all of the assets of the Company and its subsidiaries and are guaranteed by the Companys subsidiaries, subject to the
terms of an Intercreditor Agreement between our senior lenders and the collateral agent for the Noteholders, including Prudential. We amended the Note Agreement in February 2008 in connection with the sale of our 5.00% Convertible Senior Notes due
2013. The principal covenants contained in the Note Agreement, in addition to customary covenants for similar transactions are:



| |  |  | The ratio of Adjusted PV10 (as defined in the Note Agreement based on prescribed pricing and other parameters, which prescribes prices for oil production to be the
lesser of the NYMEX strip price or $50.00 and for gas production of a fixed $6.50 per mcf) to Total Debt at the end of each quarter may not be less than 1.5 to 1;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The ratio of Total Debt to EBITDA for the immediately preceding four quarters may not be greater than 4.0 to 1;
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | The ratio of EBITDA to cash interest expense (which is defined to include dividends on outstanding preferred stock) for the immediately preceding four quarters may
not be less than 2.5 to 1;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Tangible net worth may not be less than $165 million plus 50% of net income commencing with the fiscal quarter ending March 31, 2009 and 100% of net cash
proceeds from the sale of equity securities after December 31, 2008. For purposes of this covenant, the non-cash effects, if any, of Swaps, as defined in the Note Agreement, pursuant to Financial Accounting Standards Board Rule No. 133
(Accounting for Derivative Instruments and Hedging Activities) and of ceiling test write-downs (after January 1, 2009) will not be included;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We may not incur senior bank debt in excess of $200 million without the consent of the Noteholders;
| | - |  | ---------------------------------------------------------------------------------------------------



| |  |  | Neither the Company nor any subsidiaries may incur any liens other than under the Companys revolving bank credit facility and the Secured Notes, other than
certain permitted liens;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We may not issue Secured Notes in excess of the Series A Notes without the consent of Prudential and pro forma compliance with the financial covenants. Additional
debt would also require the consent of our lenders under the revolving bank credit facility;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



37



---

| |  |  | We may not incur any other indebtedness without pro forma compliance with the financial covenants, and without subordination terms satisfactory to Prudential, which
additional debt would also require the consent of our lenders under the revolving bank credit facility. In this regard, Prudential agreed that we could issue our 5.00% Convertible Senior Notes due 2013; provided no cash payments in respect of
interest on such notes or on account of the conversion, purchase, acquisition, cancellation or termination of such notes may be made by us unless after giving effect thereto (a) no event of default under the Note Agreement exists, and
(b) no event exists that, with the giving of notice, the passage of time or the satisfaction of other conditions precedent, would be an event of default under the Note Agreement;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We are required to maintain commodity price hedges with a term of not greater than three years and with notional amounts (i) greater than 25% of projected
production for the following twelve months from proved developed producing reserves and (ii) not more than the lesser of (a) 75% of projected production for the following 12 months from all proved reserves or (b) 90% of projected
production for the following twelve months from proved developed reserves; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We may not issue any additional redeemable preferred stock without the consent of Noteholders, which would also require the consent of our lenders under the
revolving bank credit facility.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

As of December 31, 2008, we were in compliance with all financial covenants except for
the tangible net worth covenant for which we received a waiver. Subsequent to December 31, 2008, the tangible net worth covenant has been amended as described above.

In the event of a change in control, defined to be an acquisition of greater than 50% of our outstanding voting stock (other than an acquisition by a public company meeting specified financial requirements) or change
in management (defined as Ken L. Kenworthy, Jr. not being the chief executive officer for any reason, except that upon Mr. Kenworthys death or disability, we have the ability to avoid a change in management if we name a successor chief
executive officer acceptable to Prudential within four months), the Company is required to give notice to the Noteholders and offer to repurchase the Subordinated Notes at the outstanding principal amount plus accrued interest plus, in the case of
any fixed rate notes, including the Series A Notes, a yield maintenance amount.

5.00% Convertible Senior Notes Due 2013.In
February 2008, we completed a $125 million private placement of 5.00% Convertible Senior Notes due 2013 (the Convertible Notes). Net proceeds of approximately $121 million were used to repay our revolving bank credit facility and the
Bridge Loan. The Convertible Notes are governed by an indenture, dated as of February 15, 2008 (the Indenture) between the Company and The Bank of New York Trust Company, N.A., as trustee (the Trustee).

The Convertible Senior Notes bear interest at a rate of 5.00% per year, payable semiannually in arrears on February 1 and August 1 of each
year, beginning August 1, 2008. The Convertible Notes mature on February 1, 2013, unless earlier converted or repurchased by us. Holders may convert their Convertible Notes at their option prior to the close of business on the business day
immediately preceding November 1, 2012 only under the following circumstances:



| |  |  | during any fiscal quarter commencing after March 31, 2008 if the last reported sale price of the common stock for at least 20 trading days during a period of
30 consecutive trading days ending on the last trading day of the preceding fiscal quarter is greater than or equal to 130% of the applicable conversion price on each such trading day;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | during the five business-day period after any five consecutive trading-day period (the measurement period) in which the trading price (as defined below)
per $1,000 principal amount of Convertible Notes for each day of that measurement period was less than 98% of the product of the last reported sale price of our common stock and the applicable conversion rate on each such day;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



38



---

| |  |  | upon the occurrence of a corporate event pursuant to which: (1) we issue rights to all or substantially all of the holders of our common stock entitling them
to purchase, for a period expiring within 60 days after the date of the distribution, shares of our common stock at a price below the average market price at the time, or (2) we distribute to all or substantially all of the holders of our
common stock our assets, debt securities or rights to purchase our securities, if the distribution has a per share value in excess of 10% of the last reported sale price for our common stock at the time; or
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | if: (1) a person or group within the meaning of Section 13(d) of the Exchange Act acquires more than 50% of our outstanding voting
stock, (2) we consummate a recapitalization, reclassification or change of our common stock as a result of which our common stock would be converted into or exchanged for stock, other securities, other property or assets, (3) we consummate
a share exchange, consolidation or merger pursuant to which our common stock will be converted into cash, securities or other property, (4) we consummate any sale, lease or other transfer in one transaction or a series of transactions of all or
substantially all of our and our subsidiaries consolidated assets to any person other than one of our subsidiaries, (5) continuing directors cease to constitute at least a majority of our board of directors, (6) our shareholders
approve any plan or proposal for our liquidation or dissolution, or (7) our common stock ceases to be listed on a United States national or regional securities exchange (any of the events described in clauses (1) through (7), a
fundamental change).
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

On and after November 1, 2012 until the close of business on the business day
immediately preceding the maturity date, holders may convert their Convertible Notes at any time, regardless of the foregoing circumstances.

Upon conversion, we will satisfy our conversion obligation by paying and delivering cash for the lesser of the principal amount or the conversion value, and, if the conversion value is in excess of the principal amount, by paying or
delivering, at our option, cash and/or shares of our common stock for such excess. The conversion value is a daily value calculated on a proportionate basis for each day of a 60 trading-day observation period.

The conversion rate is initially 30.7692 shares of the Companys common stock per $1,000 principal amount of Convertible Notes (equivalent to a
conversion price of approximately $32.50 per share of common stock). The conversion rate is subject to adjustment in some events but will not be adjusted for accrued interest. In addition, following any fundamental change that occurs prior to the
maturity date, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such a fundamental change in certain circumstances. The increase in the conversion rate is determined based on a formula that takes
into consideration our stock price at the time of the fundamental change (ranging from $25.00 to $150.00 per share) and the remaining time to maturity of the Convertible Notes. The increase in the conversion rate ranges from 0% to 30%, increasing as
the stock price at the time of the fundamental change increases from $25.00 and declining as the remaining time to maturity of the Convertible Notes decreases.

We may not redeem the Convertible Notes prior to maturity. However, if we undergo a fundamental change, holders may require us to repurchase the Convertible Notes in whole or in part for cash at a price equal to 100%
of the principal amount of the Notes to be repurchased plus any accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.

The Convertible Notes are senior unsecured obligations of the Company and rank equally in right of payment to all of the Companys other existing
and future senior indebtedness. The Convertible Notes are effectively subordinated to all our secured indebtedness, including indebtedness under our revolving bank credit facility and our senior secured notes, to the extent of the value of our
assets pledged as collateral for such indebtedness. The Convertible Notes are also effectively subordinated to all liabilities of our subsidiaries, including liabilities under any guarantees they have issued.



39



---

Share Lending Agreement

In February 2008, in connection with the offer and sale of the Convertible Notes, we entered into a share lending agreement (the Share Lending Agreement) with an affiliate of Jefferies & Company,
Inc. (the share borrower) and Jefferies & Company, Inc., as collateral agent for the Company. Under this agreement, we will loan to the share borrower up to the maximum number of shares of our common stock underlying our
Convertible Notes during a specified loan availability period. This maximum number of shares is initially 3,846,150 shares. We will receive a loan fee of $0.001 per share for each share of our common stock that we loan to the share borrower, payable
at the time such shares are borrowed. The share borrower may borrow and re-borrow up to the maximum number of shares of our common stock during the loan availability period. We have loaned to the share borrower 3,440,000 shares as of
December 31, 2008.

The share borrowers obligations under the Share Lending Agreement are unconditionally guaranteed by
Jefferies Group, Inc., the ultimate parent company of the share borrower and Jefferies & Company, Inc. (the guarantor). If the guarantor receives a rating downgrade for its long term unsecured and unsubordinated debt below a
specified level by both Standard & Poors Ratings Services and Moodys Investors Service, Inc. (or any substitute rating agency mutually agreed upon by the Company and the share borrower), or by either of such rating agencies in
certain circumstances, the share borrower has agreed to post and maintain with Jefferies & Company, Inc., acting as collateral agent for the Company, collateral in the form of cash, government securities, certificates of deposit, high-grade
commercial paper of U.S. issuers, letters of credit or money market shares with a market value at least equal to 100% of the market value of the shares of our common stock borrowed by the share borrower as security for the share borrowers
obligation to return the borrowed shares to the Company pursuant to the Share Lending Agreement.

The loan availability period under the
Share Lending Agreement commenced on the date of the Share Lending Agreement and will continue until the date that any of the following occurs:



| |  |  | we notify the share borrower in writing of our intention to terminate the Share Lending Agreement at any time after the entire principal amount of the Notes ceases
to be outstanding as a result of conversion, repurchase, at maturity or otherwise;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | we and the share borrower agree to terminate the Share Lending Agreement;
| | - |  | -------------------------------------------------------------------------



| |  |  | we elect to terminate all of the outstanding loans upon a default by the share borrower under the Share Lending Agreement or by the guarantor under its guarantee,
including a breach by the share borrower of any of its obligations or a breach in any material respect of any of the representations or covenants under the Share Lending Agreement or a breach by the guarantor of the guarantee, or the bankruptcy of
the share borrower or the guarantor; or
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the share borrower elects to terminate all outstanding loans upon the bankruptcy of the Company.
| | - |  | ------------------------------------------------------------------------------------------------

Any shares we loan to the share borrower will be issued and outstanding for corporate law purposes, and accordingly, the holders of the borrowed shares
will have all of the rights of a holder of a share of our outstanding common stock, including the right to vote the shares on all matters submitted to a vote of the Companys shareholders and the right to receive any dividends or other
distributions that we may pay or make on our outstanding shares of common stock. However, under the Share Lending Agreement, the share borrower has agreed:



| |  |  | not to vote any shares of the Companys common stock it has borrowed to the extent it owns such borrowed shares; and
| | - |  | --------------------------------------------------------------------------------------------------------------------



| |  |  | to pay to us an amount equal to any cash dividends that we pay on the borrowed shares.
| | - |  | --------------------------------------------------------------------------------------

In view of the contractual undertakings of the share borrower in the Share Lending Agreement, which have the effect of substantially eliminating the
economic dilution that otherwise would result from the issuance of the borrowed shares, we believe that under U.S. generally accepted accounting principles currently in effect, the borrowed shares will not be considered outstanding for the purpose
of computing and reporting our earnings per share.



40



---

2008 Common Stock Offering

In July 2008, we completed a public offering of 2,000,000 shares of our common stock for $70.50 per share. Net proceeds to us were approximately $134 million, which we used to fund drilling and development of our East
Texas properties and for other general corporate purposes.

Working Capital

At December 31, 2008, we had a working capital deficit of $16.8 million. Including availability under our credit facility, our working capital as of
December 31, 2008 would have been $93.2 million.

Commitments and Capital Expenditures

The following table reflects the Companys contractual obligations as of December 31, 2008.



|                             |  |                        |         |                 |   |           |  |           |         |                  |   |         |  |   |      
|---------------------------- |  | ---------------------- | ------- | --------------- | - | --------- |  | --------- | ------- | ---------------- | - | ------- |  | - | -----
|                             |  | Payments Due by Period
|                             |  | Total                  |         | Less than1 year |   | 1-3 years |  | 3-5 years |         | More than5 years
|                             |  | (in thousands)        
|Long-term debt               |  | $                      | 235,000 |                 | $ |          |  | $         | 80,000  |                  | $ | 155,000 |  | $ |     
|Operating leases             |  |                        | 2,947   |                 |   | 828       |  |           | 1,237   |                  |   | 882     |  |   |     
|Drilling contracts           |  |                        | 129,429 |                 |   | 17,024    |  |           | 86,286  |                  |   | 26,119  |  |   |     
|Asset retirement obligations |  |                        | 6,049   |                 |   | 587       |  |           | 108     |                  |   |        |  |   | 5,354
|75% PVOG financing(1)        |  |                        | 1,523   |                 |   | 61        |  |           | 105     |                  |   | 89      |  |   | 1,268
|                             |  |                        |         |                 |   |           |  |           |         |                  |   |         |  |   |      
|Total                        |  | $                      | 374,948 |                 | $ | 18,500    |  | $         | 167,736 |                  | $ | 182,090 |  | $ | 6,622
|                             |  |                        |         |                 |   |           |  |           |         |                  |   |         |  |   |      



|(1) | PVOG financing is payable out of 75% of revenues from the wells financed and repayment is based on estimated production
which may vary from actual.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------

Other than obligations under our revolving bank credit facility, the Secured Notes, the
Convertible Notes and the PVOG financing and operating leases, our commitments relate to capital expenditures for development of oil and natural gas properties. We will not enter into drilling or development commitments until such time as a source
of funding for such commitments is known to be available, either through financing proceeds, internal cash flow, additional funding under our revolving bank credit facility or working capital. During 2008, we entered into three year contracts with
H&P for four rigs to be delivered in 2009 to develop our Haynesville/Bossier Shale acreage. The total three year commitment associated with these rigs is $129.4 million. We also entered into a two year contract with Unit Corporation for a
drilling rig for a total potential commitment of $16.1 million. The contract is cancelable for a $2 million penalty.

2009 Guidance

We estimate first quarter 2009 production to be 2.8 Bcfe.

Critical Accounting Policies

The preparation of the consolidated financial statements requires us to make a number of
estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses
during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of our accounting estimates and judgments which management
believes are most significant in its application of generally accepted accounting principles used in the preparation of the consolidated financial statements.



41



---

Full Cost Calculations

The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities:
the successful efforts method and the full-cost method. We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal
costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological
and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion,
amortization and impairment of oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the aggregated full cost pool basis. Additionally, gain or loss is generally recognized on all sales
of oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as
well as a higher oil and natural gas depreciation, depletion and amortization rate, although this difference could change in periods of lower price environments that result in write-downs of our costs as described below.

The full cost method subjects companies to quarterly calculations of a ceiling, or limitation on the amount of properties that can be
capitalized on the balance sheet. If our capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense. Our discounted present value of estimated future net revenues from our proved oil and natural gas
reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of
future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated
information. There can be no assurance that significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property
write-down. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of the full cost pool amortization.

The estimates of proved undeveloped reserve quantities and values are based on estimated future drilling which assumes that we will have the financing
available to fund the estimated drilling costs. If we do not have such financing available at the time projected, the estimates of proved undeveloped reserve quantities and values will change.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Therefore, the future net revenues
associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on such prices and costs in effect as of the end of each quarter when the ceiling calculation is performed.

Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting
value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than various industry
long-term price forecasts. Therefore, oil and natural gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions in the underlying quantities of
reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.



42



---

Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural
gas reserves. Depreciation, depletion and amortization expense is also based on the amount of estimated reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly
different if our estimate of remaining reserves changes significantly.

Asset Retirement Obligations

Our asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities
associated with our oil and natural gas properties. Statement of Financial Accounting Standard (SFAS) No. 143, Accounting for Asset Retirement Obligations, requires that the discounted fair value of a liability
for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous
estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future
advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original
estimate of undiscounted cash flows. The related capitalized cost, including revisions thereto, is charged as an expense to the consolidated statement of operations.

Income Taxes

As part of the process of preparing the consolidated financial statements, we
are required to estimate the federal and state income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing
treatment of items, such as derivative instruments, depreciation, depletion and amortization, and certain accrued liabilities for tax and accounting purposes. These differences and the net operating loss carryforwards result in deferred tax assets
and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe
that recovery is not more likely than not, we must establish a valuation allowance. Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense
within the tax provisions in the consolidated statement of operations.

Derivative Instruments

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended, requires that all
derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering into a derivative contract, we may designate the derivative as either a fair
value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to market through earnings. We document the relationship between the derivative instrument designated as a hedge and the hedged items,
as well as our objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as cash flow hedges are linked to specific forecasted transactions. We assess at inception, and on an
ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting.

Changes in fair value of a qualifying cash flow hedge are recorded in accumulated other comprehensive income, until earnings are affected
by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the statement of operations, the fair value of the associated cash flow hedge is reclassified from accumulated other comprehensive income into earnings as a
component of oil and gas sales. Ineffective portions of a cash flow hedge are recognized currently as a component of oil and gas sales. The changes in fair value of



43



---

derivative instruments not qualifying or not designated as hedges are reported currently in the consolidated statement of operations as unrealized gains
(losses) on derivatives, a component of non-operating income (expense). If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in accumulated other comprehensive
income is recognized over the period anticipated in the original hedge transaction.

Oil and Gas Revenues

Oil and natural gas revenues are recognized when sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has
transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchasers pipeline or truck. As a result of the numerous requirements necessary to gather
information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues
from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by
others. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which we do not expect
to be significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

During
the course of normal operations, the Company and other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes produced. These volumetric imbalances are monitored over
the lives of the wells production capability. If an imbalance exists at the time the wells reserves are depleted, cash settlements are made among the joint interest owners under a variety of arrangements. The Company follows the sales
method of accounting for gas imbalances. A liability is recorded when the Companys excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken
less than its ownership share of gas production. There are no significant imbalances as of December 31, 2006, 2007 or 2008.

Other

See Note A to Consolidated Financial Statements for information related to other accounting and reporting policies.

Recently Issued Accounting Pronouncements

See Note A
to Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements to enhance our liquidity and capital resources position or for any other purpose.

Price Risk Management

See
Item 7AQuantitative and Qualitative Disclosures About Market Risk.

Forward-Looking Statements

All statements made in this document other than purely historical information are forward looking statements within the meaning of the federal
securities laws. These statements reflect expectations and are based



44



---

on historical operating trends, proved reserve positions and other currently available information. Forward looking statements include statements regarding
future plans and objectives, future exploration and development expenditures and number and location of planned wells and statements regarding the quality of our properties and potential reserve and production levels. These statements may be
preceded or followed by or otherwise include the words believes, expects, anticipates, intends, continues, plans, estimates, projects or similar
expressions or statements that events will, should, could, might or may occur. Except as otherwise specifically indicated, these statements assume that no significant changes will occur in
the operating environment for oil and natural gas properties and that there will be no material acquisitions or divestitures except as otherwise described.

The forward-looking statements in this report are subject to all the risks and uncertainties which are described in this document. We may also make material acquisitions or divestitures or enter into financing
transactions. None of these events can be predicted with certainty and are not taken into consideration in the forward-looking statements.

For all of these reasons, actual results may vary materially from the forward looking statements and we cannot assure you that the assumptions used are necessarily the most likely. We will not necessarily update any forward looking
statements to reflect events or circumstances occurring after the date the statement is made except as may be required by federal securities laws.

There are a number of risks that may affect our future operating results and financial condition. See Item 1A. Risk Factors.



45



---

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



|                    |  |  |  |                    |  |                         |  |                                          
|------------------- |  |  |  | ------------------ |  | ----------------------- |  | -----------------------------------------
|                    |  |  |  | GMX RESOURCES INC.
|                    |  |  | 
|Dated: May 11, 2009 |  |  |  | By:                |  | /s/    JAMES A. MERRILL
|                    |  |  |  |                    |  |                         |  | James A. Merrill, Chief Financial Officer



51



---

EXHIBIT INDEX



|           |  |                                                                                                                                             |  |                           |  |             |  |         |  |             |  |              
|---------- |  | ------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------- |  | ----------- |  | ------- |  | ----------- |  | -------------
|           |  |                                                                                                                                             |  | Incorporated by Reference |  |            
|ExhibitNo. |  | Exhibit Description                                                                                                                         |  | Form                      |  | SEC FileNo. |  | Exhibit |  | Filing Date |  | FiledHerewith
|3.1        |  | Amended and Restated Certificate of Incorporation of GMX Resources Inc.                                                                     |  | SB-2                      |  | 353-49328   |  | 3.1     |  | 11/06/2000  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|3.2        |  | Amended and Restated Bylaws of GMX Resources Inc                                                                                            |  | 8-K                       |  | 001-32977   |  | 3.2     |  | 11/04/2008  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|3.3        |  | Certificate of Designation of Series A Junior Participating Preferred Stock of GMX Resources Inc.                                           |  | 8-K                       |  | 000-32325   |  | 3.1     |  | 05/18/2005  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|3.4        |  | Certificate of Designation of 9.25% Series B Cumulative Preferred Stock                                                                     |  | 8-A12B                    |  | 001-32977   |  | 4.1     |  | 08/08/2006  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|4.1(a)     |  | Rights Agreement dated May 17, 2005 by and between GMX Resources Inc. and UMB Bank, N.A., as Rights Agent                                   |  | 8-K                       |  | 000-32325   |  | 4.1     |  | 05/18/2005  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|4.1(b)     |  | Amendment No. 1 to Rights Agreement dated February 1, 2008                                                                                  |  | 8-A/A                     |  | 001-32977   |  | 2.1     |  | 02/21/2008  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|4.1(c)     |  | Amendment No. 2 to Rights Agreement dated October 30, 2008                                                                                  |  | 8-A/A                     |  | 001-32977   |  | 1       |  | 11/17/2008  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|4.2        |  | Indenture dated February 15, 2008, between GMX Resources Inc. and The Bank of New York Trust Company, N.A., as trustee                      |  | 8-K                       |  | 001-32977   |  | 4.1     |  | 02/15/2008  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.1       |  | Amended and Restated Stock Option Plan                                                                                                      |  | 10-Q                      |  | 001-32977   |  | 10.1    |  | 11/09/2007  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.2       |  | Form of Director Indemnification Agreement                                                                                                  |  | SB-2                      |  | 333-49328   |  | 10.5    |  | 11/06/2000  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.3(a)    |  | Participation Agreement dated December 29, 2003 by and among Penn Virginia Oil & Gas Company, the Company and its wholly owned subsidiaries |  | 8-K                       |  | 000-32325   |  | 10.1    |  | 12/31/2003  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.3(b)    |  | First Amendment dated February 27, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation       |  | 8-K                       |  | 000-32325   |  | 10.1    |  | 09/14/2004  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.3(c)    |  | Second Amendment dated May 9, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation            |  | 8-K                       |  | 000-32325   |  | 10.2    |  | 09/14/2004  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.3(d)    |  | Third Amendment dated April 6, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation           |  | 8-K                       |  | 000-32325   |  | 10.3    |  | 09/14/2004  |  |              
|           |  |                                                                                                                                             |  |                           |  |            
|10.3(e)    |  | Fourth Amendment dated August 11, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation        |  | 8-K                       |  | 000-32325   |  | 10.4    |  | 09/14/2004  |  |              



E-1



---

|           |  |                                                                                                                                                                                           |  |                           |  |             |  |         |  |             |  |              
|---------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------- |  | ----------- |  | ------- |  | ----------- |  | -------------
|           |  |                                                                                                                                                                                           |  | Incorporated by Reference |  |            
|ExhibitNo. |  | Exhibit Description                                                                                                                                                                       |  | Form                      |  | SEC FileNo. |  | Exhibit |  | Filing Date |  | FiledHerewith
|10.3(f)    |  | Fifth Amendment dated effective January 1, 2005 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas L.P., successor to Penn Virginia Oil & Gas Corporation  |  | 10-QSB                    |  | 000-32325   |  | 10.6(e) |  | 05/12/2005  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.3(g)    |  | Sixth Amendment dated effective January 1, 2006, to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas L.P., successor to Penn Virginia Oil & Gas Corporation |  | 8-K                       |  | 000-32325   |  | 10.1    |  | 01/20/2006  |  |              
|10.4(a)    |  | Third Amended and Restated Loan Agreement dated June 12, 2008 among Capital One, National Association and Union Bank of California N.A.                                                   |  | 8-K                       |  | 001-32977   |  | 10.1    |  | 06/18/2008  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.4(b)    |  | First Amendment to Restated Loan Agreement dated October 29, 2008, between GMX Resources Inc., Capital One, National Association and Union Bank of California, N.A.                       |  | 10-Q                      |  | 001-32977   |  | 10.4(b) |  | 11/10/2008  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.4(c)    |  | Second Amendment to Restated Loan Agreement dated November 12, 2008, between GMX Resources Inc., Capital One, National Association, and Union Bank of California, N.A.                    |  | 8-K                       |  | 001-32977   |  | 10.1    |  | 03/02/2009  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.4(d)    |  | Third Amendment to Restated Loan Agreement dated February 27, 2009 between GMX Resources Inc., Capital One, National Association, and Union Bank of California, N.A.                      |  | 8-K                       |  | 001-32979   |  | 10.2    |  | 03/02/2009  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.5(a)    |  | Note Purchase Agreement dated July 31, 2007 between GMX Resources Inc. and The Prudential Insurance Company of America                                                                    |  | 10-Q                      |  | 001-32977   |  | 10.6(a) |  | 08/09/2007  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.5(b)    |  | Amendment No. 1 to Note Purchase Agreement and Limited Consent dated February 11, 2008 between GMX Resources Inc. and The Prudential Insurance Company of America                         |  | 8-K                       |  | 001-32977   |  | 10.6    |  | 02/15/2008  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.5(c)    |  | Amendment No. 2 to Note Purchase Agreement dated June 12, 2008 between GMX Resources Inc. and The Prudential Insurance Company of America                                                 |  | 8-K                       |  | 001-32977   |  | 10.3    |  | 06/18/2008  |  |              
|           |  |                                                                                                                                                                                           |  |                           |  |            
|10.5(d)    |  | Amendment No. 3 and Limited Waiver dated February 27, 2009 between GMX Resources Inc. and The Prudential Insurance Company of America                                                     |  | 8-K                       |  | 001-32977   |  | 10.3    |  | 03/02/2009  |  |              



E-2



---

|           |  |                                                                                                                                                                                                                                |  |                           |  |             |  |         |  |             |  |              
|---------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ------------------------- |  | ----------- |  | ------- |  | ----------- |  | -------------
|           |  |                                                                                                                                                                                                                                |  | Incorporated by Reference |  |            
|ExhibitNo. |  | Exhibit Description                                                                                                                                                                                                            |  | Form                      |  | SEC FileNo. |  | Exhibit |  | Filing Date |  | FiledHerewith
|10.6(a)    |  | Intercreditor Agreement dated July 31, 2007 between the Noteholders, Capital One, National Association, Union Bank of California, N.A. and The Bank of New York Trust Company, N.A., as collateral
agent                       |  | 10-Q                      |  | 001-32977   |  | 10.6(b) |  | 08/09/2007  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.6(b)    |  | Amendment No. 1 to Intercreditor Agreement dated June 12, 2008 between the Noteholders, Capital One, National Association, Union Bank of California, N.A. and the Bank of New York Trust Company,
N.A. as Collateral Agent     |  | 8-K                       |  | 001-32977   |  | 10.2    |  | 06/18/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.6(c)    |  | Amendment No. 2 to Intercreditor Agreement dated October 29, 2008 between the Noteholders, Capital One, National Association, Union Bank of California, N.A. and The Bank of New York Trust
Company, N.A., as collateral agent |  | 10-Q                      |  | 001-32977   |  | 10.5(f) |  | 11/10/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.7       |  | Gas Gathering and Processing Agreement effective January 31, 2008 between PVR East Texas Gas Processing LLC and GMX Resources Inc.                                                                                             |  | 8-K                       |  | 001-32977   |  | 10.1    |  | 02/01/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.8       |  | Purchase Agreement dated February 11, 2008, between GMX Resources Inc. and Jefferies & Company, Inc., as representative of the Initial Purchasers named therein                                                                |  | 8-K                       |  | 001-32977   |  | 10.1    |  | 02/15/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.9       |  | Registration Rights Agreement dated February 15, 2008, between GMX Resources Inc. and Jefferies & Company, Inc. as representative of the Initial purchasers named therein                                                      |  | 8-K                       |  | 001-32977   |  | 10.2    |  | 02/15/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.10      |  | Share Lending Agreement dated February 11, 2008, between GMX Resources Inc., Jefferies Funding LLC and Jefferies & Company, Inc., as collateral agent                                                                          |  | 8-K                       |  | 001-32977   |  | 10.3    |  | 02/15/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.11      |  | Registration Rights Agreement dated February 11, 2008, between GMX Resources Inc. and Jefferies Funding LLC                                                                                                                    |  | 8-K                       |  | 001-32977   |  | 10.4    |  | 02/15/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.12      |  | 2008 Long-Term Incentive Plan (Effective as of May 28, 2008)                                                                                                                                                                   |  | 8-K                       |  | 001-32977   |  | 10.1    |  | 06/16/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|10.13      |  | Underwriting Agreement dated July 17, 2008, between GMX Resources Inc. and Jefferies & Company, Inc., as Representative                                                                                                        |  | 8-K                       |  | 001-32977   |  | 1.1     |  | 07/21/2008  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|14         |  | Code of Business Conduct and Ethics                                                                                                                                                                                            |  | 10-KSB/A                  |  | 000-32325   |  | 14      |  | 04/15/2004  |  |              
|           |  |                                                                                                                                                                                                                                |  |                           |  |            
|21         |  | List of Subsidiaries                                                                                                                                                                                                           |  | 10-KSB                    |  | 000-32325   |  | 21      |  | 03/31/2006  |  |              



E-3



---

|           |  |                                                                       |  |                           |  |             |  |         |  |            |  |              
|---------- |  | --------------------------------------------------------------------- |  | ------------------------- |  | ----------- |  | ------- |  | ---------- |  | -------------
|           |  |                                                                       |  | Incorporated by Reference |  |            
|ExhibitNo. |  | Exhibit Description                                                   |  | Form                      |  | SEC FileNo. |  | Exhibit |  | FilingDate |  | FiledHerewith
|23.1       |  | Consent of Independent Accountants                                    |  |                           |  | 001-32977   |  |         |  |            |  | *            
|           |  |                                                                       |  |                           |  |            
|23.2       |  | Consent of MHA Petroleum Consultants                                  |  |                           |  | 001-32977   |  |         |  |            |  | *            
|           |  |                                                                       |  |                           |  |            
|31.1       |  | Rule 13a-14(a) Certification of Chief Executive Officer               |  |                           |  | 001-32977   |  |         |  |            |  | *            
|           |  |                                                                       |  |                           |  |            
|31.2       |  | Rule 13a-14(a) Certification of Chief Financial Officer               |  |                           |  | 001-32977   |  |         |  |            |  | *            
|           |  |                                                                       |  |                           |  |            
|32.1       |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350 |  |                           |  | 001-32977   |  |         |  |            |  | *            
|           |  |                                                                       |  |                           |  |            
|32.2       |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350 |  |                           |  | 001-32977   |  |         |  |            |  | *            



E-4