Home Page
Home Page
01:55:09 EDT Thu 24 Apr 2014
Enter Symbol
or Name
USA
Canada
GMX RESOURCES INC
Symbol U : GMXR
Recent Sedar Documents

GMX RESOURCES INC. Announces Operational and Financial Results for the Three and Nine Months Ended September 30, 2012

2012-11-07 22:26 ET - News Release

OKLAHOMA CITY, Nov. 7, 2012 (GLOBE NEWSWIRE) -- GMX RESOURCES INC., (NYSE:GMXR) (the "Company" or "GMXR"), reports today on the financial and operating results for the third quarter ended September 30, 2012.

Company Highlights for the Three and Nine Months Ended September 30, 2012:

  • The Company's ninth Bakken well, the Akovenko 24-34-2H, was successfully fracture stimulated and brought to sales with an initial peak flow rate of 3,029 BOEPD.

  • Total net production for the third quarter 2012 was 486,600 barrels of oil equivalent (Boe), which includes 53,305 Bbls of oil and 18,583 Bbls of NGLs. Oil production for the third quarter 2012 represents a 185% increase over third quarter 2011. Total crude oil production for the first nine months of 2012 was 148,416 Bbls a 130% increase over the first nine months of 2011. 

  • October 2012 Bakken net crude oil production (operated and non-operated) was approximately 20,900 Bbls which is an increase of 46% over September 2012 Bakken production. Total Bakken production in October represents 56% of third quarter 2012 production.

  • Bakken net crude oil guidance for the fourth quarter 2012 is expected to be 75,000 Bbls, up 100% over the third quarter of 2012. Estimated 1Q13 Bakken net oil production of 112,100 Bbls is projected to be up approximately 680% over 1Q12.

  • Operated Bakken differentials have continued to decline quarter over quarter declining 20% from 1Q12 to 2Q12 and another 20% from 2Q12 to 3Q12. Bakken differentials for October were as low as $2.50 and have a weighted average of $2.96.

  • The Company has reached total depth with its tenth operated well, the Lange 44-31-2H, which is scheduled for fracture stimulation in December 2012 and is preparing to spud the Heiser 11-2-1H well in McKenzie County.

  • The sale of certain of the Company's East Texas assets was completed for approximately $69 million.

  • The Company has identified 203 locations within its Niobrara leaseholds that we believe contain the necessary attributes for a successful crude oil development program. We have identified the first two test locations and have begun the process of securing permits, evaluating surface locations and other infrastructure needs to prepare for drilling in 2013.

  • The Company reduced the outstanding balance of its 2013 Senior Convertible Notes to $27.1 million and reduced the outstanding balance of its 2015 Senior Convertible Notes to $48.3 million in a successful exchange for new Senior Secured Second-Priority Notes due March 2018. As part of the exchange, the Company successfully reduced outstanding debt by approximately $11.4 million by exchanging the 2015 Senior Convertible Notes at a 70% discount.

  • General and Administrative expenses have been reduced by 21% quarter over quarter from $6.8 million in the second quarter 2012 to $5.4 million in the third quarter 2012 and Company is on track for a year over year reduction of greater than 20%.

Bakken

McKenzie County, North Dakota

The Akovenko 24-34-2H, in which the Company has a 92% working interest, is located in Sections 27 & 34, Township 146N, Range 99W in McKenzie County, North Dakota. The Akovenko 24-34-2H has produced an Initial Peak Flow of 3,029 BOPD. The well reached total depth in less than 30 days with a total depth of 20,997' and a horizontal lateral length of 9,341'. This ninth operated well is the first plug and perf completion in McKenzie County in the Middle Bakken and the first completion in a lateral drilled with oil base mud by the Company. The oil base mud used in this well was designed to preserve the rock's natural permeability and porosity. By comparison, the south offset Akovenko 24-34-1H was drilled with water base mud, completed in thirty stages with sliding sleeves and had an initial peak flow of 1,483 BOEPD.

We have spud our tenth operated well, the Lange 44-31-2H, located in Sections 30 & 31, Township 147N, Range 99W in McKenzie County, North Dakota. The Company has an 89% working interest in the well and will target the Middle Bakken with a proposed total depth of 20,255' and a lateral length of 8,630'. The well will be our second well drilled with oil base mud and completed with a plug and perf completion in McKenzie County. It will be drilled parallel to the Lange 11-30-1H and provide another comparison similar to the Akovenko wells. The Lange 44-31-2H has reached total depth and is planned to be fracture stimulated in December 2012.

The Company is preparing to spud its eleventh operated well, the Heiser 11-2-1H, which is located in Sections 2 & 11, Township 145N Range 99W in McKenzie County. The Company will have a 40-60% working interest (pending consents and trades) in the well and will target the Middle Bakken with a proposed total depth of 21,141' and a lateral length of 9,620'.

The Company has elected to participate in the drilling of the Marsh 41-16PH, 2% working interest, which is located in Sections 16&21, Township 140N Range 97W in Stark County, North Dakota.

Billings County, North Dakota

The Basaraba 34-35-1H, in which the Company has a 89% working interest, is GMXR's eighth operated well located in Sections 26 & 35, Township 144N Range 100W in Billings County, North Dakota. The well is the Company's first Middle Bakken well in Billings County. It was successfully fracture stimulated using a thirty-nine stage plug and perf completion. It was fracture stimulated with 25% more proppant, 4MM# which was 44% white sand and 56% ceramic proppant. The peak flow rate was 1,673 BOEPD, 48/64" choke @ 1,000# Flowing Casing Pressure (FCP). The plug and perf completion was also the first time we used this completion procedure which included cleaning out the lateral. The coiled tubing unit was released on September 30, 2012 after milling out 33 plugs and reaching a depth of 19,000'.  The Basaraba has a thirty-day cumulative production of 16,336 BOE or an average of 544 BOEPD.

The Company's seventh operated well is the Fairfield State 21-16-1H in Sections 16 & 21, Township 143N Range 99W in Billings County, North Dakota. During the sliding sleeve completion of the Three Forks, we screened out after the first four stages. We were only able to complete less than 30% of the remainder of the lateral as a modified plug and perf design. The peak flow rate on the well was 177 BOE. The Middle Bakken in pilot hole looked very good and will be the target of future development.

Production

Total crude oil production for the first nine months of 2012 was 148,416 Bbls, a 130% increase over the first nine months of 2011. Bakken only crude production was 37,558 Bbls or 408 barrels/day (Bbls/d) in the third quarter 2012 and 90,999 Bbls or 332 Bbls/d for the first nine months of 2012. East Texas crude oil production was 15,747 Bbls in the third quarter 2012 and 57,417 Bbls for the first nine months of 2012. 

In the third quarter of 2012, the Company achieved an average oil production of 579 Bbls/d. Crude oil production for the third quarter 2012 was 53,305 Bbls, a decrease of 17% over the second quarter of 2012. The quarter-over-quarter decrease is a result of a delay in new Bakken wells coming on line and ongoing drilling operations within our Bakken leaseholds.

Total production for the third quarter 2012 was 486,579 barrels of oil equivalent (Boe), which includes 53,305 Bbls of oil and 18,583 Bbls of NGLs. Oil production for the third quarter 2012 represents a 185% increase over third quarter 2011. During the third quarter 2012 we continued to see limitations in third party NGL capacity and infrastructure, and elected to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was a premium to the local index and was greater than the combined estimated price of residue gas and the net processing upgrade on the gas that was processed. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the hydrocarbons for the Company.

Natural gas production for the three months ended September 30, 2012 decreased to 2.5 billion cubic feet (Bcf) compared to 5.6 Bcf for the three months ended September 30, 2011, a decrease of 55%. Including the Volumetric Production Payment ("VPP") volumes of 0.9 Bcfe, natural gas production decreased by 2.2 Bcfe, or 39%. The decrease in natural gas production resulted primarily from the natural decline in the Company's Haynesville/Bossier (H/B) wells as a result of the Company's suspension of its H/B horizontal drilling program in mid-2011.

Crude Oil Differentials

Bakken crude oil differentials have fluctuated on a month-to-month basis during the course of 2012, ranging from a high of $25 in March to a current low of approximately $2.50-$2.75. The average Bakken differential to WTI has declined from $16.64 and $13.35 in the first and second quarters, respectively, to $10.75 in the third quarter of 2012. The even lower differential for October is attributable to the increase in rail capacity out of the Bakken as well as the continued build out of the Bakken midstream infrastructure. We currently sell all our Bakken crude oil to Shell Trading and Sunoco based on their favorable pricing and reliable takeaway capacity. 

Sale of East Texas Assets For $69 million

On October 24, 2012, the Company sold to a private third party a portion of its East Texas and Louisiana assets for a purchase price of approximately $69 million with an effective date of September 1, 2012. After adjusting for net revenues and expenses for the month of September and other selling costs, the net proceeds to the Company are $66.7 million. The asset sale includes the Company's interests in specified operated and non-operated properties in the Cotton Valley Sands and shallow rights located in East Texas and Louisiana. 

The Company is retaining its entire Haynesville / Bossier natural gas resource base consisting of approximately 40,000 gross/30,000 net acres with 38 producing wells and 200 Bcf of proved reserves. In addition, the Company is retaining Cotton Valley Sands and shallow rights across approximately 13,130 net acres that include 10 producing wells and 28 undeveloped horizontal locations, with 170 BCFE of potential reserves, within its East Texas core position.

The Company will provide customary transitional services to the buyer to ensure continued successful operations of the assets. Those services will include land, accounting, operations and marketing for a period of no less than three months.

The closing on our East Texas assets did not occur until October 24, 2012, with an effective date of September 1, 2012, and as a result, the sale of the East Texas assets will be recorded in the fourth quarter of 2012. Provided below are the estimated effects of the sale for the fourth quarter of 2012 and full year 2013: 

Estimated Effects of East Texas Asset Sale
     
 4th Quarter 20122013
Total Production 929 MMcfe 3,471 MMcfe
Oil 13.2 MBbls 50 MBbls
Gas 849 MMcf 3,171 MMcf
Revenue (1) $4.3 Million $18.0 Million
LOE / Expenses $1.8 Million $7.3 Million
EBITDA (1) $2.5 Million $10.7 Million
     
(1) 4th Quarter 2012 and 2013 are estimates based on strip prices as of October 19, 2012.

Niobrara DJ Basin Update

The Company has acquired 361 square miles of 3D seismic across our 40,082 acres in the Northern DJ Basin. The 3D seismic signatures indicate abundant fracturing of the Niobrara B bench within the Niobrara Petroleum System. Resistivity mapping reveals that approximately 85% of our leaseholds have a resistivity of greater than 50 ohms and that 100% our leaseholds have a resistivity of greater than 30 ohms. 

In the early 1990's, approximately 85 horizontal wells were drilled in the Silo Field of Wyoming. These wells were primarily open hole, single-stage completions with average lateral lengths of 3,600'. The average well from the field has produced approximately 230 MBoe with a collection of individual wells having produced approximately 500 MBoe with estimated 20-25% still to be recovered.  The Silo Field wells that were drilled perpendicular to the joints and fractures have the highest cumulative production to date. The Company's Niobrara leasehold has a similar geological footprint to the Silo Field and with modern completion schemes and proper azimuth of the lateral, the Company believes there is an opportunity to significantly improve historical ultimate recoveries. 

We have identified 203 locations within our leaseholds that possess all of the necessary characteristics for successful development. Our plan is to drill two wells in 2013. After drilling and logging to the base of the Niobrara Petroleum System, we plan to drill the lateral in the B bench of the system. We expect to pull several hundred feet of core from the vertical portion of the wells and submit those as part of our contribution to the Niobrara Core Lab Consortium.

Completion of Tender Offer for 2013 and 2015 Senior Convertible Notes

On September 19, 2012, the Company completed an exchange offer of Senior Secured Second-Priority Notes Due 2018 ("New Notes") for its 5.00% Convertible Senior Notes Due 2013 ("2013 Notes") and 4.5% Convertible Senior Notes Due 2015 ("2015 Notes"). Pursuant to the terms of the exchange offer for the 2013 Notes, the Company accepted tenders for such notes and issued in exchange an aggregate of approximately $24.9 million principal amount of New Notes and 7,176,384 shares of the Company's common stock. In addition, pursuant to the terms of the exchange offer for the 2015 Notes, the Company accepted tenders for approximately $38.0 million of 2015 Notes and issued in exchange an aggregate of approximately $26.6 million principal amount of New Notes, which reduced the Company's outstanding debt by $11.4 million.

After giving effect to the exchange offers, approximately $27.1 million aggregate principal amount of 2013 Notes and $48.3 million aggregate principal amount of 2015 Notes will remain outstanding, and approximately $51.5 million aggregate principal amount of New Notes will be outstanding.

General and Administrative Expenses

One of our goals and objectives for 2012 was to reduce year-over-year cash G&A, before adjustment for capitalized G&A, by at least 20%. We are currently on target through three quarters of 2012 with an approximate 24% reduction.  In the past twelve months, we have had a reduction in force of approximately 22% through attrition and consolidation of responsibilities. We have implemented reductions in cash compensation including long-term incentive payments and annual incentive bonuses for the executive officers. In addition, we have reduced or eliminated a number of other non-compensation related G&A expenses. 

Financial

  • Net loss applicable to common shareholders was $60.0 million, or $0.82 per basic and fully diluted share, and $206.7 million, or $3.02 per basic and fully diluted share, for the three and nine months ended September 30, 2012, respectively.
     
  • As detailed below, non-GAAP adjusted net loss applicable to common shareholders(1) was $12.2 million, or $0.17 per basic and fully diluted share, and $36.9 million, or $0.54 per basic and fully diluted share, for the three and nine months ended September 30, 2012, respectively.
     
  • Impairment expenses were $45.5 million and $166.2 million for the three and nine months ended September 30, 2012, respectively, compared to $62.6 million and $127.7 million for the three and nine months ended September 30, 2011, respectively.
     
  • Lease operating expenses were $3.3 million and $9.3 million for the three and nine months ended September 30, 2012, respectively, compared to $3.2 million and $9.0 million for the three and nine months ended September 30, 2011, respectively.
     
  • General and administrative expenses were $5.4 million and $19.2 million for the three and nine months ended September 30, 2012, respectively, compared to $7.6 million and $22.3 million for the three and nine months ended September 30, 2011, respectively.
     
  • Adjusted EBITDA(1) was $5.0 million and $18.1 million for the three and nine months ended September 30, 2012, respectively, compared to $19.8 million and $60.2 million for the three and nine months ended September 30, 2011, respectively.
     
  • Discretionary cash flow (1) was $(8.5) million and $(22.4) million for the three and nine months ended September 30, 2012, respectfully, compared to $11.7 million and $37.2 million and for the three and nine months ended September 30, 2011, respectively.
     
  • The 2012 capital expenditure plan is estimated to be approximately $110 million (including capitalized interest expense and G&A), which will fund our Bakken oil focused drilling and development plans. As of September 30, 2012, we have made $74.3 million of these planned capital expenditures.
     
  • The Company announced that it will hold a special meeting of the shareholders on November 29, 2012 to seek approval granting to the Board of Directors the discretionary authority to effect a reverse stock split in a range of not less than 1-for-5 shares and not more than 1-for-13 shares of the Company's issued and outstanding common stock. The reverse stock split proposal will not include any change the number of authorized shares of our common stock.

(1)            Adjusted net loss available to common shareholders, adjusted EBITDA and discretionary cash flow are non-GAAP measures that are further described and reconciled below in this press release.

Management Comments

Michael J. Rohleder, President said "The Akovenko 24-34-2H result provides further proof of the value of our Williston Basin leaseholds. The Bakken deal flow that has occurred over the last year as well as what other major operators have described as de-risked has validated our belief that our acreage is in the center of the play and directly in line with the ongoing expansion of the Bakken play. We have implemented a number of changes in the last quarter in our drilling and completion processes that began to manifest positively in the Basaraba, now in the Akovenko 2H, and what we expect in the Lange 2H which is scheduled for completion in December. The third quarter oil production should represent the trough for the Company. We are projected to grow production to 75,000 Bbls in the fourth quarter, and on just a one-rig program we expect to grow Bakken production to 2,000 BOEPD by November 2013. The Company is on target to reduce our G&A by over 20% year over year, and as we continue to grow the net asset value of the Company we will pursue strategies to reduce our leverage or attractively refinance our debt."

Third Quarter 2012 Conference Call Dial in Specifics

The Company has scheduled a conference call for Thursday, November 8, 2012 at 8:00 a.m. CST (9:00 a.m. EST) to discuss third quarter 2012 financial and operating results. To access the call, domestic participants should dial (877) 303-9132 and international participants should dial (408) 337-0136 prior to the conference call start time. Please reference conference code 53670688. A presentation pertaining to this call will be available on the Company's website prior to the start of the call at www.gmxresources.com

Participants are encouraged to access the live audio webcast of the conference call through the following web link or by accessing the webcast through the Company's website.

http://investor.shareholder.com/media/eventdetail.cfm?eventid=120488&CompanyID=GMXR&e=1&mediaKey=B6D3B9EAE6270A1344B4B56B803EF2BA

Financial Results for the Three and Nine Months Ended September 30, 2012

The Company reported a net loss applicable to common shareholders of $60.0 million, ($0.82 per basic and fully diluted share), and $206.7 million, ($3.02 per basic and fully diluted share), for the three and nine months ended September 30, 2012, respectively, compared to a net loss applicable to common shareholders of $68.9 million ($1.21 per basic and fully diluted share) and $138.8 million ($2.69 per basic and fully diluted share) for the three and nine months ended September 30, 2011, respectively.

Adjusted net loss applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $12.2 million and $36.9 million, or $0.17 and $0.54 per basic and fully diluted share, for the three and nine months ended September 30, 2012, respectively. Adjusted net loss is provided as a supplemental financial measure, and we believe it provides additional information regarding our operating financial performance.

Adjusted net loss is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income applicable to common shareholders, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.  

 Three Months EndedNine Months Ended
 September 30, 2012September 30, 2012
 AmountPer Share(1)AmountPer Share(1) 
(in thousands, except for per share amounts)        
GAAP net loss applicable to common shareholders $(59,956) $(0.82) $(206,688) $(3.02)
Adjustments:        
Deferred income tax provision 1,389 0.02 4,694 0.07
Impairment of oil and natural gas properties and assets held for sale 45,506 0.62 166,196 2.43
Unrealized loss on changes in fair value of hedges 1,324 0.02 545 0.01
Non-cash interest expense (2) 1,039 0.01 3,438 0.05
Gain on extinguishment of debt (1,502) (0.02) (5,114) (0.07)
Adjusted net loss applicable to common shareholders $(12,200) $(0.17) $(36,929) $(0.54)
 
(1)  Due to the adjusted net loss applicable to common shareholders for the three and nine months ended September 30, 2012, per share amounts are calculated using the basic weighted average number of shares that excludes items that would be antidilutive. Basic weighted average common shares outstanding for the three and nine months ended September 30, 2012 was 73,453,500 and 68,386,226, respectively.
(2)  Non-cash interest expense is related to additional interest expense recognized for recent accounting pronouncements applicable to our convertible bonds and our share lending agreement.

The following table summarizes certain key operating and financial results for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011.

Summary Operating Data         
         
 Three Months EndedNine Months Ended
 September 30,September 30,
 2012 (1)20112012 (1)2011
Production:        
Oil (MBbls) 53 19 148 65
Natural gas (MMcf) 2,488 5,568 7,539 16,936
Natural gas liquids (MBbls) 19 77 214 230
Gas equivalent production (MMcfe) 2,919 6,142 9,712 18,706
Natural gas VPP volumes (MMcf) 921 3,109
Gas equivalent production including VPP volumes (MMcfe) 3,840 6,142 12,821 18,706
Average daily production excluding VPP volumes (MMcfe) 31.7 66.8 35.4 68.5
Average daily production including VPP volumes (MMcfe) 41.7 66.8 46.8 68.5
Average Sales Price:        
Oil (per Bbl)        
Wellhead price $84.70 $88.03 $87.33 $93.98
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives 6.08  — 3.83 (0.67)
Total $90.78 $88.03 $91.16 $93.31
Natural gas liquids (per Bbl)        
Sales price $36.27 $43.10 $34.55 $39.82
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives  — —  —  — 
Total $36.27 $43.10 $34.55 $39.82
Natural gas (per Mcf)        
Wellhead price $2.23 $3.73 $1.83 $3.76
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives 1.42  0.84 1.80 0.77
Total $3.65 $4.57 $3.63 $4.53
Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe) $5.00 $4.95 $4.97 $4.92
Operating and Overhead Costs (per Mcfe):        
Lease operating expenses including VPP volumes $0.85 $0.52 $0.72 $0.48
Effect of excluding VPP volumes on lease operating expenses 0.27  — 0.23  —
Lease operating expense excluding VPP volumes $1.12 $0.52 $0.95 $0.48
         
Production and severance taxes including VPP volumes $0.13 $0.05 $0.06 $0.05
Effect of excluding VPP volumes on production and severance taxes 0.04  — 0.02  —
Production and severance taxes excluding VPP volumes $0.17 $0.05 $0.08 $0.05
         
General and administrative including VPP volumes $1.40 $1.24 $1.49 $1.19
Effect of excluding VPP volumes on general and administrative 0.44 0.48 — 
General and administrative excluding VPP volumes $1.84 $1.24 $1.97 $1.19
         
Total cost including VPP volumes $2.38 $1.81 $2.27 $1.72
Total cost excluding VPP Volumes $3.13 $1.81 $3.00 $1.72
         
Other (per Mcfe):        
Depreciation, depletion and amortization—oil and natural gas properties (excluding VPP volumes) $1.52 $2.03 $1.63 $1.90
         
(1) For 2012, the amounts presented are net of the VPP volumes, with exception of "Operating and Overhead Costs (per Mcfe)," which are presented gross and net of the VPP volumes.

Results of Operations for the Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended September 30, 2012 decreased 49% to $14.6 million compared to $28.4 million in the third quarter of 2011. The decrease in oil and gas sales was primarily due to a 52% decrease in production on a Bcfe-basis of which 29% of the decrease was attributable to natural gas volumetric production payment ("VPP") volumes of 0.9 Bcfe that were sold in the form of a term overriding royalty interest in December 2011 and the remainder of the decrease was a result of the natural decline from the Company's H/B production due to the suspension of the Company's H/B horizontal drilling program in mid-2011. The average price per barrel of oil, per barrel of natural gas liquids ("NGLs") and price per thousand cubic feet (Mcf) of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended September 30, 2012 was $90.78, $36.27 and $3.65, respectively, compared to $88.03, $43.10 and $4.57, respectively, in the three months ended September 30, 2011. This represented a 3% increase in oil prices, a 16% decrease in the average realized price in NGLs, and a 20% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $1.42 and $0.84, for the three months ended September 30, 2012 and 2011, respectively, was approximately 89% and 89% of the average NYMEX closing contract price for the respective periods. In the third quarter of 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $0.27 per Mcf and $0.29 per Mcf, respectively, for every Mcf of natural gas sold. 

Natural gas production for the three months ended September 30, 2012 decreased to 2.5 Bcf compared to 5.6 Bcf for the three months ended September 30, 2011, a decrease of 55%. Including the VPP volumes of 0.9 Bcf, natural gas production decreased by 2.2 Bcf, or 39%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011. 

Oil production for the three months ended September 30, 2012 increased 185% to 53,305 Bbls, from 18,733 Bbls for the three months ended September 30, 2011, primarily as a result of the Company's new Bakken production. For the third quarter of 2012, the Company produced 37,558 Bbls in the Bakken and 15,747 Bbls in East Texas compared to the third quarter of 2011 when the Company only had East Texas oil production. Bakken and East Texas oil sales, excluding hedges, during the three months ended September 30, 2012 were $3.1 million and $1.5 million, respectively.

NGL production for the three months ended September 30, 2012 decreased to 18,583 Bbls compared to 76,997 Bbls for the three months ended September 30, 2011, a decrease of 76%. Due to the limitations in NGL infrastructure in the third quarter of 2012 and the resulting decrease in available processing capacity, the Company elected to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the combined hydrocarbon stream.

For the three months ended September 30, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in oil and natural gas sales of $3.9 million compared to an increase in oil and natural gas sales of $4.7 million in the third quarter of 2011. In the third quarter of 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.42 per Mcf compared to an increase in natural gas sales price of $0.84 per Mcf in the third quarter of 2011. The increase in the natural gas sales price for the three months ended September 30, 2012, was mainly due to the amortization of $4.0 million in realized non-cash gain on our cash flow hedges that we monetized in the fourth quarter 2011. The remaining realized gain of $5.1 million, net of taxes, in other comprehensive income will be amortized into earnings ratably through 2013. Our derivative contracts that have not been monetized on natural gas decreased our natural gas sales by $0.4 million and increased our natural gas sales by $4.7 million for the three months ended September 30, 2012 and 2011, respectively. Our derivative contracts on oil increased our oil sales by $0.3 million for the three months ended September 30, 2012. The effect of our derivative contracts on oil increased the average oil sales price by $6.08 per Bbl for the three months ended September 30, 2012. The effect of our derivative contracts on oil had no effect for the three months ended September 30, 2011.

Lease Operations. Lease operations expense increased $0.1 million, or 2%, for the three months ended September 30, 2012, to $3.3 million, compared to $3.2 million for the three months ended September 30, 2011. Lease operations expense on a per thousand cubic feet equivalent (Mcfe) basis, excluding VPP volumes increased $0.60, or 115%, to $1.12 for the three months ended September 30, 2012 compared to $0.52 for the three months ended September 30, 2011. The increase in lease operating expenses in total and on a per Mcfe basis is due to higher lease operating expenses related to the Company's Bakken oil production and the impact of the volumetric production payment of $0.27 per Mcfe. For the three months ended September 30, 2012, lease operations expense on a per Mcfe basis for East Texas and the Bakken was $0.94 and $3.20, respectively.

Production and Severance Taxes. Production and severance taxes increased 61% to $0.5 million in the three months ended September 30, 2012 compared to $0.3 million in the three months ended September 30, 2011. The increase in production and severance taxes is primarily due to the increase in the Bakken production, which results in higher production taxes compared to no production in the Bakken for the same period in 2011.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $8.1 million, or 58%, to $5.9 million in the three months ended September 30, 2012 compared to $14.0 million for the three months ended September 30, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.52 per Mcfe in the three months ended September 30, 2012 compared to $2.03 per Mcfe in the three months ended September 30, 2011. This decrease in the rate per Mcfe is primarily due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.

Impairment of oil and natural gas properties and assets held for sale.  The Company recorded an impairment charge of $45.5 million in the third quarter of 2012, which was related to the impairment of oil and gas properties subject to the full cost ceiling test. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges, and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represented approximately 85% of the Company's total production for the three months ended September 30, 2012. During the third quarter of 2012, the 12-month average of the first day of the month natural gas price decreased 10% from $3.15 per MMbtu at June 30, 2012 to $2.82 per MMbtu at September 30, 2012, contributing to the impairment for the third quarter of 2012. Of the $45.5 million impairment of oil and gas properties, $33.5 million was related to the decrease in natural gas and oil prices and $12.0 million was related to continued infrastructure and operational constraints impacting proved producing reserves in the Bakken. The Company anticipates positive Bakken reserve revisions in the future.

General and Administrative Expense. General and administrative expense for the three months ended September 30, 2012 was $5.4 million, compared to $7.6 million for the three months ended September 30, 2011, a decrease of $2.2 million, or 29%, as a result of cost cutting measures implemented by the Company in early 2012. General and administrative expenses include $1.0 million and $0.9 million of non-cash compensation expense as of the three months ended September 30, 2012 and 2011, respectively. Non-cash compensation represented 19% and 12% of total general and administrative expenses, for the three months ended September 30, 2012 and 2011, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.

Interest. Interest expense for the three months ended September 30, 2012 was $10.1 million compared to $7.7 million for the same period in 2011, an increase of $2.4 million or 31%. The increase in interest expense was primarily due to the Company's decision in 2012 to elect the PIK option ("PIK Election") on its Senior Secured Notes due 2017 that allows for a 9% cash interest payment along with a 4% interest payment in the form of additional Senior Secured Notes resulting in an annual interest rate of 13%, as well as the increase in the amount of the outstanding debt between the periods as a result of the exchange offer completed in December 2011. As part of the exchange, certain parties purchased an additional $100 million of the Senior Secured Notes for a total issuance of $283.5 million of the new Senior Secured Notes due 2017. For the three months ended September 30, 2011, only the $2.0 million of 11.375% Senior Notes due 2019 were outstanding. 

For the three months ended September 30, 2012 and 2011, interest expense includes non-cash interest expense of $1.0 million and $1.4 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended September 30, 2012 and 2011 was $8.3 million and $7.8 million, respectively, of which $3.1 million and $2.5 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. Interest associated with the PIK Election was $2.9 million for the three months ended September 30, 2012. The increase in cash and PIK Election interest expense was mainly due to the Company's completion of an exchange offer in December 2011 for all but $2 million of the 11.375% Senior Notes due 2019 which resulted in $288.6 million of new Senior Secured Notes due 2017 and an increase in debt of $90.6 million. The increase in interest expense was partially offset by the reduction in the 5.00% Convertible Notes during 2012.

Income Taxes. Income tax expense for the three months ended September 30, 2012 was $1.4 million as compared to a benefit of $2.4 million in the same period in 2011. The income tax expense/benefit recognized in the three months ended September 30, 2012 and 2011, respectively, was a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes, is recorded to other comprehensive income.

Net income to non-controlling interest. Net income to non-controlling interest was $0.9 million for the three months ended September 30, 2012 compared to $1.2 million for the three months ended September 30, 2011. This decrease was due to lower natural gas production in East Texas.

Net Loss and Net Loss Per Share

Net Loss and Net Loss Per Share—Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011. For the three months ended September 30, 2012, we reported a net loss applicable to common shareholders of $60.0 million, and for the three months ended September 30, 2011 we reported a net loss applicable to common shareholders of $68.9 million. Net loss per basic and fully diluted share was $0.82 for the third quarter of 2012 compared to net loss per basic and fully diluted share of $1.21 for the third quarter of 2011. 

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our production and reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to reinvest in our drilling programs. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas will result in reductions of cash flow which will impact our oil development plans. To mitigate a portion of our exposure to fluctuations in oil and natural gas prices, we have historically entered into swaps, three-way collars and put spreads. We plan to continue to hedge oil and natural gas in the future to mitigate our commodity price risk.

As of September 30, 2012, we had cash and cash equivalents of $17.9 million, including $2.3 million in restricted cash. Through the period ended September 30, 2012, we have funded our operating expenses and capital expenditures through revenues and from capital raised in December of 2011 which included $100 million from a bond exchange of our 11.375% Senior Noted due 2019 for our new Senior Secured Notes due 2017, $49.7 million from the sale of a VPP, and $18.5 million from the December 2011 monetization of the Company's then existing hedge portfolio.

We continually review our drilling plans and may change the amount we spend based on industry and market conditions and the availability of capital. In the first nine months of 2012, our cash outlay for capital expenditures was $74.3 million. We anticipate funding approximately $110.0 million of cash capital expenditures in 2012 with cash on hand and the $66.7 million in net proceeds from the sale of the Company's East Texas Cotton Valley Sands assets. In October 2012, we closed on the sale of our East Texas Cotton Valley Sand assets, the proceeds of which will be used to fund our 2012 and 2013 capital expenditure budget. Our 2012 and 2013 capital expenditure budget will focus on our Middle Bakken development plans particularly in McKenzie and Billings Counties of North Dakota. In the Bakken, we are currently running one drilling rig. In the Niobrara, the Company is planning on drilling two horizontal wells in the Niobrara during 2013. The Company's drilling plan is contingent upon liquidity and operational results.

On September 19, 2012, the Company issued (i) $24,918,000 aggregate principal amount of Senior Secured Second-Priority Notes and 7,136,384 shares of common stock in exchange for $24,918,000 aggregate principal amount of our 5.00% Convertible Notes and (ii) $26,540,000 aggregate principal amount of Senior Secured Second-Priority Notes in exchange for $37,954,000 aggregate principal amount of our 4.50% Convertible Notes.

During the first the first nine months of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes. Pursuant to these agreements, as consideration for the surrender by the holders of $20,753,000 aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our common stock, par value $0.001 per share (the "Common Stock"), along with cash consideration relating to accrued and unpaid interest. These issuances of the Common Stock were effected pursuant to Section 3(a)(9) of the Securities Act of 1933. We continue to evaluate additional options for refinancing and repayment of these notes to address their maturity in February 2013. Options include additional debt for equity exchanges, debt for debt exchanges or other capital market transactions. The Company is unable at this time to determine the likelihood of completing these alternatives prior to the maturity of the 5.00% Convertible Notes.  

GMXR is a resource play rich E&P company. Oil shale resources are located in the Williston Basin, North Dakota & Montana targeting the Bakken Petroleum System and in the DJ Basin, Wyoming targeting the Niobrara Petroleum System; both plays are estimated 90% oil. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier gas shale and the Cotton Valley Sand Formation, where the majority of our acreage is contiguous, with infrastructure in place and substantially all held by production. We believe these oil and natural gas resource plays provide a substantial inventory of operated, high probability, repeatable, organic growth opportunities. The Company's multiple basin strategy provides flexibility to allocate capital to achieve the highest risk adjusted rate of return, with both oil and natural gas resources throughout our portfolio. Please visit www.gmxresources.com for more information on the Company.

The GMX RESOURCES INC. logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=5158

This press release includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. They include statements regarding the Company's financing plans and objectives, drilling plans and objectives, related exploration and development costs, number and location of planned wells, reserve estimates and values, statements regarding the quality of the Company's properties and potential reserve and production levels. These statements are based on certain assumptions and analysis made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes appropriate in the circumstances, including the assumption that there will be no material change in the operating environment for the Company's properties. Such statements are subject to a number of risks, including but not limited to commodity price risks, drilling and production risks, risks relating to the Company's ability to obtain financing for its planned activities, risks related to weather and unforeseen events, governmental regulatory risks and other risks, many of which are beyond the control of the Company. Reference is made to the Company's reports filed with the Securities and Exchange Commission for a more detailed disclosure of the risks. For all these reasons, actual results or developments may differ materially from those projected in the forward-looking statements.

 
 
GMX Resources Inc. and Subsidiaries
Consolidated Balance Sheets
 
 
 September 30, 2012December 31, 2011
 (Unaudited)  
ASSETS(In thousands, except share data)
CURRENT ASSETS:    
Cash and cash equivalents $ 15,535 $ 102,493
Restricted cash 2,325 4,325
Accounts receivable – interest owners 4,813 8,607
Accounts receivable – oil and natural gas revenues, net 4,629 7,082
Derivative instruments 918
Inventories 326 326
Prepaid expenses and deposits 1,058 2,655
Assets held for sale 410 2,045
Total current assets 30,014 127,533
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD    
Properties being amortized 1,136,682 1,062,801
Properties not subject to amortization 158,574 147,224
Less accumulated depreciation, depletion, and impairment (1,053,445) (871,346)
  241,811 338,679
PROPERTY AND EQUIPMENT, AT COST, NET 61,836 65,858
DERIVATIVE INSTRUMENTS 828
OTHER ASSETS 8,659 10,131
TOTAL ASSETS $ 343,148 $ 542,201
LIABILITIES AND EQUITY    
     
CURRENT LIABILITIES:    
Accounts payable $ 10,273 $ 13,550
Accrued expenses 21,514 17,835
Accrued interest 13,872 3,256
Revenue distributions payable 4,245 5,980
Short-term derivative instruments 1,390
Current maturities of long-term debt 26,876 26
Total current liabilities 78,170 40,647
LONG-TERM DEBT, LESS CURRENT MATURITIES 380,528 426,805
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS 402
OTHER LIABILITIES 8,543 7,476
EQUITY:    
Preferred stock, par value $.001 per share, 10,000,000 shares authorized:    
Series A Junior Participating Preferred Stock, 25,000 shares authorized, none issued and outstanding
9.25% Series B Cumulative Preferred Stock, 6,000,000 shares authorized, 3,176,734 shares issued and outstanding as of September 30, 2012 and December 31, 2011 (aggregate liquidation preference $79,418 as of September 30, 2012 and December 31, 2011) 3 3
Common stock, par value $.001 per share – 250,000,000 shares authorized, 82,082,972 shares issued and outstanding as of September 30, 2012 and 63,085,432 shares issued and outstanding as of December 31, 2011 82 63
Additional paid-in capital 716,278 690,986
Accumulated deficit (856,029) (649,341)
Accumulated other comprehensive income, net of taxes 5,142 14,029
Total GMX Resources' equity (134,524) 55,740
Noncontrolling interest 10,029 11,533
Total equity (124,495) 67,273
TOTAL LIABILITIES AND EQUITY $ 343,148 $ 542,201
 
 
GMX Resources Inc. and Subsidiaries 
Consolidated Statements of Operations 
(Unaudited)
 
 
 Three Months EndedNine Months Ended
 September 30,September 30,
 2012201120122011
 (In thousands, except share and per share data)
OIL AND GAS SALES $ 14,591 $ 28,364 $ 48,275 $ 90,629
EXPENSES:        
Lease operations 3,259 3,194 9,255 8,965
Production and severance taxes 499 310 818 859
Depreciation, depletion, and amortization 5,935 13,989 20,374 40,083
Impairment of oil and natural gas properties and assets held for sale 45,506 62,550 166,196 127,731
General and administrative 5,368 7,609 19,165 22,284
Total expenses 60,567 87,652 215,808 199,922
Loss from operations (45,976) (59,288) (167,533) (109,293)
NON-OPERATING INCOME (EXPENSES):        
Interest expense (10,065) (7,680) (30,890) (23,534)
Gain (loss) on conversion/extinguishment of debt 1,502 5,114 (176)
Interest and other income 23 9 131 291
Unrealized gain (loss) on derivatives (1,324) (1,338) (545) 3,654
Total non-operating expense (9,864) (9,009) (26,190) (19,765)
Loss before income taxes (55,840) (68,297) (193,723) (129,058)
INCOME TAX (PROVISION) BENEFIT (1,389) 2,386 (4,694) (481)
NET LOSS (57,229) (65,911) (198,417) (129,539)
Net income attributable to noncontrolling interest 890 1,181 2,761 4,339
NET LOSS APPLICABLE TO GMX RESOURCES (58,119) (67,092) (201,178) (133,878)
Preferred stock dividends 1,837 1,837 5,510 4,884
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS $ (59,956) $ (68,929) $ (206,688) $ (138,762)
LOSS PER SHARE – Basic $ (0.82) $ (1.21) $ (3.02) $ (2.69)
LOSS PER SHARE – Diluted $ (0.82) $ (1.21) $ (3.02) $ (2.69)
WEIGHTED AVERAGE COMMON SHARES – Basic 73,453,500 56,842,336 68,386,226 51,629,035
WEIGHTED AVERAGE COMMON SHARES – Diluted 73,453,500 56,842,336 68,386,226 51,629,035
 
 
 
GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
 
 
 Nine Months Ended
 September 30,
 20122011
CASH FLOWS DUE TO OPERATING ACTIVITIES(In thousands)  
Net loss $ (198,417) $ (129,539)
Depreciation, depletion, and amortization 20,374 40,083
Impairment of oil and natural gas properties and assets held for sale 166,196 127,731
Deferred income taxes 4,578 481
Non-cash compensation expense 3,196 2,907
(Gain) loss on conversion/extinguishment of debt (5,114) 176
Non-cash interest expense 6,129 6,978
Non-cash change in fair value of derivative financial instruments 545 (2,305)
Non-cash derivative gain in oil and gas sales (13,466)
Other (28) (49)
Decrease (increase) in:    
Accounts receivable 6,171 1,131
Inventory and prepaid expenses 1,486 (3,453)
Increase (decrease) in:    
Accounts payable and accrued liabilities 4,766 1,849
Revenue distributions payable (1,845) 2,092
Net cash (used in) provided by operating activities (5,429) 48,082
CASH FLOWS DUE TO INVESTING ACTIVITIES    
Purchase, exploration and development of oil and natural gas properties (75,580) (240,113)
Proceeds from sale of oil and natural gas properties, property, equipment and assets held for sale 1,765 13,560
Purchase of short term investments 23
Purchase of property and equipment (483) (2,061)
Cash settlement of hedges 2,673
Other Investing 2,000
Net cash used in investing activities (72,275) (225,941)
CASH FLOWS DUE TO FINANCING ACTIVITIES    
Borrowings on revolving bank credit facility 61,750
Repayments of long-term debt (33) (173,461)
Proceeds from issuance of long-term debt 193,666
Proceeds from sale of common stock 105,324
Proceeds from sale of preferred stock 25,809
Dividends paid on Series B preferred stock (3,673) (4,884)
Fees paid related to financing activities (1,283) (16,796)
Contributions from non-controlling interest member 408
Distributions to non-controlling interest member (4,265) (13,086)
Net cash (used in) provided by financing activities (9,254) 178,730
NET (DECREASE) INCREASE IN CASH (86,958) 871
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 102,493 2,357
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 15,535 $ 3,228
     
SUPPLEMENTAL CASH FLOW DISCLOSURE    
CASH PAID DURING THE PERIOD FOR:    
INTEREST, Net of amounts capitalized  $ 13,120  $ 14,653
INCOME TAXES, Paid $ 116 $ 1
NON-CASH INVESTING AND FINANCING ACTIVITIES    
Debt extinguished with common stock $ 26,207 $ —
Additions to oil and natural gas properties in exchange for common stock $ — $ 31,612
Decrease in accounts payable for property additions $ 9,053 $ 21,514
Interest paid in the form of additional notes ("PIK Election") $ 5,102 $ —
 
 
 
GMX Resources Inc. and Subsidiaries
Non-GAAP Supplemental Information - Discretionary Cash Flows (1)
 (dollars in thousands)
 
 
 Three Months EndedNine Months Ended
 September 30,September 30,
 2012201120122011
Net loss $ (57,229) $ (65,911) $ (198,417) $ (129,539)
Non-cash charges:        
Depreciation, depletion, and amortization 5,935 13,989 20,374 40,083
Impairment and other write-downs 45,506 62,550 166,196 127,731
Deferred income tax provision 1,273 (2,386) 4,578 481
Non-cash compensation expense 904 753 3,196 2,907
(Gain) loss on extinguishment of debt (1,502) (5,114) 176
Non-cash interest expense 1,966 2,355 6,129 6,978
Unrealized loss (gain) on changes in fair value of hedges 1,324 3,410 545 (2,305)
Non-cash derivative gains in oil and gas sales (3,973)   (13,466)
Other (28) (49)
Net income attributable to noncontrolling interest (890) (1,181) (2,761) (4,339)
Preferred stock dividends (1,837) (1,837) (3,673) (4,884)
Non-GAAP discretionary cash flow $ (8,523) $ 11,742 $ (22,441) $ 37,240
Net cash provided by operating activities $ 2,633 $ 10,508 $ (5,429) $ 48,082
Adjustments:        
Changes in operating assets and liabilities (8,429) 4,252 (10,578) (1,619)
Net income attributable to noncontrolling interest (890) (1,181) (2,761) (4,339)
Preferred stock dividends (1,837) (1,837) (3,673) (4,884)
Non-GAAP discretionary cash flow $ (8,523) $ 11,742 $ (22,441) $ 37,240
 
(1) Discretionary cash flow represents cash provided by operating activities before changes in assets and liabilities less preferred dividends. Discretionary cash flow is presented because we believe it is a useful additional consideration along with net cash provided by operating activities under accounting principles generally accepted in the United States ("GAAP"). Discretionary cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies within the natural gas and oil exploration and production industry. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. The manner in which we calculate discretionary cash flow may differ from that utilized by other companies.
 
 
 
GMX Resources Inc. and Subsidiaries
Non-GAAP Reconciliations - Adjusted EBITDA (1)
 
 
 Three Months EndedNine Months Ended
 September 30,September 30,
Reconciliation of GAAP "Net Income" to Non-GAAP Adjusted EBITDA2012201120122011
(Dollars in Thousands)        
Net loss $ (57,229) $ (65,911) $ (198,417) $ (129,539)
Adjustments:        
Depreciation, depletion, and amortization 5,935 13,989 20,374 40,083
Certain non-cash income and adjustments for unrestricted subsidiaries
 
(840) (724) (2,149) (2,593)
Distributions from unrestricted subsidiaries 398 1,240 1,066 2,644
Impairment and other write-downs 45,506 62,550 166,196 127,731
Deferred income tax provision 1,389 (2,386) 4,694 481
Interest expense 10,065 7,680 30,890 23,534
Change in fair value of hedges 1,324 3,410 545 (2,305)
Loss (gain) on extinguishment of debt (1,502) (5,114) 176
Adjusted EBITDA $ 5,046 $ 19,848 $ 18,085 $ 60,212
 
(1) Adjusted EBITDA represents earnings before interest, taxes, depletion, depreciation & amortization and includes non-cash compensation, hedging and derivative activities and other expenses. Adjusted EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.
CONTACT: Alan Van Horn
         Manager, Investor Relations
         405.254.5839

© 2014 Canjex Publishing Ltd. All rights reserved.