UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

xQuarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
  
 For the quarterly period ended JuneSeptember 30, 2008
  
oTransition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
  
 For the transition period from ______________to ______________.
  
  
Commission File Number 000-52316

REOSTAR ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Nevada
   
20-8428738
(State or other jurisdiction of
incorporation or organization)		   (I.R.S. Employer Identification No.)
  


3880 Hulen Street, Suite 500, Fort Worth, Texas 76107
(Address of principal executive offices)


(817) 989-7367
(Registrant's telephone number, including area code)



                   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 o

                   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 the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o 
Accelerated filer o
 
    
Non-accelerated filer o (Do not check if a smaller reporting company)
Smaller reporting company x
 

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

                   Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

                                    Class                                    
Outstanding at July 31,November 5, 2008
  
Common Stock, par value $0.001 per share80,181,310




TABLE OF CONTENTS

  Page

PART I - FINANCIAL INFORMATION

 ITEM 1-- FINANCIAL STATEMENTS  1
   
 ITEM 2-- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  76
   
 ITEM 3-- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK1413
   
 ITEM 4T-- CONTROLS AND PROCEDURES1413
   
   
PART II - OTHER INFORMATION 
   
 ITEM 1-- LEGAL PROCEEDINGS1514
   
 ITEM 1A-- RISK FACTORS1514
   
 ITEM 2-- UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS1514
   
 ITEM 3-- DEFAULTS UPON SENIOR SECURITIES1514
   
 ITEM 4-- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS1514
   
 ITEM 5-- OTHER INFORMATION1514
   
 ITEM 6-- EXHIBITS1514
   
 SIGNATURES1615






PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

ReoStar Energy Corporation
Consolidated Balance Sheets


June 30, 2008
(unaudited)
March 31, 2008
 
September 30, 2008
(unaudited)
March 31, 2008
 
ASSETS        
Current Assets:            
Cash$346,276 $592,665 $
284,932
 $
592,665
 
Accounts Receivable:  
Oil & Gas - Related Party 1,877,381  868,406  1,212,377  868,406 
Other - Related Party 237,156  -  1,149,370  - 
Other 40,339  - 
Inventory 17,958  4,748  8,731  4,748 
Hedging Account 6,410  13,062  6,316  13,062 
Total Current Assets 2,525,520  1,478,881  2,661,726  1,478,881 
        
Note Receivable 1,341,062  1,355,228  1,348,617  1,355,228 
        
Oil and Gas Properties - successful efforts method 22,321,806  17,832,931  22,713,212  17,832,931 
Less Accumulated Depletion and Depreciation (4,495,689) (4,139,337) (4,827,430) (4,139,337)
Oil & Gas Properties (net) 17,826,117  13,693,594  17,885,782  13,693,594 
        
Other Depreciable Assets: 1,819,174  1,641,806  2,007,742  1,641,806 
Less Accumulated Depreciation (165,738) (121,113) (215,656) (121,113)
Other Depreciable Assets (net) 1,653,436  1,520,693  1,792,086  1,520,693 
        
Other Related Party Receivable 80,395  80,395  80,395  80,395 
Leasehold Held for Sale 1,680,813  1,680,813  1,680,813  1,680,813 
Equity Method Investment 142,395  142,395 
Investment in Equity Method Investment -  142,395 
Total Assets$25,249,738 $19,951,999 $25,449,419 $19,951,999 
            
LIABILITIES            
Current Liabilities:            
Accounts Payable$139,699 $103,479 $312,464 $103,479 
Notes Payable to Related Party 500,000  324,330  500,000  324,330 
Payable to Related Parties 4,300,224  1,547,136  3,717,266  1,547,136 
Royalties Payable 69,879  57,485  86,947  57,485 
Accrued Expenses 1,218,836  857,887  1,250,333  857,887 
Accrued Expenses - Related Party 161,173  171,788  168,762  171,788 
Short Term Notes Payable 525,000  -  525,000  - 
Current Portion of Long-Term Debt 14,960  14,960  16,320  14,960 
Total Current Liabilities 6,929,771  3,077,065  6,577,092  3,077,065 
          
Notes Payable 1,472,999  1,647,769  1,521,940  1,647,769 
Notes Payable - Related Parties 3,769,674  3,194,594  3,769,674  3,194,594 
Other Related Party Payables 240,090  490,840  240,090  490,840 
Less Current Portion of Notes Payable (14,960) (14,960) (16,320) (14,960)
Total Long-Term Debt 5,467,803  5,318,243  5,515,384  5,318,243 
            
Deferred Tax Liability 2,584,761  2,163,183  2,796,083  2,163,183 
Total Liabilities 14,982,335  10,558,491  14,888,559  10,558,491 
            
Commitments & Contingencies:            
Contingent Stock Based Compensation 268,856  214,976  268,856  214,976 
            
Stockholders' Equity            
Common Stock, $.001 par,200,000,000 shares authorized and
80,181,310 shares outstanding on June 30, 2008 and March 31, 2008		 80,181  80,181 
Common Stock, $.001 par,200,000,000 shares authorized and
80,181,310 shares outstanding on September 30,
2008 and March 31, 2008		 80,181  80,181 
Additional Paid-In-Capital 9,590,313  9,553,346  9,590,313  9,553,346 
Retained Deficit 328,053  (454,995) 621,510  (454,995)
Total Stockholders' Equity 9,998,547  9,178,532  10,292,004  9,178,532 
Total Liabilities & Stockholders' Equity$25,249,738 $19,951,999 $25,449,419 $19,951,999 
            

See Accompanying Notes to Consolidated Financial Statements

1


ReoStar Energy Corporation
Consolidated Statements of Operations


 
Three Months Ended
 
Three Months Ended
  
Six Months Ended
 
 
June 30, 2008
(unaudited)
  
June 30, 2007
(unaudited)
 
September 30, 2008
(unaudited)
 
September 30, 2007
(unaudited)
  
September 30, 2008
(unaudited)
 
September 30, 2007
(unaudited)
 
Revenues                 
Oil & Gas Sales$2,752,747 $813,924 $2,282,048 $1,019,222 $5,034,795 $
1,833,146
 
Sale of Leases 18,005  307,028  18,005  307,028 
Other Income 99,416  65  109,568  79,367   208,983  
79,432
 
 2,852,163  813,989  2,409,621  1,405,617   
5,261,783
  
2,219,606
 
           
Costs and Expenses           
Oil & Gas Lease Operating Expenses 596,033  333,521  789,234  491,703 1,385,267  
825,224
 
Workover Expenses 72,425  -  
87,982
  
-
 
160,407
  - 
Severance & Ad Valorem Taxes 154,620  48,936  
132,125
  
59,947
 
286,237
  
108,883
 
Delay Rentals -  43,615  
-
  
8,571
 -  
52,186
 
Depletion & Depreciation 400,976  286,131  
381,660
  
332,245
 
782,636
  
618,376
 
General & Administrative:               
Salaries & Benefits 196,376  233,479  
135,068
  
249,533
 
321,613
  
483,012
 
Legal & Professional 149,334  157,849  
193,129
  
121,953
 
313,639
  
279,802
 
Other General & Administrative 132,326  59,415  
40,295
  
101,751
 
211,784
  
161,166
 
Interest, net of capitalized interest of $161,576 and
$141,012 for the periods ended 6/30/08 and 6/30/07, respectively		 -  - 
 1,702,090  1,162,946 
Interest, net of capitalized interest of
$151,343 and $126,676 for the three
 months ended 9/30/08 and 9/30/07,
 respectively and $312,919 and
 $267,688 for the six months ended
 9/30/08 and 9/30/07, respectively		 
2,900
  
-
   
2,900
  - 
     
1,762,393
  
1,365,703
   
3,464,483
  
2,528,649
 
Interest Income 61,205  23,332  
40
  
70,930
 
61,246
  
94,262
 
Loss on Equity Method Investments 
(142,395
) 
-
 
(142,395
) 
-
 
Hedging Loss (6,653) -  
(93
) 
-
   
(6,746
) 
-
 
               
Income (Loss) from continuing operations before income
taxes and discontinued operations		 1,204,625  (325,625) 
504,780
  
110,844
   
1,709,405
  
(214,781
)
               
Income Tax Provision  
(421,618
) 
113,969
  
(211,323
) 
(38,796
) 
(632,941
) 
75,173
 
Income (Loss) from Continuing Operations 783,007  (211,656)
         
Income from discontinued operations, net of income taxes:           
Pipeline Income -  22,930  -  - -  
22,930
 
Gain on Sale of Pipeline -  1,458,827  -  
(5,169
)  -  
1,453,658
 
Income from discontinued operations -  1,481,757  
-
  
(5,169
)  
-
  
1,476,588
 
Net Income (Loss)$783,007 $1,270,101 $
293,457
 $
66,879
 $
1,076,464
 $
1,336,980
 
                   
      
Basic & Diluted Loss per Common Share      $
0.00
 $
0.00
  $
$0.01
 $
0.02
 
Continuing Operations$0.01  
(0.00
)
Discontinued Operations$- $
0.02
 
$
0.01
 $
0.02
 
      
Weighted Average Common Shares Outstanding  80,181,310  76,524,026  
80,181,310
  
79,711,310
   
80,181,310
  77,907,148 
                   


See Accompanying Notes to Consolidated Financial Statements



ReoStar Energy Corporation
Consolidated Statements of Cash Flows

 
Three Months Ended
 
Six Months Ended
 
 
June 30, 2008
(unaudited)
  
June 30, 2007
(unaudited)
 
September 30, 2008
(unaudited)
 
September 30, 2007
(unaudited)
 
Operating Activities:            
Net Income$783,007 $1,270,101 $1,076,464 $
1,336,980
 
Adjustments to reconcile net income to cash from operating activities:        
Income Tax Expense 421,619  683,900  632,941  
719,913
 
Depletion, Depreciation, & Amortization 400,977  286,131  782,636  
618,376
 
Expired Leases -  - 
�� Loss on Equity Method Investment  
142,395
  
-
 
Stock based compensation 53,880  144,070  
53,880
  
309,451
 
Joint Venture Partner Expense -  3,072,448  -  
3,080,400
 
Gain on Sale of Pipeline -  (5,272,701) -  
(5,272,701
)
Changes in Operating Assets and Liabilities            
Changes in Accrued Liabilities 47,000  37,027  
86,086
  
124,366
 
Change in Inventory (13,210) -  
(3,983
) - 
Change in Related Party Receivables/Payables (237,156) 25,902  
(1,149,370
) 
(392,168
)
Changes in Other Receivables (40,339) 63,389  
-
  
(674,524
)
Changes in Hedging Account 6,652  -  
6,746
  - 
Changes in Royalties Payable 12,394  -  
29,462
  
13,834
 
Change in Revenue Receivables (1,008,975) (9,387) 
(343,971
) 
(142,099
)
Changes in Accounts Payable 36,220  (193,131) 
208,985
  
67,875
 
Net Cash provided from operating activities 462,069  107,749 
Net Cash provided from discontinued operations -  7,164,405 
Net Cash provided by operating activities and
discontinued operations 		 462,069  7,272,154 
Net Cash provided (used) from operating activities 
1,522,271
  
(210,297
)
Net Cash provided (used) from discontinued operations -  
6,802,113
 
Net Cash provided (used) by operating activities and
discontinued operations		 
1,522,271
  
6,591,816
 
        
Investing Activities:        
Oil & Gas Drilling, Completing and Leasehold Acquisition Costs (4,451,908) (960,681) 
(4,843,315
) 
(2,813,409
)
Change in Capitalized Note Accretion -  35,000  -  
70,000
 
Change in Related Party Payable Related to Drilling 2,753,088  (3,826,575)
Change in Related Party Payable related to drilling 
2,170,131
  
(4,120,568
)
Investment in Other Depreciable Assets (177,368) (918,679) 
(365,936
) 
(1,372,717
)
Note Receivable Collections  14,166  81,451 
Note Receivable Collections (Advances) 
6,611
  
148,794
 
Net Cash used in investing activities (1,862,022) (5,589,484) 
(3,032,509
) 
(8,087,900
)
        
Financing Activities        
Notes Payable (Payments) Advances  653,564  (1,950,000) 
702,505
  
(2,029,603
)
Related Party Note Advances 500,000  -  500,000  - 
Net Cash Received from Common Stock Subscriptions -  6,885,353 
Net cash received from common stock subscriptions -  
6,885,353
 
Net Cash provided (used) from financing activities. 1,153,564  4,935,353  
1,202,505
  
4,855,750
 
Net Increase (Decrease) in cash (246,389) 6,618,023  
(307,733
) 
3,359,666
 
Cash - Beginning of the period 592,665  212,254  
592,665
  
212,254
 
Cash - End of the period$346,276 $6,830,277 $
284,932
 $
3,571,920
 
            
See Accompanying Notes to Consolidated Financial Statements



ReoStar Energy Corporation
Consolidated Statements of Cash Flows
(Continued)


 
Three Months Ended
 
Six Months Ended
 
 
June 30, 2008
(unaudited)
  
June 30, 2007
(unaudited)
 
September 30, 2008
(unaudited)
 
September 30, 2007
(unaudited)
 
Supplemental Disclosure of Cash Flow Information            
Cash paid during period for:            
Interest $
87,988
 $
59,993
 $
195,386
 $
64,330
 
            
Income Taxes$- $- $- $- 
            
Non Cash Investing and Financing Activities            
Warrants Issued$36,967 $- $36,967 $- 
            
Transfer of Accrued Interest from Notes      
Payable to Accrued Liabilities$303,334 $- 
Stock Based Property Acquisition$-  298,800.00 
            



See Accompanying Notes to Consolidated Financial Statements



REOSTAR ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principals for interim financial information and pursuant to the rules and regulations of the United States Securities and Exchange Commission. They do not include all information and notes required by generally accepted accounting principals for complete financial statements. However, except as disclosed, there has been no material change in the information disclosed in the notes to financial statements included in the Annual Report on Form 10-KSB of ReoStar Energy Corporation for the year ended March 31, 2008. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three-month and six-month period ended JuneSeptember 30, 2008 are not necessarily indicative of the results that may be expected for the year ending March 31, 2009. The financial statements and notes are representations of the Company's management who are responsible for their integrity and objectivity. The Company's accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of these financial statements.

(2) CAPITAL STOCK
We have authorized capital stock of 200 million shares of common stock. There were 80,831,31080,181,310 shares of common stock issued and outstanding throughout the quarter ended JuneSeptember 30, 2008.

On April 1, 2007, ReoStar entered into employment contracts with certain key employees. In conjunction with the employment contracts, the company approved the issuance of 700,000 shares of restricted stock. Of the 700,000 shares issued, 350,000 shares vested on March 31, 2008, and the balance of the shares will vest on March 31, 2009. For the quarters ended June 30, 2008 and June 30, 2007, Salaries and Benefits included stock related compensation costs of $48,568 and $144,070, respectively. For both periods, a liability of an equal amount was recorded as a contingent stock based compensation liability.

On April 1, 2007, ReoStar also entered into a stock option arrangement with two outside members of its board of directors. Both board members received stock options of 50,000 shares with a strike price of $1.11, one-third of which vest annually on March 31 2008, 2009, and 2010. For the quarters ended June 30, 2008 and 2007 other General & Administrative expenses included stock option costs of $5,312 and $0, respectively.

The estimated compensation expense related to the restricted stock grant and stock option grants for the following two year period is shown in the table below:

Year Ending March 31, 
  2009  2010 
Restricted Stock Compensation$194,783 $- 
Stock Option Compensation 21,264  9,208 
 $216,047 $9,208 

(3) NOTES PAYABLE - RELATED PARTY
On June 11, 2008, the Company entered into a promissory note with a related third party. The note is due June 11, 2009 and bears interest, payable quarterly, of 13%. As additional consideration, the Company granted 100,000 stock warrants with a strike price of $0.50 per share, which was the closing price of the company's stock on June 11, 2008. The warrants expire on June 30, 2012. The Company calculated the cost of the warrant to be $36,967 using the Black-Scholes model with a volatility of 108%. The cost of the warrant was recorded as capitalized interest.




(4) SHORT TERM NOTES PAYABLE
During the quarter, the Company drew $525,000 down on the Frost Bank line of credit. The outstanding balance was $525,000 at June 30, 2008.

(5) SUBSEQUENT EVENTS
On July 25, 2008, the Board of Directors approved the 2008 Long-Term Incentive Plan whereby the Company reserved 8,000,000 shares of stock for issuance under the plan. The Board also approved the grant of 1,500,000 options to certain officers under the plan. The options have a strike price of $0.35 per share, which was the closing price on July 24, 2008, and expire on July 25, 2018. The options vest over a three year period, with the first third vesting on March 31, 2009. The options were valued at $486,483$679,992 using the Black-Scholes model with a volatility of 194%.

On April 1, 2007, ReoStar entered into employment contracts with certain officers. In conjunction with the employment contracts, the company approved the issuance of 700,000 shares of restricted stock. Of the 700,000 shares issued, 350,000 shares vested on March 31, 2008. The unvested portion of the restricted stock grant was cancelled in conjunction with the stock option grant described above. For the quarters ended September 30, 2008 and 2007, Salaries and Benefits included stock related compensation costs of $0 and $145,689, respectively. For the six months ended September 31, 2008 and 2007, Salaries and Benefits included stock related compensation costs of $48,564 and $289,759, respectively. For each period, a liability of an equal amount was recorded as a contingent stock based compensation liability.

On April 1, 2007, ReoStar also entered into a stock option arrangement with two outside members of its board of directors. Both board members received stock options of 50,000 shares with a strike price of $1.11, one-third of which vest annually on March 31 2008, 2009, and 2010. In August 2008, one of the board members notified the company of his intention to renounce his stock options. For the quarters ended September 30, 2008 and 2007 other General & Administrative expenses included stock option costs of $0 and $9,845, respectively. For the six months ended September 30, 2008 and 2007 other General & Administrative expenses included stock option costs of $5,316 and $19,691, respectively.

As a result of the above, the Company has an excess accrual in the contingent stock based compensation liability account. The following table summarizes the expected stock based compensation expense over the next three fiscal years.




 Year Ending March 31, 
  2009  2010  2011 
Restricted Stock Compensation$48,564 $- $- 
Stock Option Compensation 5,316  186,719  82,423 
$53,880 $186,719 $82,423 

(3) NOTES PAYABLE - RELATED PARTY
On June 11, 2008, the Company entered into a promissory note with a related third party. The note was extended on June 21, 2008, is due March 31, 2010, and bears interest, payable quarterly, of 15%. As additional consideration, the Company granted 100,000 stock warrants with a strike price of $0.50 per share, which was the closing price of the company's stock on June 11, 2008. The warrants expire on June 30, 2012. The Company calculated the cost of the warrant to be $36,967 using the Black-Scholes model with a volatility of 108%. The cost of the warrant was recorded as capitalized interest.

(4) SHORT TERM NOTES PAYABLE
During the first quarter, the Company drew $525,000 down on the Frost Bank line of credit. The following table summarizesoutstanding balance was $525,000 at September 30, 2008.

(5) NOTE RECEIVABLE
During the expected compensation expense relatedquarter, the Company agreed to renew the stocknote receivable from our drilling contractor. As part of the renewal, the Company agreed to waive outstanding unpaid interest of $32,785. The drilling contractor agreed to make a principal payment of $750,000 in November, 2008. The balance of the note will be repaid with monthly payments of $50,000 beginning in December, 2008 and will accrue interest at 10% annually.

(6) SUBSEQUENT EVENTS
On October 30, 2008, the Company entered into a $25,000,000 senior secured credit facility. Initially, the borrowing base is set at $14,000,000. The borrowing base is based upon the Company's proven oil and gas reserves and is re-evaluated semi-annually. The note bears interest based upon the greater of 1) the rate announced publicly from time to time by the bank plus a margin that varies between 0.0% and 0.5% depending upon the percentage of borrowing base drawn and 2) the Federal funds rate plus a margin that varies between 0.5% and 1.0% depending upon the percentage of borrowing base drawn. At the Company's option, grant forwe may elect to make a Eurodollar advance. The interest rate on a Eurodollar advance is LIBOR plus a margin that ranges between 2.00% and 2.75% depending upon the next three fiscal years:percentage of borrowing base drawn. The credit facility matures October 30, 2011.

 Year Ending March 31, 
  2009  2010  2011 
Stock Option Compensation$275,885 $151,631 $58,967 
          







ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

CAUTIONARY STATEMENT

You should read the following discussion and analysis in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto contained elsewhere in this report. The information contained in this quarterly report on Form 10-Q is not a complete description of our business or the risks associated with an investment in our common stock. We urge you to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission, or SEC, including our annual report on Form 10-KSB for the year ended March 31, 2008 and subsequent reports on Form 8-K, which discuss our business in greater detail.

In this report we make, and from time to time we otherwise make, written and oral statements regarding our business and prospects, such as projections of future performance, statements of management's plans and objectives, forecasts of market trends, and other matters that are 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. Statements containing the words or phrases "will likely result," "are expected to," "will continue," "is anticipated," "estimates," "projects," "believes," "expects," "anticipates," "intends," "target," "goal," "plans," "objective," "should" or similar expressions identify forward-looking statements, which may appear in documents, reports, filings with the Securities and Exchange Commission, news releases, written or oral presentations made by officers or other representatives made by us to analysts, stockholders, investors, news organizations and others, and discussions with management and other of our




representatives. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Our future results, including results related to forward-looking statements, involve a number of risks and uncertainties. Such risks and uncertainties include, but are not limited to, changes in local, regional, and national economic and political conditions, the effect of governmental regulation, competitive market conditions, our ability to obtain additional financing, and other risks detailed herein and from time to time in our SEC reports. No assurance can be given that the results reflected in any forward-looking statements will be achieved. Any forward-looking statement speaks only as of the date on which such statement is made.


Overview of Our Business

We are engaged in the exploration, development and acquisition of oil and gas properties, primarily located in the state of Texas. We seek to increase oil and gas reserves and production through internally generated drilling projects, coupled with complementary acquisitions.

At April 1, 2008, a certified engineering firm valued our proven reserves at $425,445,500, which reflects the present value of our future net cash flows from reserves before income taxes, discounted at 10 percent.

We own approximately 20,000 gross (16,250 net) acres of leasehold, which includes 16,000 acres of exploratory and developmental prospects as well as 4,000 acres of enhanced oil recovery prospects. We have built a multi-year inventory of drilling projects and drilling locations and currently have enough acreage to sustain several years of drilling.

Our corporate offices are located at 3880 Hulen Street, Suite 500, Fort Worth, Texas 76107. Our telephone number is (817) 989-7367.




Business Strategy

Our objective is to build shareholder value by establishing and consistently growing our production and reserves with a strong emphasis on cost control and risk mitigation. Our strategy is (1) to control operations of all our leases via our affiliated operating companies, (2) to acquire and develop leasehold in key regional resource development plays while utilizing existing infrastructure and engaging in long-term drilling and development programs, and (3) to acquire leasehold in mature fields and implement enhanced oil recovery programs.


Significant Accomplishments in the FirstSecond Quarter

Barnett Shale: We completedbrought all four wells that were in flow-back at the end of the first quarter on line in July.

We began drilling our secondfourth "cluster" of wells in April.July. This cluster was comprised of six newthree wells that are stepped out from the previously drilled clusters. All three wells were fractured using high pressure stimulation over a three-day period. Twothree day period in early October. Flow back began immediately, and we expect to bring all three wells were fractured simultaneously each day. All six wells were brought online in late April and early May.

We completed our third "cluster" of wells in June. This cluster was comprised of three new wells that were fractured using high pressure stimulation over a three-day period. A fourth well not included in the cluster was also completed in June. All four wells were in flow-back at the end of the quarter, and all four were brought online in July, 2008.

During the quarter, we began re-completing four wells into the Forestburg Limestone formation, which is uphole from the Barnett interval. Two of these wells were turned over to production in June and the remaining two were turned over to production in July.

During the quarter, we also re-completed one well into a Caddo formation, which is uphole from the Barnett interval. The well was turned over to production in late June.

During the quarter, we repurchased working interests in several of our wells for a total investment of approximately $165,000. Our average working interest position in our Barnett wells is now more than 50%.November.

Corsicana: We began drilling the second stage of the surfactant-polymer project in the first quarter. A total of 13 new wells are in the process of being drilled, of which four wells will be injectors and nine will be producers. The expansion will continue the drilling pattern established whereby each injector has approximately four producers surrounding it (inverted five-spot drilling pattern). To date,Through the end of the second quarter, we have drilled 12 of the second stage wells, have been drilled and the Company is inbegan the process of adding pumpsexpanding our plant to facilitateaccommodate the increase in volumeaddition of surfactant - -polymer being injected.an alkali injection process as well as the new injector wells. The Company also intends to addis adding an alkali solution to its injection solution, which willprocess in order to help stabilize clays existent in the formation and prevent them from swelling; this should improve the sweep efficiency of the flood.

We have acquiredcontinue to acquire the deeper rights on severalto leases as well as ratifying title to current leasehold. The Company has applied for an area injection permit and planexpects to drill uphave the permit applicable to fiveall of its




leasehold interests in Corsicana, which will result in a reduction of costs and improved efficiencies. One exploratory wells in the area. The first of the four exploratory wellswell (Pecan Gap formation) was drilled during the first quarter, butand another exploratory well (Glen Rose formation) was drilled in the second quarter. Both wells were not completed, as the logs did not show enoughsufficient hydrocarbons to make the wellwells economic. The second well, a Glen Rose well, was spudded in July. We plan to drill up to three more wells in the Pecan Gap formation. We have mitigatedreduced the exploration risk associated with drilling these deeper wells by selling a 50% working interest in each of these wells to our industry partner.




Industry Environment

Oil is a global fungible commodity. The globalizationsglobalization of the world's economy, the rapid development of the emerging markets, and increased commodity speculation have resulted in unprecedented commodity pricing and volatility. Oil prices peaked at unprecedented highs in July before contracting significantly. By early November, oil prices were down nearly 60% from the July highs.

While natural gas is also a fungible commodity, it is more regional in nature than oil. Constant changes in regional supplies and demand have resulted in significant pricing volatility in the natural gas market as well. Natural gas prices (the Houston Ship Channel index) peaked at $13 per MMBTU in early July and have since then dropped by more than 50%.

We operate entirely within the United States, primarily in Texas, a mature region for the exploration and production of oil and gas. The size and frequency of new discoveries of oil and gas in the United States are declining. Therecent trend of increasing commodity prices havehas placed increased upward pressure on finding and development costs.

We believe that For example, during the quarter, a shortage of pipe caused casing and tubing prices to dramatically increase, which resulted in order for an independent oil and gas producer to be successful, the producer must either operate its leases effectively or have significant operational control over their oil and gas properties. As commodity prices fluctuate, controlling costs through operations will make the difference between making a profit and incurring a financial loss.

We believe that there remain certain areasmaterial increase in the continental United States that are under-explored or have not been fully exploited and developed. With the improvements of exploration, production and enhanced recovery technologies, we believe there are acquisition and production opportunities that have not been economically feasible in the past. Larger independent producers and major oil companies have ventured increasingly overseas and offshore, de-emphasizing their onshore United States assets. This movement out of mature basins with significant proven reserves has provided acquisition opportunities for well managed companies that are capable of quickly analyzing opportunities, positioned financially to quickly close an acquisition, and have the technical expertise to generate value from these assets.total completion costs.

We believe the acquisition market for U.S. natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities. Acquisition values have reached historic highs, but we expect these values to begin to soften in the near future. We expect drilling and service costs pressures to ease slightly, but expect them to remain at a high level relative to past pricing. In addition, we expect lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain production in more mature fields.

We derive our revenues from the sale of crude oil and natural gasbelieve that is produced from our properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is the primary factor affecting our revenues.

Crude oil and natural gas are commodities. The price that we receivein order for the crude oil and natural gas we produce is largely a function of market supply and demand. Demand for natural gas in the United States has increased dramatically over the last ten years. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal condition, including hurricanes and tropical storms. Demand for crude oil has also increased over the last ten years while the increase in supply has not increased proportionately resulting in a tight market. Market conditions involving over or under supply of crude oil and natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. A substantial or extended decline inan independent oil and gas pricesproducer to be successful, the producer must either operate its leases effectively or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities ofsignificant operational control over its oil and gas reserves that may be economically producedproperties. As commodity prices fluctuate, controlling costs through operations will make the difference between turning a profit and our ability to access capital markets.incurring a financial loss.




Principal Components of Our Cost Structure

• Direct Operating Expenses. Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include work-over repairs to our oil and gas properties not covered by insurance. To minimize and help control our costs, we acquired a work-over drilling rig and a swab rig in June of 2007, and weWe continue to acquire miscellaneous oil field equipment in the pursuit of operational cost control.

• Production and Ad Valorem Taxes. Taxes. These costs are primarily paid based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities.

• Exploration Expense. Expense. The costs include geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful wells or dry holes. While our current asset mix requires a minimum of geological and geophysical costs and seismic costs, it is possible this component of our cost structure could sharply increase depending upon future property acquisitions.

• Plugging Costs.Costs. The Corsicana field is over one hundred years old and has hundreds of abandoned well bores scattered throughout the properties. In order to properly execute our enhanced oil recovery projects, we need to plug these abandoned, worn out well bores. Since the wells are fairly shallow, we are able to cement in the entire well bore at a cost of less than $1,500 per well. To date we have plugged over 150 old well bores in the Corsicana field and will continue to maintain a schedule of plugging wells throughout the year.




• General and Administrative Expenses. Expenses. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of finding our working interest partners, costs of managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. General and administrative expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants as part of employee compensation.

•  Interest. InterestWe. Historically, we carry minimum levels of debt, butinterest burdened debt. However, in the future,October, we may financeclosed on a portion of our working capital requirements and acquisitions with borrowings under asenior secured credit facility, or with longer-term public traded debt securities. As a result,and, consequently, interest expense couldwill become a much more prevalent component of our cost structure.

• Depreciation, Depletion and Amortization.Amortization. As a successful efforts company, we capitalize all costs associated with our acquisition and all successful development and exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly depreciation of our oilfield equipment assets.

• Income Taxes. We are subject to state and federal income taxes but are currently not in a minimal tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs ("IDC"). We are also subject to some state income taxes. Currently, virtually all of our Federal taxes are deferred; however, at some point, we will utilize all of our net operating loss carry-forwards and we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income.

Results and Analysis of Financial Condition, Cash Flows and Liquidity

During the quarter ended JuneSeptember 30, 2008, we sold approximately 14,63011,565 barrels of oil compared with 6,830approximately 7,800 barrels of oil for the quarter ended JuneSeptember 30, 2007, an increase of approximately 215%48%. The average price for oil sold during the quarter ended June 30, 2008 was $123.01$115.90 per barrel compared with the average price for the quarter ended June 30, 2007 of $61.06$71.50 per barrel, an increase of 201%62%.

We sold approximately 109,755124,300 mcf of gas for the quarter ended JuneSeptember 30, 2008 compared with 66,81582,030 mcf of gas for the quarter ended JuneSeptember 30, 2007, an increase of approximately 164%50%. The average price for




natural gas sold during the quarter ended JuneSeptember 30, 2008 was $8.68$7.57 per mcf (net of transportation, compression and CO2 charges) compared with $5.94$5.45 per mcf for the quarter ended JuneSeptember 30, 2008.2008, an increase of approximately 39%.

Oil and gas revenues for the quarter ended JuneSeptember 30, 2008 were $2,752,747,$2,282,048, compared with $813,924$1,019,222 during the quarter ended JuneSeptember 30, 2007, an increase of 338%approximately 123%. Oil and gas revenues for the six months ended September 30, 2008 were $5,034,795, compared with $1,833,146 for the six months ended September 30, 2007, an increase of approximately 174%.

During the fiscal quarter ended JuneSeptember 30, 2008, we incurred drilling costs of approximately $4.3$0.4 million. Additionally, we repurchased working interests on several of our Barnett wells for approximately $165,000.

On JuneSeptember 30, 2008, we had $0.35$0.28 million in cash and total assets of $25.2$25.5 million. Debt consisted of accounts and notes payables to non-related parties of $3.4$3.7 million, of which, 1.5$1.5 million is long-term. We also had accounts and notes payables to related parties of $9.0$8.4 million.

During the first quarter we retained an investment banking firm to assist us in securing financing to fund our Barnett development and Corsicana re-development programs. The tightening credit market has reduced the opportunities to secure debt financing at terms that are acceptable to our Board. However, subsequent to quarter end we will continue to seek to procureclosed on a $25MM senior secured credit facility. The material terms of the credit facility which when combined withwere reported on our cash flow from production, will provide the liquidity necessaryForm 8K filed on November 4, 2008.

We continue to fully implement our fiscal year 2009 capital expenditure budget. Additionally, we are consideringconsider various other financing options which may or may not be implemented during this fiscal year.




Cash Flow
Our principal sources of cash are operating cash flow, the sale of a portion of the working interest in our Barnett Shale drilling projects, the credit facility and other financing options, including debt and equity, thatwhich may be available to us from time to time. Our operating cash flow is highly dependent on oil and gas prices.

Based on current projections and oil and gas futures prices, the balance of the 2009 capital program is expected to be funded with internal cash flow and the proceeds of a plannedthe credit facility.

However, thereThere can be no assurance that we will be successful in raising additional capital through a subordinated credit facility, private placements or otherwise. Even if we are successful in raising capital through the sources specified, there can be no assurances that any such financing would be available in a timely manner or on terms acceptable to us and our current shareholders. Additional equity financing could be dilutive to our then existing shareholders, and any debt financing could involve restrictive covenants with respect to future capital raising activities and other financial and operational matters.

Capital Requirements
Our primary needs for cash are for exploration and development of our Barnett Shale properties, expanding the enhanced oil recovery projects in our Corsicana properties, and the acquisition of additional oil and gas properties, both in unconventional gas plays and mature fields. OurDue to the tightening credit and equity markets, the increased costs, and the recent contraction in commodity pricing, we have revised our capital expenditure budget for the current fiscal year is $25downward to $12.5 million.

Our drilling budget for the Barnett acreage is $20.5$9.7 million for fiscal year 2009. To date we have completed the seven wells that were in process at year-end and have drilled and completed threesix more wells in our main area of interest in Cooke County. We plan to drill up to 2710 more wells by the end of the fiscal year. We will retain up to 60% working interest in the new wells. We expect to fund the drilling with the proceeds of a planned debtthe credit facility, proceeds from the sale of up to 40% working interest in each well on a turnkey basis, and cash flow from production.

We expect to re-complete at least 16 more wells in up-hole zones in fiscal year 2009 at an average cost for our working interest of approximately $50,000 per well. We expect to fund the entire re-completions out of cash flow.

We have initiated phase two of the Corsicana pilot project and we expect to expandcomplete the project during the last half of this fiscal year. Beginning in the third quarter, we plan to drill six wells per month, one-third of which will be injection wells. Funding for this phase will be achieved primarily through the plannedour $25MM credit facility. The totalrevised capital expenditure budget for our Corsicana project for this fiscal year is $3.4$2 million.




However, thereThere can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to efficiently develop our properties and offset inherent declines in production and proved reserves.

Future Commitments
In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of JuneSeptember 30, 2008, we have no capital leases nor have we entered into any material long-term contracts for equipment, nor do we have any off-balance sheet debt or other such unrecorded obligations.

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at JuneSeptember 30, 2008. In addition to the contractual obligations listed on the table below, our balance sheet at JuneSeptember 30, 2008 reflects accrued interest payable on our debt of $620,666,$667,512, of which $449,122$98,750 is related to the LeaseholdLease Notes Payable, which will not be due until the associated acreage is either sold or drilled.




 Fiscal Years Ending March 31,      
  2009  
2010
  2011  2012  Thereafter  
Total
Office Lease Payments$150,000 $
160,000
 $- $- $- $
310,000
Construction Loan 14,960  16,320  16,320  16,320  126,699  190,619
Notes Payable - Related Parties -  
3,518,924
  -  250,750  -  3,769,674
Short Term Note Payable - Related Party -  
500,000
  -  -  -  
500,000
Line of Credit 525,000  -  -  -  -  525,000
Leasehold Notes Payable -  -  -  -  1,285,100  1,285,100
 $539,960 $4,035,244 $16,320 $267,070 $1,411,799 $6,270,393
 Fiscal Years Ending March 31,      
  2009  
2010
  2011  2012  Thereafter  
Total
Office Lease Payments$75,000 $
160,000
 $- $- $- $
235,000
Construction Loan ** 8,160  16,320  16,320  16,320  179,720  236,840
Notes Payable - Related Parties * -  
3,518,924
  -  250,750  -  3,769,674
Short Term Note Payable - Related Party ** -  
500,000
  -  -  -  
500,000
Line of Credit ** 525,000  -  -  -  -  525,000
Lease Notes Payable -  -  -  -  1,285,100  1,285,100
$608,160 $4,195,244 $16,320 $267,070 $1,464,820 $6,551,614

* Subsequent to quarter end, the $250,750 note payable to a related party was repaid in full with the proceeds of the credit facility.

** Subsequent to quarter end, these notes were repaid in full with the proceeds of the credit facility.

Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital resource position, or for any other purpose.


Inflation and Changes in Prices
Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. In order to minimize our downside exposure to oil and gas price volatility, we will likely hedge ourThe hedges put in place in the prior year have all expired. Currently, the Company has no future production during the second quarter.hedged.

Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during the first quarter, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on our capital costs. Industry capital costs have nearly doubled during the last two years. Industry analysts expect the trend to continue during the next fiscal year.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ.




Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Successful Efforts Method of Accounting

We account for our exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and




productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

To ensure the reliability of our reserve estimates, we engage independent petroleum consultants to prepare an estimate of proved reserves. The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be required in future periods.

We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, physical damage to production equipment and




facilities, a change in costs, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property's carrying value for impairment. We cannot predict whether impairment charges may be required in the future. We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations.




Deferred Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit which can take years to complete and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carry forwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized. In determining deferred tax liabilities, accounting rules require OCI to be considered, even though such income or loss has not yet been earned.

At JuneSeptember 30, 2008, deferred tax liabilities exceeded deferred tax assets by $2.6$2.8 million. We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of costs can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. We currently have no material accruals for contingent liabilities.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

As a "smaller reporting company" defined in Item 10(f)(1) of Regulation S-K, we are electing scaled disclosure reporting obligations and therefore are not required to provide the information requested by this item.

ITEM 4T. CONTROLS AND PROCEDURES.

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective.

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.






PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are currently notOn September 15, 2008, a partyroyalty owner in the Corsicana polymer pilot, representing approximately one-third of the mineral ownership, filed an amendment to a suit originally filed in 2007. The amendment was filed to include the Company as a defendant. The suit, filed in the 13th Judicial District Court in Navarro County, Texas, alleges the lease has expired because no oil was produced from January 2005 through September 2005. The Plaintiff has asked the court to declare the lease to be void; demands payment for any pending legal proceeding. From time to time, we may receive claims ofoil produced and become subject to ordinary routine litigation that is incidentalsold subsequent to the business.time the lease expired; demands that all equipment and salvage located on the lease be given by Court order to the Plaintiff; and asks that any plugging liability be adjudged to be the responsibility of the Company.

The other royalty owners representing the remaining two-thirds mineral ownership have ratified the lease. In October 2008, the Court issued an order requiring the Company and plaintiff to attend mediation to settle the matter.

ITEM 1A. RISK FACTORS.

As a "smaller reporting company" defined in Item 10(f)(1) of Regulation S-K, we are electing scaled disclosure reporting obligations and therefore are not required to provide the information requested by this item.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Not applicable.

ITEM 5. OTHER INFORMATION.

Not applicable.

ITEM 6. EXHIBITS.

EXHIBIT NUMBER DESCRIPTION
   
31.1 CEO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 CFO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 CEO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 CFO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002




SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 REOSTAR ENERGY CORPORATION
  
August __,November 18, 2008 
  By    /s/ Scott D. Allen          
 Scott D. Allen, Chief Financial Officer
(Principal     (Principal Financial Officer and duly authorized signatory)
  
  





1615


EXHIBITS INDEX


EXHIBIT NUMBER DESCRIPTION
   
31.1 CEO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 CFO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 CEO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 CFO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002





1716