REOSTAR ENERGY CORP - Form 10-QSB

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

FORM 10-QSB

[X] Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934
   
  For the quarterly period ended September 30, 2007.
   
[   ] Transition report under 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
Name of small business issuer in its charter

Nevada
  
 
  
20-8428738
(State or other jurisdiction of incorporation)
  
 
  
(IRS Employer Identification No.)
 
 


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


(817) 989-7367
(Registrant's telephone number)



                   Check whether the issuer: (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]   No [ ]

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

                   State the number of shares outstanding of each of the issuer's classes of common equity, as of the latest practicable date:

                                    Class                                    
Outstanding at October 31, 2007
 
 
Common Stock, par value $0.001 per share
79,831,310




REOSTAR ENERGY CORPORATION

INDEX
    Page

PART I - FINANCIAL INFORMATION

  ITEM 1-- FINANCIAL STATEMENTS   1
   
  ITEM 2-- MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION   8
   
  ITEM 3-- CONTROLS AND PROCEDURES 15
   
PART II - OTHER INFORMATION
   
  ITEM 1-- LEGAL PROCEEDINGS 15
   
  ITEM 2-- UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 15
     
  ITEM 3-- DEFAULTS UPON SENIOR SECURITIES 15
     
  ITEM 4-- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 15
     
  ITEM 5-- OTHER INFORMATION 15
     
  ITEM 6-- EXHIBITS 15
     
  SIGNATURES 16
     
     






REOSTAR ENERGY CORPORATION
PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ReoStar Energy Corporation
Consolidated Balance Sheet
September 30, 2007
(unaudited)


ASSETS  
 
Current Assets:      
         Cash $
3,571,920
  
         Accounts Receivable:      
                  Oil and Gas  
637,299
  
                  Lease Sales  
737,913
  
                  Related Party  
403,111
  
         Total Current Assets  
5,350,243
  
   
 
Note Receivable  
1,465,424
  
       
Oil and Gas Properties - successful efforts method  
14,816,930
  
         Less Accumulated Depletion and Depreciation  
(3,327,272
 )
                  Oil and Gas Properties (net)  
11,489,658
  
       
Other Depreciable Assets:  
1,372,717
  
         Less Accumulated Depreciation  
(31,147
 )
                  Other Depreciable Assets (net)  
1,341,570
  
Total Assets $
19,646,895
  
       
LIABILITIES      
Current Liabilities:      
         Accounts Payable $
1,002,267
  
         Payable to Related Parties  
250,750
  
         Royalties Payable  
13,834
  
         Accrued Expenses  
1,037,870
  
         Current Portion of Long-Term Debt  
3,194,594
  
                  Total Current Liabilities  
5,499,315
  
       
         Notes Payable  
1,646,334
  
         Notes Payable - Related Parties  
3,618,924
  
         Less Current Portion of Notes Payable  
(3,194,594
 )
                  Total Long-Term Debt  
2,070,664
  
       
         Deferred Tax Liability  
2,454,476
  
                  Total Liabilities  
10,024,455
  
       
         Commitments and Contingencies:  
-
  
                  Contingent Stock Based Compensation  
309,451
  
       
Stockholders' Equity      
         Common Stock, $.001 par,200,000,000 shares authorized
                  79,831,310 and shares outstanding on September 30, 2007 		 
79,831
  
         Additional Paid-In-Capital  
9,147,072
  
         Retained Earnings  
86,086
  
                  Total Stockholders' Equity  
9,312,989
  
                  Total Liabilities and Stockholders' Equity $
19,646,895
  
       

See Accompanying Notes to Financial Statements


1


ReoStar Energy Corporation
Consolidated Statements of Operations


   
Three Months Ended
  
Six Months Ended
 
Twelve Months
Ended
 
   
Sept. 30, 2007
(unaudited)
    
June 30, 2007
(unaudited)
    
Sept. 30, 2007
(unaudited)
    
December 31, 2006
(audited)
  
Revenues                        
         Oil and Gas Sales $
1,019,222
   $
813,924
   $
1,833,146
   $
2,874,291
  
         Sale of Leases  
307,028
    
-
    
307,028
    
400,378
  
         Other Income  
79,367
    
65
    
79,432
    
45,771
  
                  Total Revenue  
1,405,617
    
813,989
    
2,219,606
    
3,320,440
  
   
   
   
   
 
Costs and Expenses  
   
   
   
 
         Oil & Gas Lease Operating Expenses  
491,703
    
333,521
    
825,224
    
1,131,502
  
         Severance and Ad Valorem Taxes  
59,947
    
48,936
    
108,883
    
163,523
  
         Delay Rentals  
8,571
    
43,615
    
52,186
    
-
  
         Depletion & Depreciation  
332,245
    
286,131
    
618,376
    
1,856,365
  
         General & Administrative:  
-
    
-
    
-
    
281,727
  
                  Salaries and Benefits  
249,533
    
233,479
    
483,012
    
-
  
                  Legal & Professional  
121,953
    
157,849
    
279,802
    
-
  
                  Other General & Administrative  
101,751
    
59,415
    
161,166
    
-
  
         Interest, net of capitalized interest of $126,676 and
             $141,012 for the periods ended 9/30/2007 and
             6/30/2007, respectively 		 
-
   
-
   
-
   
13,660
  
                  Total Costs and Expenses  
1,365,703
    
1,162,946
    
2,528,649
    
3,446,777
  
   
   
   
   
 
Income from continuing operations before income taxes  
39,914
    
(348,957
 )  
(309,043
 )  
(126,337
 )
   
   
   
   
 
Income from discontinued operations:  
   
   
   
 
         Pipeline Income  
-
    
35,277
    
35,277
    
319,093
  
         Gain on Sale of Pipeline  
(7,952
 )  
2,244,349
    
2,236,397
    
-
  
         Income from discontinued operations  
(7,952
 )  
2,279,626
    
2,271,674
    
319,093
  
   
   
   
   
 
Interest Income  
70,930
    
23,332
    
94,262
    
-
  
Income Tax Provision  
(36,013
 )  
(683,900
 )  
(719,913
 )  
-
  
Net (Loss) Income $
66,879
   $
1,270,101
   $
1,336,980
   $
192,756
  
                         
                         
Basic and Diluted Loss per Common Share $
0.00
   $
0.02
   $
0.02
        
Weighted Average Common Shares Outstanding  
79,711,310
    
76,524,026
    
77,907,148
        
                         
                         
Pro-Forma Earnings Per Share                        
         Net Income                   $
192,756
  
         Proforma Income Tax Expense at Statutory Rate (35%)                    
(67,465
 )
         Proforma Net Income                   $
125,291
  
                         
Proforma Weighted Average Shares Outstanding                    
68,129,310
  
                         
Proforma Basic and Diluted Earnings Per Share                   $
0.00
  
                         


See Accompanying Notes to Financial Statements

2


ReoStar Energy Corporation
(Formerly Goldrange Resources, Inc.)
Consolidated Statements of Cash Flows

   
Three Months Ended
  
Six Months Ended
 
Twelve Months
Ended
 
Operating Activities:  
Sept. 30, 2007
(unaudited)
    
June 30, 2007
(unaudited)
    
Sept. 30, 2007
(unaudited)
    
December 31, 2006
(audited)
  
         Net (Loss) Income $
66,879
   $
1,270,101
   $
1,336,980
   $
192,756
  
                  Adjustments to reconcile net cash from operating activities:  
   
   
   
 
                  Deferred Income Tax Expense  
36,013
    
683,900
    
719,913
    
-
  
                  Depletion, Depreciation, & Amortization  
332,245
    
286,131
    
618,376
    
1,856,365
  
                  Note Accretion  
35,000
    
35,000
    
70,000
    
128,334
  
                  Stock based compensation  
165,381
    
144,070
    
309,451
    
-
  
                  Joint Venture Partner Expense  
7,952
    
3,072,448
    
3,080,400
    
332,413
  
                  Gain on Sale of Pipeline  
-
    
(5,272,701
 )  
(5,272,701
 )  
-
  
         Changes in Operating Assets and Liabilities  
-
    
-
    
-
    
-
  
                  Cash Overdraft  
-
    
-
    
-
    
186,912
  
                  Changes in Other Assets  
-
    
-
    
-
    
(13,455
 )
                  Changes in Accrued Liabilities  
87,339
    
37,027
    
124,366
    
86,667
  
                  Change in Related Party Receivables/Payables  
(418,070
 )  
25,902
    
(392,168
 )  
(543,483
 )
                  Changes in Other Receivables  
(737,913
 )  
63,389
    
(674,524
 )  
2,324
  
                  Changes in Royalties Payable  
13,834
    
-
    
13,834
    
-
  
                  Change in Revenue Receivables  
(132,712
 )  
(9,387
 )  
(142,099
 )  
86,762
  
                  Changes in Accounts Payable  
261,006
    
(193,131
 )  
67,875
    
-
  
         Net Cash provided from operating activities  
(283,046
 )  
142,749
    
(140,297
 )  
2,315,595
  
         Net Cash provided (used) from discontinued operations  
(362,292
 )  
7,164,405
    
6,802,113
   
(2,103,248
 )
         Net Cash provided (used) by operating activities and
                   discontinued operations 		 
(645,338
 )  
7,307,154
    
6,661,816
    
212,347
  
   
   
   
   
 
Investing Activities:  
   
   
   
 
   
   
   
   
 
         Oil & Gas Drilling, Completing and Leasehold Acquisition Costs  
(1,852,728
 )  
(960,681
 )  
(2,813,409
 )  
(6,371,739
 )
         Change in Drilling Reimbursements in Excess of Costs  
-
    
-
    
-
    
492,160
  
         Change in Related Party Payable related to drilling  
(293,993
 )  
(3,826,575
 )  
(4,120,568
 )  
2,220,498
  
         Deposits  
-
    
-
    
-
    
200,000
  
         Investment in Other Depreciable Assets  
(454,038
 )  
(918,679
 )  
(1,372,717
 )  
-
  
         Note Receivable Collections  
67,343
    
81,451
    
148,794
    
-
  
         Net Cash used in investing activities  
(2,533,416
)  
(5,624,484
 )  
(8,157,900
 )  
(3,459,081
 )
   
   
   
   
 
Financing Activities  
   
   
   
 
         Notes Payable (Payments) Advances  
(79,603
 )  
(1,950,000
 )  
(2,029,603
 )  
704,466
  
         Changes in Notes Payable Related Party  
-
    
-
    
-
    
1,264,957
  
         Net cash received from common stock subscriptions  
-
    
6,885,353
    
6,885,353
    
-
  
         Net Cash provided from financing activities.  
(79,603
 )  
4,935,353
    
4,855,750
   
1,969,423
  
   
   
   
   
 
Net Increase in cash  
(3,258,357
 )  
6,618,023
    
3,359,666
    
(931,139
 )
Cash - Beginning of the period  
6,830,277
    
212,254
    
212,254
    
1,263,552
  
Cash - End of the period $
3,571,920
   $
6,830,277
   $
3,571,920
   $
332,413
  
                         

See Accompanying Notes to Financial Statements

3


ReoStar Energy Corporation
Consolidated Statements of Cash Flows
(Continued)


   
Three Months Ended
  
Six Months Ended
 
Twelve Months
Ended
 
   
Sept. 30, 2007
(unaudited)
    
June 30, 2007
(unaudited)
    
Sept. 30, 2007
(unaudited)
    
December 31, 2006
(audited)
  
Supplemental Disclosure of Cash Flow Information                        
         Cash paid during period for:                        
                  Interest $
4,337
   $
59,993
   $
64,330
   $
185,284
  
                         
                  Income Taxes  
-
    
-
    
-
    
-
  
                         
Non Cash Investing and Financing Activities                        
         Stock Based Property Acquisition $
298,800
   $
-
   $
-
   $
-
  
                         



See Accompanying Notes to Financial Statements

4


REOSTAR ENERGY CORPORATION
(FORMERLY GOLDRANGE RESOURCES, INC.)
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, 2007. 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 period ended September 30, 2007, are not necessarily indicative of the results that may be expected for the year ending March 31, 2008. 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.

The following is a schedule of changes in the number of outstanding common shares since June 30, 2007

 
Quarter Ended
September 30, 2007
 
Beginning Balance
79,591,310
  
Wilson Energy Inc. Asset Acquisition
240,000
  
Shares outsanding September 30, 2007
79,831,310
  
     

Effective as of August 1, 2007, ReoStar acquired the assets of Wilson Energy Inc for $159,000 cash and 240,000 shares of stock. A description of the material terms of the transaction is set forth on our Form 8-K filed on October 4, 2007.

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 vest on March 31, 2008, and the balance of the shares will vest on March 31, 2009. For the quarter ended September 30, 2007 and the six months ended September 30, 2007, Salaries and Benefits included stock related compensation costs of $145,689 and $289,759, 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 will vest annually on March 31 2008, 2009, and 2010. For the quarter ended September 30, 2007 and the six months ended September 30, 2007, other General & Administrative expenses included stock option costs of $9,845 and $19,691, respectively.


5


The estimated compensation expense related to the restricted stock grant and stock option grants for the following three year period is shown in the table below:
Year Ending March 31
  
   
2008
    
2009
    
2010
  
Restricted Stock Compensation $
581,137
   $
$195,336
  $
-
  
Stock Option Compensation  
39,382
    
21,256
    
9,232
  
  $
620,519
   $
216,592
   $
9,232
  
                   

(3) DISCONTINUED OPERATIONS
Effective May 1, 2007 we sold our entire interest in the Tri-County Gas Gathering System. The sales price was $15,000,000. The proceeds from the sale was reduced $900,000 for outstanding capital calls. The proceeds were distributed as follows: $12.5 million were distributed in June at closing with the balance of $1.6 million escrowed. Of the escrowed amount, $600,000 was released in September (90 days after closing) and the balance of $1 million is scheduled to be released from escrow in December 2007 (180 days after closing). Approximately $7.9 million of the net proceeds were allocable to the minority interest partners. The following table reflects the calculation of gain from the sale.
   
Sept. 30, 2007
  
Total Proceeds $
15,000,000
  
Closing adjustment for unpaid capital calls  
(900,000
 )
Net Proceeds  
14,100,000
  
Basis in the pipeline  
(8,827,299
 )
Total Gain on sale  
5,272,701
  
Less Allocations to Minority Interest  
(3,036,304
 )
Gain on Sale of Pipeline $
2,236,397
  
       

(4) OTHER DEPRECIABLE ASSETS
In June 2007, ReoStar formed a wholly owned subsidiary, ReoStar Leasing, Inc. ("RLI"), a Texas corporation. RLI acquired a workover drilling rig and a swab rig near the end of June. In July, RLI began leasing the rigs to the related party operator of its Barnett Shale properties. Effective August 1, 2007, RLI acquired a service rig which was leased to the related party operator of its Corsicana properties. The rigs were included in other depreciable assets on September 30, 2007. The following table summarizes the other depreciable asset holdings at period end.


6



   
Sept. 30, 2007
  
Workover Drilling Rig $
687,777
  
Swab Rig  
175,000
  
Service Rig  
200,000
  
Office Equipment & Other  
309,940
  
Total Other Depreciable Assets $
1,372,717
  
       

(5) SALE OF LEASES
In late September, ReoStar entered into an agreement to sell approximately 1,738 acres of undeveloped minerals in the Barnett Shale area. The acreage disposed was not in the ReoStar's core area of operations. The acreage was sold for a gain of approximately $300,000. The sale closed in mid-October.

(6) SUBSEQUENT EVENTS
In late October, the Company agreed to acquire 710 acres of undeveloped minerals in the Company's core area of operations in the Barnett Shale for $213,000. We expect to complete the purchase in November 2007.



7


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

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-QSB 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, 2007 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 an independent natural gas and oil company engaged in the acquisition, development, and production of natural gas and oil properties, primarily focused on developmental resource plays and enhanced oil recovery projects located in the Mid-Continent Region of the United States.



8


ReoStar's development strategy is to acquire acreage positions in resource plays such as the Barnett Shale in North Texas and acreage in mature oil fields that provide the opportunity to increase production through secondary or tertiary recovery techniques. Our objective is to increase reserves and production through internally generated drilling projects coupled with complementary acquisitions. Further, we evaluate various Enhanced Oil Recovery (EOR) techniques to optimize exploitation of mature oil holdings.

Vern Wilson Energy Transaction

On September 28, 2007, we entered into a Purchase and Sale Agreement with Vern Wilson Energy, Inc, a Texas corporation ("WEI"). As a result, we purchased from WEI its working interests in 4 oil and gas leases located in Texas and Louisiana, a service rig, and an operating shop to assist in maintenance of field equipment. The leases have 30 total wells with 8 currently producing and one salt water disposal well. Eight additional wells are planned for recompletion in the immediate future. The acquisition provides the company with an introduction to the East Texas Field and all the related opportunities in the area. The acquisition of the service rig adds to our equipment inventory that already includes a work-over rig and a swab rig, which we believe will allow us to significantly lower completion and operating costs by not having to procure this equipment on an hourly basis from third-party vendors.

Barnett Shale: We expect to bring two of the wells that were in process on September 30 online during the third quarter. During the second quarter we began a close proximity "cluster" re-completion and infill drilling program in our Barnett Shale properties. We will continue to implement the program during the third quarter. During the third quarter, we expect to drill and complete a cluster of 3 new wells and 1 older well (a recompletion). We also expect to begin drilling two wells which will be part of a cluster that will be completed during the fourth quarter. All wells within a cluster will be fractured using high pressure stimulation within a seven-day period and be brought online simultaneously.

Corsicana: We began injecting a polymer-surfactant solution into our pilot area in mid-June. During the second quarter we injected a total of approximately 600 barrels of the polymer-surfactant solution in 6 injection wells per day. Pressures have slowly been increasing and we have begun to see incremental increases in production in two of the seven producer wells. We will continue to closely monitor the injection process and expect to see continuing improvement in results during the third and fourth quarter of this fiscal year.

We have begun to permit and plan the drilling of the next 13 wells for the second stage of the pilot project. We are in the process of securing additional financing for the continued expansion of our pilot project. We expect to secure financing and begin work on the second stage during the third quarter and expect to complete the second stage during the fourth quarter.

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.


9


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.

Industry Environment
We operate entirely within the United States, 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, while finding and development costs are increasing.

We believe that there remain certain areas in the continental United States which are under-explored or have not been fully explored and developed with the benefit of newly available exploration, production and reserve enhancement technology. Examples of such technology include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation, advances in well logging and analysis, and enhanced oil recovery practices.

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, well positioned financially to quickly close an acquisition, and have the technical expertise to generate additional value from these assets.

In other situations, to increase cash flow without increasing capital spending, larger independent producers and major integrated oil companies have allowed smaller companies the opportunity to explore and develop reserves on their undeveloped acreage through joint ventures and farm-in arrangements.

We believe the acquisition market for 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 in 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 aging fields.

We derive our revenues from the sale of crude oil and natural gas 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 receive 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 in oil and gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and our ability to access capital markets.

Principal Components of Our Cost Structure
• Direct Operating 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 have recently acquired a service rig to add to our previously acquired work-over drilling rig and swab rig.

•Production and Ad Valorem 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.


10


• Exploration 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. The Corsicana field is over one hundred years old and has approximately 200 suspended wells scattered throughout the properties. In order to properly execute our enhanced oil recovery projects, we will plug the suspended wells that have no mechanical integrity. Since the wells are shallow, we are able to plug the well bore at a cost of less than $1,500 per well and can plug up to 15 wells in one day.

• General and Administrative Expense. 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. We may finance a portion of our working capital requirements and acquisitions with borrowings under a credit facility or with longer term public traded debt securities. As a result, interest expense could become a much more prevalent component of our cost structure. Currently we capitalize all interest associated with acquiring and developing our oil and gas properties.

• Depreciation, Depletion and 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 amortization of capitalized interest.

• 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 September 30, 2007, we sold approximately 7,800 barrels of oil compared with 6,829 barrels of oil for the previous quarter, an increase of approximately 14%. We sold 82,030 mcf of gas for the quarter ended September 30, 2007 compared with 66,816 mcf of gas for the previous quarter, an increase of approximately 23%.

The average price for natural gas sold during the quarter was $5.45 per MCF net of transportation, compression and CO2 charges compared with $5.95 per MCF for the previous quarter. The average price per barrel of oil was $71.50 compared with $62.00 per barrel during the previous quarter.

Oil and gas revenues for the quarter ended September 30, 2007 were $1,019,222, compared with $813,924 during the previous quarter, an increase of 25%.

During the fiscal quarter ended September 30, 2007, we spent approximately $2.6 million on capital expenditures . For the six months ended September 30, 2007 we spent approximately $8.3 million on capital expenditure, of which approximately $4.1 million related to drilling costs incurred prior to the February 1, 2007 contribution of assets.

On September 30, 2007, we had $3.6 million in cash and total assets of $20 million. Debt consisted of payables to non-related parties of $3.4 million, of which, 1.6 million is long-term. We also had accounts and notes payables to related parties of $3.8 million.


11


Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves (which is typical in the oil and gas industry). The future success of increasing reserves and production will be dependent on capital resources available and the success of finding or acquiring additional reserves. We believe that net cash generated from operating activities and the proceeds from our private placement offering will be adequate to satisfy near-term financial obligations and liquidity needs.

However, long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. A material drop in oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings or the issuance of debt or equity securities. There 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.

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, and the issuance of equity securities. 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 2007 capital program is expected to be funded with internal cash flow, asset sales and the company's cash resources.

Capital Requirements
Our primary needs for cash are for exploration and development of our Barnett Shale properties, establishing 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. During the year ended December 31, 2006, a predecessor company, REO Energy, Ltd. expended approximately $24 million on Barnett drilling projects. During the three months ended September 30, 2007 and June 30, 2007, respectively, $4.7 million and $4.7 million of capital was expended on Barnett Shale drilling projects. Our working interest partners contributed approximately $3.9 million and $3.4 million respectively for the quarters ended September 30, 2007 and June 30, 2007 toward the Barnett Shale drilling costs. Our retained working interests in the Barnett Shale development program was funded by cash flow from the Barnett Shale properties and cash on hand.

We have initiated phase two of the Corsicana pilot project and we expect to expand the project during the next fiscal year. We plan to drill more than eighty-eight wells, one-third of which will be injection wells, over the next six quarters. This phase will require at least one additional polymer mixing plant. Funding for this phase will be achieved partially through the Company's resources and additional outside capital. Management is considering its options with regards to such funding, which could be as much as $15 million, As the redevelopment program progresses, we expect the remaining capital requirements will be derived from the project's cash flow. There is no guarantee that such outside capital will be available to us or, if available, it will be on terms acceptable to us.

Cautionary Statement: There can be no assurance that we will be successful in raising capital through 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.


12


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 September 30, 2007, 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 September 30, 2007. In addition to the contractual obligations listed on the table below, our balance sheet at September 30, 2007 reflects accrued interest payable on our debt of $276,568.

 
Fiscal year ended March 31
  
 
2008
 
2009
 
2010
  
Office Lease
111,000
150,000
132,000
  
Mineral Lease loans
-
100,000
-
  
Related Party Notes Payable
3,194,594
324,330
-
  


We expect to refinance the $3.3 million related party note before the note becomes due.

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 more than likely begin to hedge our future production during the third quarter.

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 2005 and 2006, 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. We expect demand for vertical drilling rigs in the Barnett Shale to ease during the next fiscal year, which we expect will result in a leveling out of our capital costs during the next fiscal year.

Management's Discussion of 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.


13


Oil and Gas Properties
To ensure the reliability of our reserve estimates, we engage independent petroleum consultants to prepare an estimate of proved reserves. Proved reserves are defined by the SEC 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 September 30, 2007, deferred tax liabilities exceeded deferred tax assets by $2.4 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


14



ITEM 3. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, we conducted an evaluation, under the supervision and with the participation of our chief executive office r and chief financial officer of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")). Based upon this evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. There was no change in our internal controls or in other factors that could affect these controls during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are currently not a party to any pending legal proceeding. From time to time, we may receive claims of and become subject to routine litigation that is incidental to the business.

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

None

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


15



SIGNATURES

           In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

  REOSTAR ENERGY CORPORATION
November 14, 2007  
  
 By /s/ Mark S. Zouvas                                         
  Mark S. Zouvas, Chief Executive Officer
   
   





16


EXHIBITS INDEX
EXHIBIT NUMBER   DESCRIPTION
     
10.1   Purchase and Sale Agreement by and between ReoStar Energy Corporation and Vern Wilson Energy, Inc. dated September 28, 2007. (Incorporated by reference to the Form 8-K filed on October 4, 2007)
     
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
     
     



17