REOSTAR ENERGY CORP - Form 10-Q

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

FORM 10-Q
x Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
   
  For the quarterly period ended December 31, 2008
   
o Transition 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 February 12, 2008
 
 
Common Stock, par value $0.001 per share
80,181,310




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   7
     
  ITEM 3-- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 13
     
  ITEM 4T-- CONTROLS AND PROCEDURES 13
     
     
PART II - OTHER INFORMATION  
     
  ITEM 1-- LEGAL PROCEEDINGS 14
     
  ITEM 1A-- RISK FACTORS 14
     
  ITEM 2-- UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 14
     
  ITEM 3-- DEFAULTS UPON SENIOR SECURITIES 14
     
  ITEM 4-- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 14
     
  ITEM 5-- OTHER INFORMATION 14
     
  ITEM 6-- EXHIBITS 14
     
  SIGNATURES 15






PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.

ReoStar Energy Corporation
Consolidated Balance Sheets


 
December 31, 2008
(unaudited)
March 31, 2008
  
ASSETS  
   
 
Current Assets:            
         Cash $
155,279
   $
592,665
  
         Accounts Receivable:            
                  Oil & Gas - Related Party  
574,629
    
868,406
  
                  Other - Related Party  
740,484
    
-
  
         Inventory  
15,814
    
4,748
  
         Hedging Account  
6,316
    
13,062
  
         Total Current Assets  
1,492,522
    
1,478,881
  
   
   
 
Note Receivable  
553,537
    
1,355,228
  
         
Oil and Gas Properties - successful efforts method  
24,805,078
    
17,832,931
  
         Less Accumulated Depletion and Depreciation  
(4,355,967
 )  
(4,139,337
 )
                  Oil & Gas Properties (net)  
20,449,111
    
13,693,594
  
         
Other Depreciable Assets:  
2,603,714
    
1,641,806
  
         Less Accumulated Depreciation  
(300,945
 )  
(121,113
 )
                  Other Depreciable Assets (net)  
2,302,769
    
1,520,693
  
         
Other Related Party Receivable  
81,771
    
80,395
  
Leasehold Held for Sale  
1,680,813
    
1,680,813
  
Investment in Equity Method Investment  
-
    
142,395
  
Total Assets $
26,560,523
   $
19,951,999
  
             
LIABILITIES            
Current Liabilities:            
         Accounts Payable $
44,946
   $
103,479
  
         Notes Payable to Related Party  
-
    
324,330
  
         Payable to Related Parties  
-
    
1,547,136
  
         Royalties Payable  
65,587
    
57,485
  
         Accrued Expenses  
609,691
    
857,887
  
         Accrued Expenses - Related Party  
141,473
    
171,788
  
         Short Term Notes Payable  
-
    
-
  
         Current Portion of Long-Term Debt  
-
    
14,960
  
                  Total Current Liabilities  
861,697
    
3,077,065
  
           
         Notes Payable  
9,213,000
    
1,647,769
  
         Notes Payable - Related Parties  
3,518,924
    
3,194,594
  
         Other Related Party Payables  
240,090
    
490,840
  
         Less Current Portion of Notes Payable  
-
    
(14,960
 )
                  Total Long-Term Debt  
12,972,014
    
5,318,243
  
              
         Deferred Tax Liability  
2,575,793
    
2,163,183
  
                  Total Liabilities  
16,409,504
    
10,558,491
  
             
         Commitments & Contingencies:  
 
    
 
  
                  Contingent Stock Based Compensation  
268,856
    
214,976
  
             
Stockholders' Equity            
         Common Stock, $.001 par,200,000,000 shares authorized and
                  80,181,310 shares outstanding on December 31, 2008
                  and March 31, 2008 		 
80,181
    
80,181
  
         Additional Paid-In-Capital  
9,590,313
    
9,553,346
  
         Retained Earnings (Deficit)  
211,669
    
(454,995
 )
                  Total Stockholders' Equity  
9,882,163
    
9,178,532
  
                  Total Liabilities & Stockholders' Equity $
26,560,523
   $
19,951,999
  
             

See Accompanying Notes to Consolidated Financial Statements

1


ReoStar Energy Corporation
Consolidated Statements of Operations


 
Three Months Ended
     
Nine Months Ended
  
 
December 31, 2008
(unaudited)
  
December 31, 2007
(unaudited)
   
December 31, 2008
(unaudited)
 
December 31, 2007
(unaudited)
 
Revenues                          
         Oil & Gas Sales $
904,494
   $
1,597,018
     $
5,939,289
   $
3,430,164
  
         Sale of Leases  
-
    
-
      
18,005
    
307,028
  
         Other Income  
124,194
    
80,989
      
333,178
    
160,421
  
                     
1,028,688
    
1,678,007
      
6,290,472
    
3,897,613
  
   
   
     
   
 
Costs and Expenses  
   
     
   
 
         Oil & Gas Lease Operating Expenses  
709,047
    
667,420
      
2,094,314
    
1,470,053
  
         Workover Expenses  
35,862
    
16,402
      
196,269
    
38,993
  
         Severance & Ad Valorem Taxes  
103,617
    
93,378
      
389,854
    
202,261
  
         Geological & Geophysical  
-
    
8,993
      
-
    
8,993
  
         Delay Rentals  
-
    
-
      
-
    
52,186
  
         Dry Holes & Abandonments  
9,925
-
9,925
-
  
         Depletion & Depreciation  
453,736
254,721
1,236,372
873,097
  
         General & Administrative:  
   
     
 
    
 
  
                  Salaries & Benefits  
133,284
    
300,393
      
454,744
    
796,733
  
                  Legal & Professional  
44,481
    
210,451
      
358,272
    
490,253
  
                  Other General & Administrative  
173,336
    
90,999
      
384,738
    
238,837
  
         Interest, net of capitalized interest of
         $170,196 and $100,403 for the three
         months ended 12/31/08 and 12/31/07,
         respectively and $482,494 and $368,091
          for the nine months ended 12/31/08 and
         12/31/07, respectively          		  
880
    
-
      
3,780
    
-
  
                     
1,664,168
    
1,642,757
      
5,128,268
    
4,171,406
  
Interest Income  
4,966
    
61,717
      
66,211
    
155,979
  
Loss on Equity Method Investments  
-
    
-
      
(142,395
 )  
-
  
Hedging Loss  
-
    
-
      
(6,746
 )  
-
  
   
   
               
Income (Loss) from continuing operations
           before income taxes and
           discontinued operations 		 
(630,514
 )  
96,967
      
1,079,274
    
(117,814
 )
   
   
               
Income Tax Provision  
220,290
    
(33,938
 )    
(412,651
 )  
41,235
  
         
   
     
 
    
 
  
Income from discontinued operations, net of income taxes:
     
   
 
         Pipeline Income  
-
    
-
      
-
    
22,930
  
         Gain on Sale of Pipeline  
-
    
(2,854
 )    
-
    
1,450,804
  
         Income from discontinued operations  
-
    
(2,854
 )    
-
    
1,473,734
  
Net Income (Loss) $
(410,224
 ) $
60,175
     $
666,623
   $
1,397,155
  
                           
Basic & Diluted Loss per Common Share $
(0.01
 ) $
0.00
     $
0.01
   $
0.02
  
Weighted Average Common
           Shares Outstanding 		 
80,181,310
    
79,711,310
      
80,181,310
    
78,484,396
  
                           


See Accompanying Notes to Consolidated Financial Statements

2


ReoStar Energy Corporation
Consolidated Statements of Cash Flows

 
Nine Months Ended
  
December 31, 2008
(unaudited)
 
December 31, 2007
(unaudited)
 
Operating Activities:            
          Net Income $
666,623
   $
1,397,155
  
                  Adjustments to reconcile net income to cash from operating activities:  
   
 
                  Deferred Income Tax Expense  
412,651
    
752,316
  
                  Depletion, Depreciation, & Amortization  
1,236,372
    
873,097
  
                  Loss on Equity Method Investment  
142,395
    
-
  
                  Stock based compensation  
53,880
    
464,986
  
                  Joint Venture Partner Expense  
-
    
3,084,789
  
                  Gain on Sale of Pipeline  
-
    
(5,272,701
 )
                  Salvage in Excess of Plugging Costs  
(50,290
 )  
-
  
         Changes in Operating Assets and Liabilities  
 
    
 
  
                  Changes in Accrued Liabilities  
(278,511
 )  
(390,144
 )
                  Change in Inventory  
(11,066
 )  
-
  
                  Change in Related Party Receivables/Payables  
(741,859
 )  
(328,894
 )
                  Changes in Other Receivables  
-
    
63,389
  
                  Changes in Hedging Account  
6,746
    
(23,109
 )
                  Changes in Royalties Payable  
8,102
    
48,345
  
                  Change in Revenue Receivables  
293,777
    
(518,929
 )
                  Changes in Accounts Payable  
(58,533
 )  
(412,307
 )
         Net Cash provided (used) from operating activities  
1,680,287
    
(262,007
 )
         Net Cash provided (used) from discontinued operations  
-
    
6,202,067
  
         Net Cash provided (used) by operating activities and
                   discontinued operations 		 
1,680,287
    
5,940,060
  
   
   
 
Investing Activities:  
   
 
         Oil & Gas Drilling, Completing and Leasehold Acquisition Costs  
(7,724,800
 )  
(4,944,410
 )
         Change in Capitalized Note Accretion  
-
    
105,000
  
         Change in Related Party Payable related to drilling  
(1,547,136
 )  
(4,120,568
 )
         Investment in Other Depreciable Assets  
(458,569
 )  
(1,475,435
 )
         Investment in Equity Method Investment  
-
    
(175,000
 )
         Note Receivable Collections (Advances)  
801,691
    
208,905
  
         Net Cash used in investing activities  
(8,928,814
 )  
(10,401,508
 )
   
   
 
Financing Activities  
   
 
         Notes Payable (Payments) Advances  
7,565,231
    
(2,105,078
 )
         Loan Costs  
(503,340
 )  
-
  
         Related Party Note (Payments) Advances  
(250,750
 )  
(100,000
 )
         Net cash received from common stock subscriptions  
-
    
6,885,353
  
         Net Cash provided (used) from financing activities.  
6,811,141
    
4,680,275
  
Net Increase (Decrease) in cash  
(437,386
 )  
218,827
  
Cash - Beginning of the period  
592,665
    
212,254
  
Cash - End of the period $
155,279
   $
431,081
  
             
See Accompanying Notes to Consolidated Financial Statements

3


ReoStar Energy Corporation
Consolidated Statements of Cash Flows
(Continued)


 
Nine Months Ended
  
 
December 31, 2008
(unaudited)
 
December 31, 2007
(unaudited)
 
Supplemental Disclosure of Cash Flow Information            
          Cash paid during period for:            
                  Interest $
290,898
   $
127,111
  
             
                  Income Taxes $
-
   $
-
  
             
Non Cash Investing and Financing Activities            
         Warrants Issued $
36,967
   $
-
  
             
         Stock Based Property Acquisition $
-
   $
298,800
  
             



See Accompanying Notes to Consolidated Financial Statements

4


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 principles 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 principles 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 nine-month period ended December 31, 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 80,181,310 shares of common stock issued and outstanding throughout the quarter ended December 31, 2008.

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 $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 December 31, 2008 and 2007, Salaries and Benefits included stock related compensation costs of $0 and $145,689, respectively. For the nine months ended December 31, 2008 and 2007, Salaries and Benefits included stock related compensation costs of $48,564 and $435,448, 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 December 31, 2008 and 2007 other General & Administrative expenses included stock option costs of $0 and $9,845, respectively. For the nine months ended December 31, 2008 and 2007 other General & Administrative expenses included stock option costs of $5,316 and $29,538, 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.


5


 
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.

On October 30, 2008, the Company repaid the promissory note in full.

(4) SHORT TERM NOTES PAYABLE
During the first quarter, the Company drew $525,000 down on the Frost Bank line of credit. The line of credit was paid in full on October 30, 2008.

(5) OTHER RELATED PARTY PAYABLES
On October 30, 2008, the Company repaid a related party payable of $250,750 in full.

(6) NOTES PAYABLE
On October 30, 2008, the Company entered into a $25,000,000 senior secured credit facility with a bank. 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, we 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 percentage of borrowing base drawn. The credit facility matures October 30, 2011.

On December 31, 2008, the Company has drawn $8,000,000 of the $14,000,000 borrowing base. Accrued interest for the quarter totaling $56,830 was recorded as capitalized interest.

(7) NOTE RECEIVABLE
During the quarter, the Company restructured the note receivable from our drilling contractor. The drilling contractor made a principal payment of $750,000 in November, 2008. The balance of the note will be repaid with monthly payments of $50,000 which began in December, 2008 and accrues interest at 10% annually.

(8) SUBSEQUENT EVENTS
None.


6


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.


7


Significant Accomplishments in the Third Quarter

The Company secured a $25 million senior secured credit facility with Union Bank of California during the quarter. The credit facility will be used to partially fund the Company's capital expenditure budget for the balance of this fiscal year and the fiscal years ending in 2010 and 2011.

Barnett Shale: We brought all three wells that were in process at the end of the second quarter on line during the quarter.

A fourth well was drilled during the quarter, and a fifth well was being drilled at the end of the quarter. No completion date has been targeted for these wells due to soft commodity prices.

Corsicana: We continue to acquire the deeper rights to leases as well as ratifying title to current leasehold. Two exploratory wells in the Pecan Gap formation were drilled during the quarter. The wells were completed during January 2009. We have identified several more drilling locations which are offsets to the wells completed in January and expect to spud the new wells late in the fourth quarter. We expect to reduce the exploration risk associated with drilling these deeper wells by selling up to 50% of the working interest in each of these wells to an industry partner.

Industry Environment

Oil is a global fungible commodity. The globalization 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 the end of December, oil prices were down more than 70% 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 60%.

The rapid run up in commodity prices encouraged a substantial drilling, which resulted in upward pressure on finding and development costs. For example, during the second quarter, a shortage of pipe caused casing and tubing prices to dramatically increase, which resulted in a material increase in 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. 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 believe that 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 its oil and gas properties. As commodity prices fluctuate, controlling costs through operations will make the difference between turning a profit and incurring a financial loss.

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. We continue to acquire miscellaneous oil field equipment in the pursuit of operational cost control.

• 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.


8


• 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 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 $2,500 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. 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. Historically, we carry minimum levels of interest burdened debt. However, in October, we closed on a senior secured credit facility, and, consequently, interest expense will become a much more prevalent component of our cost structure.

• 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 depreciation of our oilfield equipment assets.

• Income Taxes. We are subject to state and federal income taxes but are currently 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 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 December 31, 2008, we sold approximately 9,650 barrels of oil compared with approximately 9,980 barrels of oil for the quarter ended December 31, 2007, a decrease of approximately 3%. The average price for oil sold during the quarter ended December 31, 2008 was $55.90 per barrel compared with the average price for the quarter ended December 31, 2007 of $87.55 per barrel, a decrease of 36%.

We sold approximately 123,000 mcf of gas for the quarter ended December 31, 2008 compared with approximately 110,000 mcf of gas for the quarter ended December 31, 2007, an increase of approximately 12%. The average price for natural gas sold during the quarter ended December 31, 2008 was $3.10 per mcf (net of transportation, compression and CO2 charges) compared with $6.53 per mcf for the quarter ended December 31, 2007, a decrease of approximately 52.5%.

Oil and gas revenues for the nine months ended December 31, 2008 were $5,939,289 compared with $3,430,164 for the nine months ended December 31, 2007, an increase of approximately 73%.

During the fiscal quarter ended December 31, 2008, we incurred drilling and completion costs of approximately $2.9 million.

On December 31, 2008, we had $0.16 million in cash and total assets of $26.4 million. Debt consisted of accounts and notes payables to non-related parties of $9.9 million, of which, $9.2 million is long-term. We also had accounts and notes payables to related parties of $3.9 million.


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During the quarter, we secured a $25 million credit facility secured by our assets. The material terms of the credit facility were reported on our Form 8-K filed on November 4, 2008. The remaining credit available under the credit facility at quarter end was $4.7 million.

We continue to consider 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, which 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 the credit facility.

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. Due to the tightening credit and equity markets, the increased costs, and the recent contraction in commodity pricing, we have suspended our development drilling program in the Barnett Shale and have deferred planned expansion of the enhanced oil recover project in Corsicana. While, management has not determined a capital expenditure budget for fiscal year 2010, we expect total investment to be less than half the amount during the current fiscal year.

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. 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 shareholders, and any debt financing could involve restrictive covenants with respect to future capital raising activities and other financial and operational matters.

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 December 31, 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 December 31, 2008. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2008 reflects accrued interest payable on our debt of $751,164, of which $544,772 is related to the Lease 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 $
37,500
  
$
160,000
  
$
-
   $
-
   $
-
   $
197,500
Notes Payable - Related Parties  
-
  
 
-
  
 
-
    
-
    
3,518,924
    
3,518,924
Senior Secured Note Payable  
-
  
 
-
  
 
8,000,000
    
-
    
-
    
8,000,000
Lease Notes Payable  
-
  
 
-
  
 
-
    
-
    
1,213,000
    
1,213,000
$
37,500
   $
160,000
   $
8,000,000
   $
-
   $
4,731,924
   $
12,929,424
                                   

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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. The hedges put in place in the prior year have all expired. Currently, the Company has no future production 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 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.


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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 December 31, 2008, deferred tax liabilities exceeded deferred tax assets by $2.55 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.


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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.




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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

On September 15, 2008, a royalty 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 oil produced and sold subsequent to the 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. The Company and plaintiff attended mediation in Corsicana, Texas, but were unable to resolve the matter during the mediation.

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
     
10.1 Credit Agreement, dated October 30, 2008, among ReoStar Energy Corporation, certain lenders party thereto from time to time, and Union Bank of California, N.A. as administrative agent and issuing lender. (Incorporated by reference from the registrant's current report on Form 8-K filed on November 4, 2008.)
10.2 Security Agreement, dated October 30, 2008, among ReoStar Energy Corporation, ReoStar Gathering, Inc., ReoStar Leasing, Inc., ReoStar Operating Incorporated, and Union Bank of California, N.A. as administrative agent. (Incorporated by reference from the registrant's current report on Form 8-K filed on November 4, 2008.)
10.3 Pledge Agreement, dated October 30, 2008, among ReoStar Energy Corporation and Union Bank of California, N.A. as administrative agent. (Incorporated by reference from the registrant's current report on Form 8-K filed on November 4, 2008.)
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


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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
   
February 12, 2009  
  
 By    /s/ Scott D. Allen                                
       Scott D. Allen, Chief Financial Officer
     (Principal Financial Officer and duly authorized signatory)
   
   





15


EXHIBITS INDEX


EXHIBIT NUMBER   DESCRIPTION
     
10.1 Credit Agreement, dated October 30, 2008, among ReoStar Energy Corporation, certain lenders party thereto from time to time, and Union Bank of California, N.A. as administrative agent and issuing lender. (Incorporated by reference from the registrant's current report on Form 8-K filed on November 4, 2008.)
10.2 Security Agreement, dated October 30, 2008, among ReoStar Energy Corporation, ReoStar Gathering, Inc., ReoStar Leasing, Inc., ReoStar Operating Incorporated, and Union Bank of California, N.A. as administrative agent. (Incorporated by reference from the registrant's current report on Form 8-K filed on November 4, 2008.)
10.3 Pledge Agreement, dated October 30, 2008, among ReoStar Energy Corporation and Union Bank of California, N.A. as administrative agent. (Incorporated by reference from the registrant's current report on Form 8-K filed on November 4, 2008.)
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





16