FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
x
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

-OR-

¨
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to _______
 
 
Commission file number 001-32997

 
PETRO RESOURCES CORPORATION
(Name of registrant as specified in its charter)

Delaware
86-0879278
(State or other jurisdiction of
incorporation or organization)
(IRS Employer
Identification No.)

777 Post Oak Boulevard, Suite 910, Houston, Texas 77056
(Address of principal executive offices)

(832) 369-6986
(Issuer’s telephone number)
 
 
Indicate by check mark  whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding twelve months, and (2) has been subject to such filing requirements for the past 90 days. Yes x No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ¨ No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):
 
Large accelerated filer o
Accelerated filer o
   
Non-accelerated filer o
Smaller reporting company x
(Do not check if a smaller reporting company)
 

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

As of May 1, 2009 there were 36,788,172 shares of the registrant’s common stock ($.01 par value) outstanding.


PETRO RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q
FOR THE PERIOD ENDED MARCH 31, 2009

TABLE OF CONTENTS
 
 
Page
   
PART I. FINANCIAL INFORMATION
 
   
Item 1. Financial Statements (Unaudited):
1
   
Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008
1
   
Consolidated Statements of Operations for the Three Months March 31, 2009 and 2008
2
   
Consolidated Statements of Cash Flows for the Three months Ended March 31, 2009 and 2008
3
   
Notes to Consolidated Financial Statements
4
   
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
8
   
Item 3. Quantitative and Qualitative Disclosures About Market Risk                                                                                                                                
18
   
Item 4T. Controls and Procedures
18
   
Part II. OTHER INFORMATION
20
 
 
Item 6. Exhibits
20
   
SIGNATURES
21
 
i

PART I.  FINANCIAL INFORMATION
 
ITEM 1.      FINANCIAL STATEMENTS (UNAUDITED)
 
PETRO RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
             
             
   
March 31,
   
December 31,
 
   
2009
   
2008
 
Assets
           
Current assets
           
Cash and cash equivalents
  $ 2,154,045     $ 6,120,402  
Accounts receivable
    1,192,112       1,038,973  
Prepaids
    13,521       75,406  
Derivative assets
    2,964,445       2,944,997  
Total current assets
    6,324,123       10,179,778  
                 
                 
Property and equipment
               
Oil and natural gas properties, successful efforts accounting
               
Unproved
    17,807,560       18,562,932  
Proved properties, net
    30,638,182       27,264,790  
Furniture and fixtures, net
    104,833       110,499  
Total property and equipment
    48,550,575       45,938,221  
                 
Other assets
               
Derivative Assets
    3,820,966       4,338,832  
Deferred financing costs, net of amortization of $232,102 and $129,200 respectively
    1,094,878       1,197,780  
Deposit
    10,257       10,257  
Total other assets
    4,926,101       5,546,869  
                 
Total Assets
  $ 59,800,799     $ 61,664,868  
                 
Liabilities and Shareholders' Equity
               
Current liabilities
               
Accounts payable
  $ 2,022,377     $ 2,617,034  
Accrued liabilities
    96,746       106,592  
Payable on sale of partnership
    754,255       754,255  
Note payable
            19,527  
Total current liabilities
    2,873,378       3,497,408  
                 
Revolving credit borrowings
    6,500,000       6,500,000  
Term loan
    15,000,000       15,000,000  
Asset retirement obligation
    1,646,285       1,589,197  
Total liabilities
    26,019,663       26,586,605  
                 
Shareholders' equity
               
Preferred stock, $0.01 par value; 10,000,000 shares authorized,
               
none issued and outstanding.
    -       -  
                 
Common stock, $0.01 par value; 100,000,000 shares authorized,
               
36,788,172 and 36,768,172 shares issued and outstanding
               
as of March 31, 2009 and December 31, 2008 respectively
    367,882       367,682  
Additional paid in capital
    51,504,077       51,311,502  
Accumulated deficit
    (19,357,113 )     (17,985,830 )
Total Petro Resources Corp. shareholders' equity
    32,514,846       33,693,354  
Minority interest     1,266,290       1,384,900   
Total Equity     33,781,136       35,078,263   
Total Liabilities and Shareholders' Equity
  $  59,800,799     $  61,664,868  
 
 
The accompanying notes are an integral part of these financial statements
1
 
PETRO RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
             
             
   
Three Months Ended
 
   
March 31,
 
   
2009
   
2008
 
Revenue
           
Oil and gas sales
  $ 1,817,036     $ 3,058,001  
Other income
    100,000       100,000  
      1,917,036       3,158,001  
Expenses
               
Lease operating expenses
    1,244,562       1,222,398  
Exploration
    94,475       572,510  
Depreciation, depletion and accretion
    1,307,527       525,172  
General and administrative
    746,613       1,293,443  
                 
Total expenses
    3,393,177       3,613,523  
                 
Loss from operations
    (1,476,141 )     (455,522 )
                 
Other income and (expense)
               
Interest income
    601       75,855  
Interest expense
    (570,677 )     (514,961 )
Gain (loss) on derivative contracts
    556,315       (685,594 )
                 
Net loss
    (1,489,902 )     (1,580,222 )
                 
Less:  Net loss attributable to the minority interest
    118,619       126,825  
                 
Net loss attributable to Petro Resources Corp.
    (1,371,283 )     (1,453,397 )
                 
Dividend on Series A Convertible Preferred
    -       (180,808 )
                 
Net loss attibutable to Petro Resources Corp. common stockholders
  $ (1,371,283 )   $ (1,634,205 )
                 
Earnings per common share
               
Basic and diluted
  $ (0.04 )   $ (0.04 )
                 
Weighted average number of common shares outstanding
               
Basic and diluted
    36,778,172       36,652,831  
 
 
The accompanying notes are an integral part of these financial statements.
2
 
 
 
PETRO RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
             
   
Three Months Ended
 
   
March 31,
 
   
2009
   
2008
 
             
Cash flows from operating activities
           
Net loss
  $ (1,371,283 )   $  (1,453,397 )
Adjustments to reconcile net income to net cash
               
(used in) provided by operating activities:
               
Minority interest
    (118,619 )     (126,826 )
Depletion, depreciation, and accretion
    1,307,527       525,172  
Amortization included in interest expense
    102,902       365,703  
Dry hole costs
    30,339       465,439  
Issuance of common stock and stock options for services
    192,775       594,635  
Unrealized loss on derivative contracts
    498,417       208,109  
Changes in operating assets and liabilities:
               
Accounts receivable and accrued revenue
    (153,140 )     (432,586 )
Prepaid expenses
    61,885       25,519  
Accounts payable
    11,680       (513,089 )
Accrued expenses
    (9,846 )     109,553  
Net cash provided by (used in) operating activities
    552,637       (231,768 )
                 
Cash flows from investing activities
               
Capital expenditures
    (4,499,467 )     (1,928,169 )
Net cash used in investing activities
    (4,499,467 )     (1,928,169 )
                 
Cash flows from financing activities
               
Proceeds from loan
    -       2,268,575  
Principal payment on loan
    (19,527 )     (778,150 )
Net cash provided by (used in) financing activities
    (19,527 )     1,490,425  
                 
Net (decrease) in cash
    (3,966,357 )     (669,512 )
Cash, beginning of period
    6,120,402       15,399,547  
                 
Cash, end of period
  $  2,154,045     $  14,730,035  
                 
Supplemental disclosure of cash flow information
               
Cash paid for interest
  $  467,775     $  395,682  
Cash paid for federal income taxes
    -       -  
                 
Non-cash transactions
               
Preferred stock dividend paid in preferred shares
  $  -     $  180,808  
Capitalized interest in oil and gas properties
  $  -     $  850,738  
Property and equipment included in accounts payable
  $  606,339     $  317,710  
 
 
The accompanying notes are an integral part of these financial statements
 
3
 

PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
 
Note 1—Basis of Presentation

The accompanying unaudited interim financial statements of Petro Resources Corporation (the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America and rules of the Securities and Exchange Commission, and should be read in conjunction with the audited financial statements and notes thereto contained in Petro Resource’s annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 31, 2009. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited consolidated financial statements as reported in the 2008 annual report on Form 10-K have been omitted.

Certain prior period balances have been reclassified to conform to the current period presentation. 

Note 2 - Fair Value of Financial Instruments

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, Fair Value measurements, for all financial instruments. SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

●
Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets
   
●
Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable
   
●
Level 3 — Significant inputs to the valuation model are unobservable

The following describes the valuation methodologies we use to measure financial instruments at fair value. 

Derivative Instruments

At March 31, 2009 we had commodity derivative financial instruments in place that do not qualify for hedge accounting under SFAS 133. Therefore, the changes in fair value subsequent to the initial measurement are recorded in income. Although our derivative instruments are valued using public indexes, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, our derivative liabilities have been classified as Level 2.

The follow table provides a summary of the fair value of our derivative liabilities measured on a recurring basis under SFAS 157:

   
Fair value measurements on a recurring basis
March 31, 2009
 
   
Level 1
   
Level 2
   
Level 3
 
Assets
                       
      Commodity derivatives
 
$
-
   
$
6,785,411
   
$
-
 
 
Note 3 —Derivative Financial Instruments

We entered into commodity derivative financial instruments intended to hedge our exposure to market fluctuations of oil prices. As of March 31, 2009, we had commodity swaps for the following oil volumes:
 
4
 
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
 
     
Barrels per
quarter
   
Barrels per
day
   
Price per
barrel
   
                             
 
2009
                         
 
Second quarter
   
8,325
     
91
   
$
72.62
   
 
Third quarter
   
8,400
     
91
   
$
72.55
   
 
Fourth quarter
   
8,400
     
91
   
$
72.55
   
                             
 
2010
                         
 
First quarter
   
14,825
     
165
   
$
93.50
   
 
Second quarter
   
15,000
     
165
   
$
105.45
   
 
Third quarter
   
15,000
     
163
   
$
105.45
   
 
Fourth quarter
   
15,000
     
163
   
$
105.45
   
                             
 
2011
                         
 
First quarter
   
13,500
     
150
   
$
105.45
   
 
Second quarter
   
13,500
     
148
   
$
105.45
   
 
Third quarter
   
13,500
     
147
   
$
105.45
   
 
Fourth quarter
   
13,500
     
147
   
$
105.45
   

As of March 31, 2009, the fair value of the above commodity swaps $4,718,673.
 
On June 5, 2008, the Company purchased a floor at $110 per barrel for 100 bbls per day for the calendar year 2009 for a price of $363,175. As of  March 31, 2009 the fair value of the floor was $1,514,305.

On October 6, 2008, the Company purchased a floor at $7.75 per MCF for 20,000 MCF per month for the calendar year 2009 for a price of $200,400. As of  March 31, 2009 the fair value of the floor was $552,433.

During quarter ended March 31, 2009, we incurred a gain of $556,315 related to derivative contracts. Included in this gain was $1,054,732 of realized gains related to settled contracts, and $498,417 of unrealized losses related to unsettled contracts. Unrealized gain and losses are based on the changes in the fair value of derivative instruments covering positions beyond March 31, 2009.
  
Note 4 – Minority Interest

In connection with the Williston Basin acquisition, we entered into equity participation agreements with the lenders pursuant to which we agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which at this time is 100% owned by Petro Resources. The equity participation agreements were valued at $3,401,655 and accounted for as a minority interest in PRC Williston.

     
Minority
Interest
   
 
Minority interest at December 31, 2008
 
$
1,384,909
   
 
Loss to minority interest
   
(118,619
)
 
 
Minority interest at March 31, 2009
 
$
1,266,290
   
 
Note 5 —Share Based Compensation

Petro Resources recognized stock compensation expense of $192,775 and $594,635 for the three months ended March 31, 2009 and 2008 respectively.
 
5
 
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
 
A summary of option activity for the three months ended March 31, 2009 is presented below:

   
Shares
 
Weighted-
Average
Exercise Price
   
               
 
Outstanding at December 31, 2008
1,035,000
 
$
3.11
   
 
Granted
-
   
-
   
 
Exercised, forfeited, or expired
       -
   
       -
   
 
Outstanding at March 31, 2009
1,035,000
   
3.11
   
               
 
Exercisable at December 31, 2008
752,500
   
     3.56
   
 
Exercisable at March 31, 2009
830,000
 
$
  3.37
   
 
A summary of Petro Resources non-vested options as of  March 31, 2009 is presented below.
 
 
Non-vested Options
 
Shares
   
 
Non-vested at December 31, 2008
   
282,500
   
 
Granted
   
-
   
 
Vested
   
(77,500
)
 
 
Forfeited
   
-
   
 
Non-vested at March 31, 2009
   
205,000
   
 
Total unrecognized compensation cost related to non-vested options granted under the Plan was $158,739 and $1,381,405 as of March 31, 2009 and 2008 respectively. The cost at March 31, 2009 is expected to be recognized over a weighted-average period of 1.6 years. The aggregate intrinsic value for options was $0; and the weighted average remaining contract life was 2.64 years.

As allowed by SFAS 123(R), the Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options and stock settled stock appreciation rights.
 
6
 
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
 
The assumptions used in the fair value method calculation for the three months ended March 31, 2009 and 2008 are disclosed in the following table:
 
     
Three Months Ended
 March 31,
   
     
2009
   
2008 (1)
   
                 
 
Weighted average value per option granted during the period (2)
  $ N/A     $ 1.36    
 
Assumptions (3) :
                 
 
Stock price volatility
    N/A       104-105 %  
 
Risk free rate of return
    N/A       1.87-2.69 %  
                     
 
Expected term
    N/A    
3.25 years
   

(1)
Our estimated future forfeiture rate is zero.
(2)
Calculated using the Black-Scholes fair value based method.
(3)
We do not pay dividends on our common stock.
 
 
A summary of warrant activity for the three months ended March 31, 2009 is presented below:
 
   
Shares
 
Weighted-
Average
Exercise Price
   
               
 
Outstanding at December 31, 2008
6,838,962
 
$
2.15
   
 
Granted
-
   
-
   
 
Exercised, forfeited, or expired
       -
   
       -
   
 
Outstanding at March 31, 2009
6,838,962
 
$
2.15
   
               
 
Exercisable at December 31, 2008
6,838,962
 
$
     2.15
   
 
Exercisable at March 31, 2009
6,838,962
 
$
2.15
   
 
The aggregate intrinsic value for warrants was $0; and the weighted average remaining contract life was 1.67 years.
 
Note 6 – Subsequent events
 
On April 10, 2009, the Company signed a promissory note with a finance company for $217,336 to finance its various insurance policies. The interest rate on the note is 4.75% with payments of $22,210 per month beginning May 1, 2009 and the final payment due February 1, 2009. The note is secured by the insurance policies.

On April 16, 2009, the Company borrowed an additional $1,000,000 against its line of credit.
 
7
 
ITEM 2.       MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Terms located at the end of this Item

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 our officers or other representatives 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. 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. Our forward-looking statements are based upon assumptions that are sometimes based upon estimates, data, communications and other information from operators, government agencies and other sources that may be subject to revision. Except as required by law, we do not undertake any obligation to update or keep current either (i) any forward-looking statement to reflect events or circumstances arising after the date of such statement, or (ii) the important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or which are reflected from time to time in any forward-looking statement.

There are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, are included in our filings with the SEC, including the risk factors set forth of our annual report on Form 10-K for our 2008 fiscal year filed with the SEC on March 31, 2009.

General

Petro Resources Corporation is an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the United States. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.

We have been successful in creating and expanding a balanced portfolio consisting of producing properties and prospects that are geologically and geographically diverse, including producing properties, secondary enhanced oil recovery projects, and exploration prospects. This diversity provides projects with varied payout periods, helping us to remain competitive in volatile markets. We target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Texas, Louisiana, North Dakota, New Mexico and Kentucky. We currently own interests in approximately 286,282 gross (50,611 net) leasehold acres, of which 261,147 gross (43,281 net) acres are classified as undeveloped acreage.
 
8
 
In July 2005, we acquired our initial interest in drilling prospects and commenced drilling activities in November 2005.  In December 2005, we commenced production operations from our first oil and gas prospects and received our first revenues from oil and gas production in February 2006.  In the first quarter of 2007, we acquired oil and gas producing assets in the Williston Basin area of North Dakota. In the third quarter of 2007, we increased our oil and gas producing assets with the addition of acreage in the Permian Basin located in West Texas. Subsequently, in 2008, we participated in new prospects located in southwest Louisiana as well as east Texas.   As of March 30, 2009, we held interests in approximately 238 producing wells in Texas, Louisiana and North Dakota.  Our current drilling inventory includes prospects located in Texas, Louisiana, New Mexico, North Dakota and Kentucky.

We recognize the value of hedging oil and gas production through both derivative and physical contracts to help stabilize cash flow. During the second and third quarters of 2008, we entered into three separate hedging agreements. In June 2008, we purchased put options for crude oil at a price of $110 per bbl for 100 bbls per day of production during 2009. The cost of these crude oil put options was $363,175. We also entered into swap agreements in September covering 207,400 barrels of crude oil at a price of $105 per bbl for the period of October 2008 to December 2011. We incurred no cost in entering these swap agreements. In addition to crude oil hedges, we also hedged natural gas production in October 2008, whereby we purchased natural gas put options at a strike price of $7.75 per mcf for 658 mcf per day (240,000 total mcf) of production during 2009. The cost of these natural gas put options was $200,400.

As of December 31, 2008, our total proved reserves were 3,118 mboe net of production, a gain of 401 mboe from year end 2007 of 2,716 mboe net of production. This gain in proved reserves was the result of gains of 932 mboe from prospect areas in Texas and Louisiana offset by a reduction in North Dakota proved reserves of 531 mboe. The decrease of reserves in North Dakota was precipitated by a lower year end price causing a decrease to the estimated life of the reserves. The total 2008 year end proved reserves is comprised of 2,409 mbbls of crude oil and NGLs and 709 mboe of natural gas.
 
Our executive offices are located at 777 Post Oak Blvd., Suite 910, Houston, Texas 77056, and our telephone number is (832) 369-6986.  Our web site is www.petroresourcescorp.com .  Additional information which may be obtained through our web site does not constitute part of this quarterly report on Form 10-Q.  A copy of this quarterly report on Form 10-Q is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549.  Information on the operation of the SEC’s Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.  The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.

Results of Operations

For the three months ended March 31, 2009 compared to the three months ended March 31, 2008

The Company’s net production for the quarter ended March 31, 2009 included 33,369 barrels of oil, 121,874 mcf of natural gas, and 12,100 barrels of natural gas liquids for a barrel-equivalent total of 65,781 boe compared to 30,179 barrels of oil, 42,275 mcf of natural gas, and 4,035 barrels of natural gas liquids for a barrel-equivalent total of 41,260 boe for the quarter ended March 31, 2008.

For the quarter ended March 31, 2009, the average daily production was approximately 730 boe per day compared to average daily production of 461 boe per day for the quarter ended March 31, 2008.

9
 
The Company realized prices for the quarter ended March 31, 2009 were $33.84 per barrel of oil, $3.24 per mcf of natural gas, and $24.25 per barrel of natural gas liquids compared to $85.93 per barrel of oil, $5.59 per mcf of natural gas, and $48.06 per barrel of natural gas liquids for the comparable prior year period.

Revenue for the quarter ended March 31, 2009 consisted $1,817,036 of oil and gas sales compared to oil and gas sales of $3,058,001 for the quarter ended March 31, 2008. The decrease in revenue from oil and gas sales was due primarily to significantly lower commodity prices.

Lease operating expenses for the quarter ended March 31, 2009 totaled $1,244,562 compared to lease operating expenses of $1,222,398 for the prior year comparable period. While lease operating expenses have not come off as quickly as the drop in commodity prices in the initial months of 2009, the industry has begun to see a retreat in these costs reflecting the current market conditions.

Exploration costs for the quarter ended March 31, 2009 were $94,475 compared to $572,510 for the quarter ended March 31, 2008. Exploration costs represent our drilling costs associated with dry holes and the carrying costs of properties. The decrease in exploration costs represents our successful drilling efforts in the Cinco Terry Prospect in Crockett County, Texas as well as the Surprise Prospect in Nacogdoches County, Texas.

We incurred no expenses related to the impairment of oil and gas properties in the quarters ended March 31, 2009 or 2008. Impairment expenses represent the write-down of previously capitalized expenses for productive wells. We take an impairment charge for a productive well when there is an indication that we may not receive production payments equal to the net capitalized costs. No wells needed to be written down in either quarter.

Our expenses for depreciation, depletion, and accretion for the quarter ended March 31, 2009 totaled $1,307,527 compared to $525,172 for the same period in the prior year. This was due to our increased production as a result of the Cinco Terry Field drilling program, the Surprise prospect wells coming online as well as increased depletion rates.

General and administrative expenses for the quarter ended March 31, 2009 totaled $746,613 compared to general and administrative expenses of $1,293,443 for the prior year period. General and administrative expenses for the quarters ended March 31, 2009 and March 31, 2008 included expenses of $192,775 and $594,365, respectively, for outstanding common stock shares and common stock options granted under our Stock Incentive Plan. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the quarters ended March 31, 2009 and March 31, 2008 were $553,838 and $699,078, respectively. The decrease in general and administrative expenses (other than expenses for options and common shares) between reporting periods was due to the decrease in legal and professional services and a decrease in employee costs because at this time, no bonuses have been paid this year.

We incurred a net loss from operations of $1,476,141 for the quarter ended March 31, 2009 compared to a loss from operations of $455,522 during the same period in the prior year.   The increase in net loss occurred due to the decline in commodity prices leading to reduced revenue in addition to slowly retreating lease operating expenses.

During the quarter ended March 31, 2009, interest expense totaled $570,677, compared to $514,961 for the quarter ended March 31, 2008.  The increase in interest expense was principally due to decreased capitalization of interest.

10
 
Beginning in March 2007, we entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices.  During the quarter ended March 31, 2009, we incurred a gain on derivative contracts of $556,315 compared to a loss of $685,594 for the comparable period in 2008. Our gain on derivative contracts include both $1,054,732 in gains on the actual settlement of certain derivative financial instruments during quarter ended March 31, 2009 and the unrealized loss of $498,417 based on the changes in the fair value of derivative instruments covering positions beyond March 31, 2009.

We incurred a net loss attributable to common shareholders of $1,371,283 ($.04 per share) during the quarter ended March 31, 2009, compared to a net loss of $1,634,205 ($.04 per share) to common shareholders for the same period in 2008.  The  decrease in net loss was primarily the result of an gain on derivative contracts.

Plan of Operations

Our plan of operations for the next twelve months is to continue further exploration and development of oil and natural gas prospects that we currently own; concentrating on those with the lowest development and lifting costs. Consistent with that is our gradual structuring and staffing of our company toward becoming an operator of select properties in Texas and Louisiana. By becoming an operator, we will have more control over drilling and developmental decisions and will broaden the spectrum of exploration prospects we can consider for participation.  As an operator we should reduce overall finding costs and in the future we may start to generate exploration prospects.

The continued development of our properties and prospects and the pursuit of fresh opportunities require that we maintain access to adequate levels of capital.   We will strive for an optimal balance between our property portfolio and our capital structuring that will allow for growth and to the maximum benefit of our shareholders.   The decisions around the balancing of capital needs and property holdings will be a challenge to us as well as all companies in the entire energy industry during this time of lowered commodity prices and an increasing complex global economic picture.  As a function of balancing properties and capital, we may decide to monetize certain properties to reduce debt or to allow us to acquire interest in new prospects or producing properties that may be better suited to the current economic and energy industry environment.

The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties.  As explained under “Financial Condition and Liquidity” below, based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2009.  However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2009.  We will seek additional working capital through the sale of our securities and we will endeavor to obtain additional capital through bank lines of credit and project financing.  However, as described further below, under the terms of our existing credit facilities, we are prohibited from incurring any additional debt from third parties.  Our ability to obtain additional working capital through new bank lines of credit and project financing may be subject to the repayment of outstanding sums drawn from the $65.0 million credit facilities.

We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental, investor relations, audit and tax services.  We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management.  

11

Financial Condition and Liquidity

As of the date of this report, we estimate our capital budget for fiscal 2009 to be approximately $7.3 million, including:

 
·
Up to $3.4 million to be deployed for drilling in Cinco Terry.
 
 
·
Up to $1.2 million towards operations in the Surprise Prospect.
 
 
·
Up to $1.5 million to be used in connection with our interest in the East Chalkley Prospect and Leblanc Prospect.
 
 
·
 
Up to $495,000 to maintain secondary recovery efforts in North Dakota.
 
·
Approximately $700,000 to be used in connection with other prospect areas.

As of March 31, 2009, we had total assets of $59,800,799 and working capital of $3,450,745.  In addition, we have $65.0 million in credit facilities, of which $21.5 million is outstanding as of March 31, 2009 and $5.5 million is available for additional borrowing for purposes of financing our commitments towards the drilling and development of our oil and gas properties.  Based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2009.  However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2009.  
 
We may seek to obtain additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing.  However, other than our existing credit facilities, we have no agreements or understandings with any third parties at this time for our receipt of additional working capital and we have no history of generating significant cash from oil and gas operations.  Further, as described further below, under the terms of our existing  credit facilities, we are prohibited from incurring any additional debt from third parties.  Our ability to obtain additional working capital through bank lines of credit and project financing may be subject to the repayment of our credit facilities.  Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms.  If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price may be materially adversely affected.

CIT Credit Facility

On September 9, 2008 and amended on March 19, 2009, we entered into a $50.0 million Credit Agreement (the "Credit Agreement") with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders, and a $15.0 million Second Lien Term Loan Agreement (the "Second Lien Term Loan Agreement") with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders. All term loans available under the Second Lien Term Loan facility were advanced to us on September 9, 2008 and were used to retire our previously existing credit facility arranged by Petrobridge Investment Management, LLC.
 
12
 
The Credit Agreement provides for a $50.0 million first lien revolving credit facility, with an initial borrowing base availability of $17.0 million. The first lien facility may be used for loans and, subject to a $500,000 sublimit, letters of credit. Borrowings under the Credit Agreement may be used to provide working capital for exploration and production purposes, to refinance existing debt, and for general corporate purposes. The maturity date of the Credit Agreement is September 9, 2011.
 
Borrowings under the Credit Agreement bear interest, at our option, at either a fluctuating base rate or a rate equal to LIBOR plus, in each case, a margin determined based on our utilization of the borrowing base. The Credit Agreement also requires us to satisfy certain financial covenants, including maintaining (A) a ratio of EBITDAX to Interest Expense (as each term is defined in the Credit Agreement) of not less than 2.5:1.0; (B) a ratio of Net Debt (as such term is defined in the Credit Agreement) to EBITDAX of not more than (y) 4.5:1.0 for the fiscal quarters ending December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, and (z) 3.5:1.0 for each fiscal quarter ending thereafter; and (C) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0:1.0. We are also required to enter into certain swap agreements pursuant to the terms of the Credit Agreement.
 
The Second Lien Term Loan Agreement provides for a $15 million second lien term loan facility. As noted above, all term loans available under the second lien term loan facility were advanced to us on September 9, 2008 and were also used to retire our previously existing credit facility arranged by Petrobridge Investment Management, LLC. The maturity date of the Second Lien Term Loan Agreement is September 9, 2012. Under certain circumstances, we are permitted to repay the term loans prior to the maturity date; however, any payments made on or prior to September 9, 2009 are subject to a prepayment penalty equal to 2% of the amount prepaid, and any payments made after September 9, 2009 but on or before September 9, 2010 are subject to a prepayment penalty equal to 1% of the amount prepaid.
 
Borrowings under the Second Lien Term Loan Agreement bear interest, at our option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR plus 7.50% per annum. The Second Lien Term Loan Agreement also requires us to satisfy certain financial covenants, including maintaining (1) a ratio of Total Reserve Value to Debt (as each term is defined in the Second Lien Term Loan Agreement) of not less than 1.75:1.0; and (2) a ratio of Net Debt to EBITDAX (as each term is defined in the Second Lien Term Loan Agreement) of not more than (a) 4.5:1.0 for the fiscal quarters ending December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, and (b) 4.0:1.0 for each fiscal quarter ending thereafter.
 
If an event of default occurs and is continuing under either the Credit Agreement or the Second Lien Term Loan Agreement, the lenders may increase the interest rate then in effect by an additional 2% per annum. The Credit Agreement and the Second Lien Term Loan Agreement contain covenants that, among others things, restrict our ability to, with certain exceptions: (i) incur indebtedness; (ii) grant liens; (iii) acquire other companies or assets; (iv) dispose of all or substantially all of our assets or enter into mergers, consolidations or similar transactions; (v) make restricted payments; (vi) enter into transactions with affiliates; and (vii) make capital expenditures.
 
PRC Williston LLC, our wholly-owned subsidiary, has guaranteed the performance of all of our obligations under the Credit Agreement, the Second Lien Term Loan Agreement and related agreements pursuant to a Guaranty and Collateral Agreement and a Second Lien Guaranty and Collateral Agreement each dated as of September 9, 2008. Subject to certain permitted liens, our obligations have been secured by the grant of a first priority lien on no less than 80% of the value of our and PRC Williston's existing and to-be-acquired oil and gas properties and the grant of a first priority security interest in related personal property of ours and PRC Williston. We also granted a first priority security interest in our ownership interest in PRC Williston, subject only to certain permitted liens.
 
13
 
The Credit Agreement was amended on March 19, 2009 because we were unable to comply with the interest and debt coverage covenants under the terms of the original Credit Agreement and Second Lien Term Loan Agreement for the fiscal quarter ended December 31, 2008. Pursuant to the amendments, the administrative agent and the lenders have agreed to waive these defaults. In connection with the semi-annual review of our borrowing base, lower commodity prices have resulted in our borrowing base for the Credit Agreement being reduced from $17.0 million to $12.0 million. The terms of the Credit Agreement and Second Lien Term Loan Agreement as amended are as follows.
 
Under the Credit Agreement, the Company must have (A) a ratio of EBITDAX to Interest Expense (as each term is defined in the Credit Agreement) of not less than 2.0:1.0 for the first and second fiscal quarters of 2009, 2.25:1.0 for the third and fourth fiscal quarters of 2009, and 2.5:1.0 for each fiscal quarter thereafter; (B) a ratio of Net Debt (as such term is defined in the Credit Agreement) to EBITDAX of not more than 6.5:1.0 for the fiscal quarters of 2009, 6.0:1.0 for the fiscal quarters of 2010, and 5.0:1 for each fiscal quarter thereafter; (C) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0:1.0 for each fiscal quarter; and (D) a ratio of First Lien debt to EBITDAX of not more than 2.75:1.0 for each fiscal quarter. Borrowings under the Credit Agreement bear interest, at our option, at either a fluctuating base rate or a rate equal to LIBOR (with a LIBOR floor of 2.50%) plus, in each case, a margin determined based on our utilization of the borrowing base. The amendment includes an increase in the margin of 50 basis points.
 
Under the Second Lien Term Loan Agreement, the Company must have (A) a ratio of Total Reserve Value to Debt (as each term is defined in the Second Lien Term Loan Agreement) of not less than 1.75:1.0; and (B) a ratio of Net Debt to EBITDAX (as each term is defined in the Second Lien Term Loan Agreement) of not more than 6.5:1.0 for the fiscal quarters of 2009 and 2010 and 5.5:1 for the fiscal quarters of 2011 each fiscal quarter ending thereafter. Borrowings under the Second Lien Term Loan Agreement bear interest, at our option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR (with a LIBOR floor of 2.50%) plus 7.50% per annum.
 
As of March 31, 2009, we have drawn $21.5 million, of which $15.0 million was drawn on the Second Lien Term Loan Agreement and $6.5 million was drawn on the Credit Agreement. Subject to the above-described conditions, we are permitted to use the remaining available funds under the Credit Agreement to finance our capital program and fund general corporate purposes.  As of March 31, 2009, $5.5 million is available for additional borrowing under the credit facilities.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet financing arrangements. 
 
Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.
 
bbl . Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

bcf . Billion cubic feet of natural gas.

boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
14
 
boe/d . boe per day.

Completion . The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate . Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.

Development well . A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling locations . Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

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

Exploratory well . A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
 
Field . An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation . An identifiable layer of rocks named after its geographical location and dominant rock type.

Lease . A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold . Mineral rights leased in a certain area to form a project area.

mbbls . Thousand barrels of crude oil or other liquid hydrocarbons.

mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids

mcf. Thousand cubic feet of natural gas.

mcfe . Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbbls . Million barrels of crude oil or other liquid hydrocarbons.

mmboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbtu . Million British Thermal Units.

mmcf . Million cubic feet of natural gas.

15
 
Net acres, net wells, or net reserves . The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.

ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.

Overriding royalty interest . Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

Plugging and abandonment . Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (PV-10 ). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such a general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

PV-10 . Pre–tax present value of estimated future net revenues discounted at 10%.

Production . Natural resources, such as oil or gas, taken out of the ground.

Proved oil and gas reserves . Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
(i)  
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii)  
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)  
Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilscnite , and other such sources.
 
16
 
Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves . Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves he attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
 
Probable Reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.
 
Possible Reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

Productive well . A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Project . A targeted development area where it is probable that commercial gas can be produced from new wells.

Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Recompletion . The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves . Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.

17
 
Reservoir . A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Secondary Recovery . A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

Shut-in . A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.

Standardized measure . The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful . A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.

Undeveloped acreage . Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Water flood . A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.

Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

ITEM 3.       QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .

Not applicable.
 
ITEM 4(T).       CONTROLS AND PROCEDURES
 
Our chief executive officer and chief financial officer have reviewed and continue to evaluate the effectiveness of our controls and procedures over financial reporting and disclosure (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this quarterly report. The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating our controls and procedures over financial reporting and disclosure, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and our management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

18
 
An evaluation was performed under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2009. Based on that evaluation, our management, including our chief executive officer and chief financial officer, has concluded that our disclosure controls and procedures were effective as of March 31, 2009.

Changes in Internal Control . We made no changes to our internal control over financial reporting during the quarter ended March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


 
 
19

PART II.  OTHER INFORMATION
 
 
ITEM 6.      EXHIBITS
 
Exhibit
No.
Description
Method of Filing
10.1
First Amendment to Credit Agreement dated March 19, 2009 among Petro Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto
(1)
 
10.2
First Amendment to Second Lien Term Loan Agreement dated March 19, 2009 among Petro Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto
(1)
 
31.1
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
Filed herewith
     
31.2
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
Filed herewith
     
32
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350
Filed herewith
 
(1)    Incorporated by reference from Petro Resources Corporation’s annual report on Form 10-K filed on March 31, 2009.
 
 
 
20

SIGNATURES
 
In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereto duly authorized.
 
   
PETRO RESOURCES CORPORATION
 
 
       
Date: May 11, 2009
 
/ s/  Wayne P. Hall
 
   
Wayne P. Hall,
 
   
Chief Executive Officer
 
 
       
Date: May 11, 2009
 
/s/  Harry Lee Stout
 
   
Harry Lee Stout,
 
   
Chief Financial Officer
 
 
 
 
21
Grafico Azioni Proterion (AMEX:PRC)
Storico
Da Ott 2024 a Nov 2024 Clicca qui per i Grafici di Proterion
Grafico Azioni Proterion (AMEX:PRC)
Storico
Da Nov 2023 a Nov 2024 Clicca qui per i Grafici di Proterion