UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

August 5, 2010

Date of Report (Date of earliest event reported)

Radiant Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

Nevada

(State or other jurisdiction)

000-24688

(Commission File Number)

27-2425368

(IRS Employer Identification No.)

9700 Richmond Ave., Suite 124, Houston, Texas 77042

(Address of principal executive offices)

(832) 242-6000

Registrant’s telephone number, including area code

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[  ]		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[  ]		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[  ]		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[  ]		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 FR 240.13e-4(c))

 

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Table of Contents

Item 1.01

Entry into a Material Definitive Agreement

4

Item 2.01

Completion of Acquisition or Disposition of Assets

4

DESCRIPTION OF OUR BUSINESS

6

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATION

18

RISK FACTORS

22

MANAGEMENT AND EXECUTIVE COMPENSATION

34

STOCK OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND

MANAGEMENT AND RELATED STOCKHOLDER MATTERS

37

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

38

LEGAL PROCEEDINGS

39

MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S

COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

40

RECENT SALES OF UNREGISTERED SECURITIES

40

DESCRIPTION OF SECURITIES

41

INDEMNIFICATION OF DIRECTORS AND OFFICERS

42

WHERE YOU CAN OBTAIN ADDITIONAL INFORMATION

42

Item 3.02

Unregistered Sales of Equity Securities

42

Item 3.03

Material Modification to Rights of Security Holders

42

Item 5.01

Changes in Control of Registrant

43

Item 5.02

Departure of Directors or Principal Officers; Election of Directors; Appointment of Principal Officers

43

Item 5.06

Change in Shell Company Status

43

Item 9.01

Financial Statements and Exhibits

43

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Our business, financial condition, results of operations, cash flows and prospects, and the prevailing market price and performance of our common stock, may be adversely affected by a number of factors.  Certain statements and information set forth in this Current Report on Form 8-K, as well as other written or oral statements made from time to time by us or by our authorized executive officers on our behalf, constitute “forward-looking statements” within the meaning of the Federal Private Securities Litigation Reform Act of 1995.  We intend for our forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995, and we set forth this statement and the risk factors in this Current Report on Form 8-K in order to comply with such safe harbor provisions.  You should note that our forward-looking statements speak only as of the date of this Current Report on Form 8-K or when made and we undertake no duty or obligation to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise.  Although we believe that the expectations, plans, intentions and projections reflected in our forward-looking statements are reasonable, such statements are subject to known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements.  The risks, uncertainties and other factors that our stockholders and prospective investors should consider are included under the heading “Risk Factors”.

EXPLANATORY NOTE

This Current Report on Form 8-K is being filed in connection with a series of transactions consummated by, and certain related events and actions taken by, Radiant Oil & Gas, Inc.

This Current Report responds to the following items on Form 8-K:

Item 1.01

Entry into a Material Definitive Agreement

Item 2.01

Completion of Acquisition or Disposition of Assets

Item 3.02

Unregistered Sales of Equity Securities

Item 3.03

Material Modification to Rights of Security Holders

Item 5.01

Changes in Control of Registrant

Item 5.02

Departure of Directors or Principal Officers; Election of Directors; Appointment of Principal Officers

Item 9.01

Financial Statements and Exhibits

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Item 1.01

Entry into a Material Definitive Agreement

As used in this Current Report on Form 8-K, all references to the “Company”, “Radiant”, “we”, “our”, and “us” or similar terms refer to Radiant Oil & Gas, Inc., including its predecessors and subsidiaries. Information about the Company and the principal terms of the Reorganization are set forth below.

On July 23, 2010, the Company entered into an exchange agreement (that was amended effective July 31, 2010, the “Reorganization Agreement”) with Jurasin Oil & Gas, Inc., a Louisiana corporation (“Jurasin”), John M. Jurasin, the majority shareholder of Jurasin (the “Majority Shareholder”), and certain other shareholders of Jurasin (collectively with the Majority Shareholder, the “Jurasin Shareholders”), pursuant to which we acquired 100% of the issued and outstanding shares of Jurasin common stock held by the Jurasin Shareholders in consideration for the issuance of up to 12,000,000 shares of our common stock (the “Reorganization”).  As a result of the Reorganization, Jurasin became a wholly-owned subsidiary of the Company.  The transaction was accounted for as a reverse merger and recapitalization of Radiant (the legal acquirer), with Jurasin considered the accounting acquirer.  There was no goodwill or other intangible assets recorded in connection with the acquisition.

The description of the transactions contemplated by the Reorganization Agreement and related agreements in this Form 8-K does not purport to be complete and is qualified in its entirety by reference to the full text of the exhibits filed herewith and incorporated herein by reference.

Item 2.01

Completion of Acquisition or Disposition of Assets

Reorganization

As described in Item 1.01 of this Current Report on Form 8-K, on July 23, 2010, the Company entered into a Reorganization Agreement by and among the Company, Jurasin, and the Jurasin Shareholders pursuant to which we agreed to acquire 100% of the issued and outstanding shares of Jurasin common stock held by the Jurasin Shareholders.  At the closing of the Reorganization on August 5, 2010 (the “Closing”), at which time Jurasin became a wholly-owned subsidiary of the Company, we issued 10,000,000 shares of our common stock to the Jurasin Shareholders and up to an additional 2,000,000 shares upon satisfaction of certain vesting requirements as follows:

Shareholder		No. of Radiant Shares Issued to Jurasin Shareholders at Closing		No. of Radiant Shares Issued to Jurasin  Shareholders upon Satisfaction of Certain Vesting Requirements (1)
John M. Jurasin		9,013,535		1,802,708
Barry J. Rava		200,000		40,000
Arthur Thomas McCarroll		150,000		30,000
Timothy N. McCauley		428,131		85,626
Robert M. Gray		150,000		30,000
Allen W. Hobbs		41,667		8,333
Melissa A. Wright		16,667		3,333
		10,000,000		2,000,000

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(1)  Upon the satisfaction of any four of the following conditions, Radiant shall issue to the Jurasin Shareholders, on a pro-rata basis, an aggregate of 500,000 shares (not to exceed 2,000,000 shares) for each condition satisfied:

o

Garnet – Nominate the southern (St. Mary Parish School Board) acreage for lease

o

Coral – Permit well

o

Amber – Re-acquire State seismic permit covering open acreage in Bayou Teche, Grand Lake and Attakapas Wildlife Management Areas

o

Amber – Re-acquire seismic permit on 1,000 net acres

o

Amber – Re-acquire seismic permit on additional 1,000 net acres

o

Amber – Extend Apache Seismic Permit and Sub-Lease from September 2010

o

Amber – Execute Seismic Services Contract for shooting of 3-D survey

At the Closing of the Reorganization, the Company also issued a promissory note in favor of the Majority Shareholder in the original principal amount of $884,000, which accrues interest at the rate of 4% per annum and matures upon the earlier of (i) May 31, 2013 or (ii) the date on which the Company closes any equity financing in which the Company receives gross proceeds of at least $10,000,000.  Also in connection with the Reorganization, an additional $165,000, which has no formal repayment terms, is also due to Mr. Jurasin.  The note and payable were treated as a deemed dividend to Mr. Jurasin.

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In July 2010, the Company issued 1,086,409 shares of Company common stock to an investor relations consultant for services to be rendered upon completion of the Reorganization.  In August 2010, the Company issued 6,000,000 shares of Company common stock to John Thomas Financial, Inc. in consideration for entering into an investment banking agreement that contemplates raising up to $14,500,000 on a best efforts basis.  In August 2010, the Company issued $600,000 in principal amount of debentures due on the earlier of July 31, 2011 and upon the closing of a $2,000,000 financing (to be partially pre-paid with 30% of the gross proceeds from subsequent financings equaling and exceeding $500,000), and four-year warrants to purchase 600,000 shares of common stock (with piggyback registration rights for the underlying shares of common stock) at a purchase price of $.50 per share (issued as additional consideration for the $600,000 of debentures).

Concurrent with the Closing of the Reorganization, the Company issued 100,000 shares of Company common stock to Mr. Rodriguez pursuant to his director’s agreement.

The securities of the Company issued above were not registered under the Securities Act of 1933 (“Securities Act”), and all shares issued in connection therewith were issued in reliance upon the exemption from registration provided by Section 4(2) under the Securities Act for transactions not involving any public offering.  All such securities constitute “restricted securities” as defined in Rule 144 under the Securities Act of 1933 (the “Act”), and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements. Certificates representing these securities contain a restrictive legend stating the same.

General Changes Resulting from the Reorganization

We intend to carry on the business of Jurasin and we have retained all of Jurasin’s management. We will also relocate our executive offices to 9700 Richmond Avenue, Suite 124, Houston, Texas 77042, and our new phone number is (832) 242-6000.

Changes to the Board of Directors and Executive Officers

Immediately following the completion of the Reorganization, the size of our board of directors was increased from two to four members, and John M. Jurasin and Robert M. Gray were appointed as directors.  The Majority Shareholder has the right to nominate and appoint one additional director, provided that a majority of the existing board members approve.  All of the Company’s directors will hold office until the next annual meeting of the stockholders or until the election and qualification of their successors.  Brian Rodriguez resigned as chief executive officer and Mr. Jurasin was appointed chief executive officer, chief financial officer and chairman of the board.  Additional executive officers have entered into employment agreements with the Company as further described in “-Management and Executive Compensation – Employment Agreements.”  The Company’s officers are elected by the board of directors and serve at the discretion of the board of directors.

Accounting Treatment

While Radiant is the surviving corporation (and Jurasin is the wholly owned subsidiary) for legal purposes, Jurasin is deemed to be the acquirer in the Reorganization for accounting purposes and, consequently, the assets and liabilities and the historical operations that are reflected in the financial statements are those of Jurasin and will be recorded at the historical cost basis of Jurasin. As a result of the Reorganization, there was a change in control of the Company. The Company will continue to be a “smaller reporting company” as defined under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), following the Reorganization.

We consolidate all investments in which we have exclusive control.  The accompanying consolidated financial statements include the accounts of Jurasin and its wholly owned subsidiary, Rampant Lion Energy, LLC (“Rampant Lion”), and Jurasin Oil and Gas Operating Company (“JOGop”), a company under common control.  In accordance with established practice in the oil and gas industry, our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of a limited liability company, Amber Energy, LLC (“Amber”) in which we have an interest.  We own a 51% interest in Amber as of March 31, 2010 and as of August 5, 2010.  

Credit Facility

Concurrent with the Closing of the Reorganization, Jurasin and the Company entered into modifications with respect to certain credit facilities, being the Amber Energy, LLC credit facility (“Amber Credit Facility”) and Rampant Lion Energy, LLC credit facility (“Rampant Lion Credit Facility”, collectively with the Amber Credit Facility, referred to as “Credit Facility”) with Macquarie Bank Ltd. (“MBL”).  The material modifications to the Credit Facility are as follows:

·

The maturity date of the Amber Credit Facility has been extended to March 20, 2011, to correspond to the maturity date of the Rampant Lion Credit Facility;

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·

MBL agreed to convert $1,000,000 of the Credit Facility into shares of common stock at a conversion price of $2.00 per share (subject to downward adjustment depending upon pricing of subsequent Company equity financings) in increments of $500,000 corresponding to principal reductions made by the Company in and after July 2010, provided that upon each such conversion there is (i) no event of default in the Credit Facility and (ii) $500,000 and $1,000,000, respectively, of aggregate mandatory principal payments on the Credit Facility have been paid, of which $100,000 has been paid to date (“Debt Conversion”);

·

MBL agreed to reconvey to Jurasin all interests in real property and membership interests conveyed to MBL’s affiliate Macquarie Americas Corp (“MAC”) in connection with the Amber Credit Facility, provided that all obligations under the Amber Credit Facility, Rampant Lion Credit Facility, and all letters of credit shall have been paid or refinanced prior to March 15, 2011;

·

The Company agreed to make mandatory interest and principal reduction payments to MBL on the Credit Facility on each of August 20, 2010 and September 20, 2010 in the amount of $100,000 and on each of October 20, 2010, November 20, 2010, December 20, 2010, January 20, 2011 and February 20, 2011, in the amount of $250,000. The Company shall also pay to MBL an amount equal to 1/6^th of the gross proceeds raised by the Company through the subsequent equity raised, which amounts shall be credited against the monthly mandatory principal reduction payments; and

·

The Company agreed to guarantee $500,000 of the Credit Facility indebtedness owed by Jurasin to MBL.

·

We cross-collateralized the Amber Credit Facility and the Rampant Lion Credit Facility and each subsidiary guaranteed the obligations under the Credit Facility.

The principal amount and accrued interest owed by Rampant Lion and Amber, on a stand-alone basis, pursuant to the Credit Facility as of August 5, 2010 is approximately $5,791,413.  As discussed in “Item 2-01 Completion of Acquisition or Disposal of Assets – Accounting Treatment”, our consolidated financial statements include the accounts of Rampant Lion and our pro-rata share of assets, liabilities, income and costs and expenses of Amber. The principal amount and accrued interest of our Credit Facility as presented in our consolidated financial statements of March 31, 2010 is $3,812,310 and as of August 5, 2010 is approximately $4,000,000.  

Listing

The Company’s common stock is quoted on the OTCBB, under the symbol “ROGI”. The Company’s common stock is subject to provisions of Section 15(g) and Rule 15g-9 of the Exchange Act, commonly referred to as the “penny stock rule.” Section 15(g) sets forth certain requirements for transactions in penny stocks, and Rule 15g-9(d) incorporates the definition of “penny stock” that is found in Rule 3a51-1 of the Exchange Act. The SEC generally defines “penny stock” to be any equity security that has a market price less than $5.00 per share, subject to certain exceptions. As long as the Company’s common stock is deemed to be a penny stock, trading in the shares will be subject to additional sales practice requirements on broker-dealers who sell penny stocks to persons other than established customers and accredited investors.

Tax Treatment

The Reorganization is intended to constitute a reorganization within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended (the "Code"), or such other tax free reorganization exemptions that may be available under the Code.

DESCRIPTION OF OUR BUSINESS

We intend to engage in the exploration for and production of natural gas and oil through the development of repeatable, low geological risk, infill exploitation of existing proven fields in South Louisiana, the Gulf Coast of Texas, the state waters of Louisiana and Texas, and the federal waters offshore Texas and Louisiana.

We have contracts for gross acres permitted, leased, optioned, farmed-in or under negotiation totaling 44,338 acres.  With the exception of an offshore block east of Corpus Christi, Texas in approximately 140 feet of water, all other projects are located in South Louisiana either directly on land or in water depths not exceeding 10 feet.

Below is a map showing the locations of each major project.

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Amber Energy LLC

Radiant owns 51% membership interest in Amber Energy, LLC (“Amber”).  Amber has certain interests in 2 different project areas that are contiguous, the Ensminger Replacement Well Project and the Amber Project.  

Amber Project.  Amber currently has a Seismic Permit Agreement, dated April 18, 2008, which was granted by Apache Corporation to complete a 3-D survey.  The Seismic Permit Agreement expires on September 1, 2010.  Amber also owns interests in seismic permits and seismic permits with options to lease on additional acreage in the project area.  Amber has an Exploration Agreement, dated October 6, 2008, with Energy XXI Onshore, LLC, which provides that Amber and Energy XXI Onshore, LLC will each have a 50% working interest if this project is developed.  Amber will manage and operate the land and lease functions as well as the actual shooting of the seismic. Amber will also lead the interpretation of the resultant seismic data and generation of prospects within the project. Energy XXI Onshore, LLC will operate the drilling and production of all wells in which it participates.

While at one time Amber held additional permits and permits with options to lease in this area, due to financial difficulty, these permits expired before the seismic could be shot.  The Company’s plan is to renew the additional permits, commence the seismic shoot and acquire additional leaseholds; provided that at least $4,000,000 can be raised to fund this project.  We believe that the Amber Project holds significant oil and gas potential on and near several salt domes onshore St. Mary Parish, South Louisiana. Within and around the total acreage, we believe there are low risk oil and gas objectives from 5,000’ to 14,000’ as well as riskier deep gas potential to 18,000’.  

Several regional 3-D seismic programs were shot several years ago that acquired data in and around the project area.  The plan is to augment the existing 3-D coverage by shooting the gaps between the existing programs to get a full fold and coverage over the objective area that has not been 3-D’ed.  This area will require land rig locations to fully develop.

In connection with the Seismic Permit Agreement with Apache Corporation, we entered into an Exploration Agreement with Apache Corporation which is subject to a pending lawsuit regarding non-producing deep rights of some of the various underlying leases.  While the litigation is in the early stages, the Company does not believe that this litigation will have a material impact on the Company or its operations.

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Amber Project

Acreage:	>25,000	Success Rate in area:	75% (historically)
Amber's Interest:	50.0% (depending on location)	Potential # of wells:	10 – 50
Potential Gross Oil:	10MMBO	Potential Gross Gas:	400BCF
Primary Objective:	Established field oil sands that are offsets to the 40 established field pays.
Secondary Objective:	Higher risk deeper sands that are offsets to the 20 established deeper field pays. We will need to raise additional funds to accomplish this objective.
2010 Plan:	Fund on a best efforts basis; shoot 3-D; evaluate 3-D and integrate with ongoing sub-surface geologic interpretation.
2011 Plan:	Continue Geologic & Geophysical interpretation; drill up to 5 wells provided that sufficient funds are available

Ensminger Replacement Well Project. The Ensminger Replacement Well Project covers 634 acres, in which the Company holds a 12.5% working interest before pay out and a 15% working interest after pay out.  Energy XXI Onshore, LLC is the operator for this project.  The Company is not responsible for funding the drilling and completion of the initial well in connection with this project.  The Ensminger #2 Well was drilled to a Total Vertical depth of 15,101’.  The operator was unable to log the lowest portion of the well and the participants are using 3-D seismic to determine in which direction a contemplated side-tracking of the well should be pursued.  For safety reasons, the well has been temporarily abandoned during this evaluation period.  The Company believes that the side-tracking will be considered a part of the original well drilling and, as such, will not be responsible for any associated costs.  The Company will be responsible for its proportionate share of the drilling and completion costs of any additional wells on this project.

The Ensminger Replacement Well Project is located onshore in sugar cane fields in St. Mary Parish, Louisiana.  The drilling of the Ensminger #2 replacement well to the Ensminger #1 well is being operated by Energy XXI Onshore, LLC.  The Ensminger # 1 well was drilled in 2004 in partnership with Exxon Mobil Corp. and Century Exploration New Orleans, Inc. and it is estimated that it discovered a potentially 70 BCFG and associated high yield condensate depletion-drive field from the Planulina Pay Sands at approximately 15,000’ Total Vertical Depth.

The Ensminger #1 well produced from the lower Planulina 69 Sand at a maximum productive rate of 10.4 million cubic feet of gas per day (“MMCFGPD”) and 205 barrels of oil per day (“BOPD”), with what we estimate to be cumulative production of over 3.25 BCFG and 49 MBO (thousands barrels of oil) from only 6 feet of pay; the thinnest of the three pay sands.  The operator shut in production while the well was still producing at a rate of 2 MMCFGPD and 11 BOPD with no formation water.  The plan was to abandon the 69 Sand and re-complete in the 68 Sand with an expected production rate of 18 MMCFGPD.  During the recompletion, the operator lost tools in the hole, and subsequent failed fishing operations resulted in damage to the casing; making further use of the well bore unfeasible.  In connection with the assignment of interest from ExxonMobil Corp, and Century Exploration New Orleans, Inc., Amber assumed the obligation to plug the Ensminger #1 well, which includes providing a bond in the amount of $730,000, which we obtained by collateralizing our assets under the letter of credit pursuant to the Amber Credit Facility. Other participants have assumed or will assume their share of this obligation. Amber’s current share of the bond’s collateralization is $365,000.

Ensminger Project

Acreage:	634	Success Rate in  area:	100%
Amber's Interest:	12.5-15%	Potential # of wells:	3
Potential Gross Oil:	70 BCF 1,080 MBO	Potential Gross Gas:	70 BCF
Risk values:	Low
Primary Objective:	Miocene Planulina sands (3) proven in offset well

Rampant Lion

Radiant owns 100% of Rampant Lion Energy, LLC (“Rampant Lion”).  Rampant Lion owns interests in a lease, comprising approximately 5,760 acres located in the federal waters offshore Texas.  The Aquamarine Project is approximately 28 miles from shore and is located in 140’ of water.  There is currently a shut in platform, which we intend to use to drill and produce our prospective wells.  The acreage position in which Rampant Lion holds its interest in the Aquamarine Project is subdivided into an exclusive area (Aquamarine Project – Marg A- Exclusive) and a nonexclusive area (Marg A-5 Non-Excusive).

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Aquamarine Project – Marg A Exclusive Area.  Marg A Exclusive includes 2,520 acres located in the federal waters offshore Texas, more specifically MU 758. Pursuant to the participation agreements with Challenger Minerals, Inc. and Medco Energi US, LLC, the Company holds an 11.25% working interest upon the well’s first production, a 28.135% working interest after the well pays out, and a 21.325% working interest after the project pays out and assuming certain third parties make certain elections.  A well was re-completed in May 2010 and production resumed shortly thereafter.  Medco Energi US, LLC is the operator for this project.

There is currently one well producing from the field.  It is supported from a caisson which is tied into the MU 759 “B” production platform located on a contiguous block. There is also a shut-in platform on Rampant Lion’s block We want to utilize the shut-in platform to drill and produce our prospective wells.  Chevron discovered normally-pressured multiple pays in the Rob L, Rob M & Marg A sands in 1977. Chevron set the ‘A’ platform and successfully drilled and completed 6 wells. The block has cumulative production of 96BCFG & 67MBO. The last date of production from this platform was in 1994. Rampant Lion generated and caused the Medco #1 well to be drilled in October 2006. This well tested the under-produced Marg A sands in a structurally higher position than the Chevron wells. The Medco well was successful in finding 103’ of net pay in 7 sands. The well was successfully tested in the Marg A at 2.5 MMCFGPD & Marg A-2 sands at 1.75 MMCFGPD and was producing from the Marg A – B sand at 1.75 MMCFGPD.

Our strategy is to prove up additional reserves by developing the sands tested above and the other pay sands seen in the initial well. We believe that the trap is a downthrown 3 and 4-way closure and that the sands are consistent across the structure and block.

Aquamarine Project – Marg A-5 Non-Exclusive.  Marg A-5 is located on MU 758 in the federal waters offshore Texas.  We currently hold a 100% working interest on 3,240 acres that make up the Aquamarine Project – Marg A-5.  We anticipate being the operator for this project.  There is currently no activity on this project.  In order to drill and complete a well on this project, the Company anticipates it will need to raise an additional $15,000,000 from third parties.  

Rampant Lion has identified a normally-pressured Marg A-5 prospect on the northeast portion of our block. The Marg A-5 sand is the lowermost of the Marg A sands locally.  There is approximately 2,500’ of gross sand section in the Marg A. Although our primary target is the Marg A-5, we intend to test the majority of this section in a trapping position.

In the adjacent block to the east, MU 759, EOG discovered commercial gas in January 1994. We understand that EOG drilled 6 productive well and set two structures, and that they found pay in 8 sands within the Marg A section.  The wells have cumulatively produced 45.5 BCFG & 165 MBO.  These sands are normally-pressured.  The trap is upthrown with 3 way dip closure. Seismically, there is some amplitude anomalies with phase changes within the Marg A section that are direct ties to the pay sands, including the Marg A-5.

We have interpreted 3D seismic and have integrated it with the sub-surface control.  Our prospect is upthrown with 3 way dip closure and has an amplitude anomaly with phase changes at the Marg A-5 level.  Approximately 7,000’ to the northwest, Chevron drilled its #1 well in November 1985.  This well encountered 65’ of Marg A-5 sand at 9,710’.  The sand is in a non-trapping position and had no amplitude or phase change characteristics.  At our location, we will be >200’ high to this well at the Marg A-5 sand level.  The prospect has 335 acres of closure.   

Aquamarine Project (Exclusive Area)

Acreage:	2,520	Potential # of wells:	2
Rampant Lion's Interest:	28.125%	Success rate in area:	>75%
Potential Oil:	N/A	Potential Gas:	20 BCF
Risk values:	Low - Moderate
Primary Objective:	Marg A; Sands
2009 Plan:	Fund through best efforts; drill normally-pressured Marg A Sand

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Aquamarine Project – Marg A-5 (Non-Exclusive Area)

Acreage:	3.240	Potential # of wells:	1-3
Rampant Lion’s Interest:	100%	Success rate in area:	>75%
Potential Oil:	N/A	Potential Gas:	60 BCF
Risk values:	Moderate
Primary Objective:	Marg A Sands (Exclusive Area)
2010 Plan:	Fund through best efforts & drill normally-pressured Marg A sand

Garnet Project

We currently hold no rights to the Garnet Project. We anticipate deploying between $125,000 and $255,000 in capital to acquire a 33% working interest in the Garnet Project.  We anticipate needing an additional $6,200,000 to drill and complete a well and place production barge facilities on this property.  We intend to be the operator for this project.  The Garnet Project is an oil redevelopment project of a 1950’s field first developed by Sun Oil Company and is composed mainly of new drill sites that would sidetrack out of existing well bores. Additionally there are a number of rework/re-complete opportunities and deep gas exploration opportunities, all mostly within the confines of a 1950’s vintage Held By Production (HBP) state lease.

The project area is in the inland state waters of lower southeast St. Mary Parish, Louisiana within two fields that were discovered in the early 1950’s and have produced over 59MMB0 and 2.8TCFG since 1965.  The subject property is a state lease on which a major oil company drilled 26 wells. Since 1965 the wells produced 217BCF and 5.8MMBO from 21 productive wells out of 63 individual perforated intervals from 20 different normally-pressured pay sands ranging from 9,000’ to 12,000’. Overall we believe this is an excellent opportunity to redevelop a major oil company’s legacy leasehold.  The lease was originally taken by Sun Oil Company in 1947. The approximately 2000 acre lease has been and remains held by production by a third party. There are 13 existing wellbores on the property available for future utilization.

If we are able to acquire an interest in the Garnet Project, we anticipate processing the project in 3 phases:

Lower Risk Rework and Recompletions There are as many as 8 wells that are capable of being reworked and/or recompleted in a total of 16 different zones. Projected reserves for the rework/recomplete opportunities are not the main thrust of the proposed operations and only 2 wells are targeted to re-enter and re-complete.

Development Drilling for PUD and Low Risk Probable and Possible Reserves The initial thrust of the redevelopment effort is to prove up reserves in these categories that can be subsequently drilled from existing locations utilizing existing well bores or through new wells. Use of existing wellbores should qualify for a two-year exemption from Louisiana severance taxes of 12.5% on oil and approximately 7% on gas.

The PUD (Proved Undeveloped) reserves are up dip to existing wells that have either watered out or gone off production making 30-60 barrels of oil with water ranging from 60 to 95% BS&W. Additionally there are compression reserves that can be captured utilizing 3 stage compression. Most wells went off production in the mid to late 70’s and the last well drilled in the area was in 1985.  Current pricing makes this an economic venture.

There are 20 productive pay sand intervals in the field in a 3000’ stratigraphic interval and all of the identified fault blocks thus far have not tested the entire stratigraphic section in optimal trapping position. There are a number of fault blocks that have only tested narrow intervals of the entire productive stratigraphic section and there is further potential for these untested strata graphic sections.

Wells in the PUD and probable category require wells no deeper than 12,500’ in normally-pressured sections requiring mud weights in the 10 pound range.

High Potential Exploratory Drilling Although deep sand potential is not the initial thrust of the development program a very large potential deep gas exploratory play on the acreage position has been identified. The play consists of an over all 2000 + acre 3-way dip closure, which is down-thrown and along trend to the same fault that is responsible for deep gas production in adjacent fields both to the east and to the west. We believe that potentially large reserves exist within this large down-thrown closure.

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Garnet Project

Acreage:	~2000acres	Success Rate in area:	80% (historically)
Radiant Interest:	0% (anticipated 100%)	Risk values:	Low - Moderate
Potential Oil:	5MMBO	Potential Gas:	200BCF
Production in area:	Minimum
Primary Objective:	Shallow offsets to field pay sands for mostly oil.
Secondary Objective:	Deeper geopressured gas sands
2010 Plan:	Purchase 3D seismic data, fund on a best efforts basis; permit; drill up to 4 wells

Baldwin Project

We have an Area of Mutual Interest Agreement with J&S 2008 Program, LLC, in which J&S 2008 Program LLC will assemble this prospect.  J&S 2008 Program, LLC will pay 100% of the leasehold costs and will carry us for a 12.5% interest in the initial test well.  In addition, we have the right to participate for 10% in the prospect by paying that percentage amount of the leasehold and initial well costs.  We will be responsible for our proportionate share of all drilling and completion costs in subsequent wells and will need to raise the financing to participate in this project.  Radiant currently has no leasehold ownership interests in this prospect.

The Baldwin Project is an offset to the Ensminger Project.  Baldwin Field was discovered in the late 70’s by Sun Oil Company and has produced over 45 BCF and 550MBO out of a geopressured sand at approximately 14,000’.  We believe that the reserves of the prospective fault block are 6.7 BCF and 82MBO.

Ruby-Diamond-Coral Project

There are currently 5 leases that comprise this prospect.  We have a 65% working interest in the Ruby-Diamond-Coral Project before pay out and a 56.35% working interest after pay out.  We intend to act as the operator of this project.  We anticipate needing to raise $4,224,000 to drill and complete a well on this project.  Ruby-Diamond consists of 2,868 gross acres in shallow Louisiana state waters offshore St. Mary Parish.  Some additional leasing may be required before drilling is initiated.

Pursuant to an Option Agreement dated April 15, 2008, with Energy XXI, Energy XXI was to acquire 100% of the leases and we were provided the option to participate for a 25% working interest.  The Option Agreement was subsequently assigned to Buccaneer Resources, LLC.  As of the date hereof none of the leases had been assigned to Buccaneer Resources, LLC pursuant to the Option Agreement, although they will be upon request by Buccaneer.  

In addition, pursuant to an Exploration Agreement between Jurasin, Sweet Bay Exploration, LLC and Energy XXI, Jurasin and Sweet Bay were provided the right to receive a permanent overriding interest of 2.5% and a 2% overriding interest which could be converted into a 25% working interest at payout.  Subsequently, Energy XXI withdrew from the project but the Exploration Agreement has never been amended to reflect the terms between the remaining parties. We anticipate amending the Exploration Agreement in September 2010 to reflect all current terms.

Ruby Diamond.  The Ruby Prospect is an overall 180 BCFG multiple well prospect in an old Shell Oil Company field, which has produced 509 BCFG and 65 MMBO.  The primary objective is the Text. W (Middle Miocene) sands in a reservoir pool extension at an estimated depth of 12,000’.  The secondary objective is the Cib.  Op (Middle Miocene) sands in a deeper pool reservoir in a gas productive fault block at an estimated depth of 15,500’.  The prospect is covered with 3-D seismic.

Coral Prospect.  The Coral Prospect is a new fault block extension of the Eugene Island Block 18 field (509 BCFG, 65 MMBO).  The primary objectives are the geopressured Text. W sands which have produced 103 BCFG and 2.8 MMBC in the field proper.  Three Text. W sands ranging in depths from 12,300′ to 12,800′ are the specific prospect targets. Total potential gas reserves for the coral prospect are 30 BCFG.

The initial proposed well will be a re-entry and sidetrack from the inactive COCKRELL #1 SL 14354 borehole.  A directional well will be drilled to 13,702′ MD (13,000′ TVD). The estimated dry hole cost of the proposed sidetrack is $3,300,000.  

Potential reserves for the prospect fault block total 30 BCFG.  Potential reserves were calculated using three Text. W sand levels (“Z-1”, “AA” and “BB”).  These particular sands were wireline logged as gas productive in the down dip COCKRELL #2 SL 14354.  Recently, a third-party reserve report assigned a potential of 11 BCFG and 300 MBC solely to the initial proposed well.

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Productive Wells

Our working interests in productive wells:

	December 31, 2009
	Gross	Net
Natural Gas	1	0.1125
Crude Oil	0	0
Total	1	0.1125

Drilling Activity

The following table sets forth our drilling activity.

	Year Ended December 31,
	2009		2008
	Gross	Net	Gross	Net
Productive Wells
Development	0	0	0	0
Exploratory	0	0	0	0
Total	0	0	0	0
Non productive wells
Development	0	0	1	0.5
Exploratory	0	0	0	0
Total	0	0	1	0.5

Acreage

Working interests in developed and undeveloped acreage:

	December 31, 2009
	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Onshore	0	0	1,624	414	1624	414
Offshore	2,520	709	6,108	5,104	8,628	5,813
Total	2,520	709	7,732	5,518	10,252	6,227

Our estimate of acreage includes those that we directly own and our pro rata share of acreage associated with Amber Energy which is accounted for on a proportional consolidation basis.  Our interest in Amber Energy was 51% as of December 31, 2009.

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The following table summarizes potential expiration of our onshore and offshore undeveloped acreage.

	Year Ended December 31,
	2010		2011		2012
Onshore	4,547	1,038	0	0	0	0
Offshore	508	330	0	0	0	0
Total	5,055	1,368	0	0	0	0

Our estimate of acreage includes those that we directly own and our pro rata share of acreage associated with Amber Energy which is accounted for on a proportional consolidation basis.  Our interest in Amber Energy was 51% as of December 31, 2009.

Capital Expenditures, Including Oil and Gas Costs Incurred

Property acquisition costs:

	Year Ended December 31,
	2009	2008
	(In Thousands)
Oil and Gas Activities
Development	$133	$2,876
Exploration	122	227
Property acquisitions	149	1,512
Administrative and Other	--	16
Capital Expenditures, Including Acquisitions	404	4,631
Cost recovery	--	(2,356)
Adjustment of interest in investee	(652)	--
Total costs incurred	$(248)	$2,275

Oil and Gas Production and Prices

Our average daily production represents our net ownership.  Our average daily production and average sales prices:

	Year Ended December 31,
	2009	2008
Sales Volumes per Day
Natural gas (Mcf)	50	93
Crude Oil (Bbls)	0.4	0.4
Total (McfE)	52.3	95.2
Percent of McfE from crude oil	0.8%	0.4%
Average Sales Price
Natural Gas per Mcf	$3.85	$8.96
Crude oil per Bbl	$63.19	$88.43

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Production Unit Costs

Our production unit costs.  Production costs include lease operating expense and production taxes.

	Year Ended December 31,
	2009	2008
Average Costs per McfE	12.08	6.19
Production Costs
Lease operating expense	109,676	136,386
Gathering and Processing	13,500	7,941
Workover and maintenance	150,637	63,327
Production Taxes	4,570	3,211
Total production costs	$278,383	$210,865

Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

	December 31, 2009
	Proved Developed Producing	Proved Developed Non-Producing	Total Proved Developed	Proved Undeveloped	Total Proved Reserves
Crude oil (MBbls)	0.06	0.58	0.64	40	41
Natural gas (MMcf)	79	534	613	2,664	3,277
Total (MMcf)	80	537	617	2,904	3,521
PV-10 (In Thousands)(1)	$235	$518	$753	$6,352	$7,105

⁽¹⁾ PV-10 reflects the present value of our estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the average price from the first day of every month in 2009) without giving effect to non-property related expenses such as general and administrative expenses, debt service, DD&A expense and discounted at 10 percent per year before income taxes. Average prices in effect for 2009 were $61.18 per barrel of oil and $3.87 per mmbtu of natural gas, excluding differentials.

Our estimate of proved reserves include those that we directly own and our pro rata share of proved reserves associated with Amber Energy, which is accounted for on a proportional consolidation basis. Our interest in Amber Energy was 51% as of December 31, 2009.

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Industry Overview

Crude oil prices continue to be very volatile.  The WTI spot price is projected to rise slowly as economic conditions improve, to an average of about $72 per barrel in 2010.  The high price case depicts a future world oil market in which conventional production is restricted by political decisions as well as by resource availability, as major producing countries use quotas, fiscal regimes, and various degrees of nationalization to increase their national revenues from oil production.  In 1970, we imported 24% of our oil, today it's nearly 70% --and growing. Although the United States represents a mere 4% of the world's population, we use nearly 25% of its oil.

The No. 1 field in the world, the Ghawar, is pretty close to peaking if it hasn't already. The non-OPEC world, 175 countries, of which only 30 produce meaningful amounts of oil, should experience peak production in 2010. Then the world will become dependent on OPEC for all future growth in barrel needs. That should put the US in a pretty difficult situation and the price of oil should begin to rise.  

Eleven of the non-OPEC countries have peaked already, representing 34.3% of non-OPEC production. There are three on the cusp of peaking, and one of them, Mexico, may have already peaked and represents 7.9% of production. China will probably peak this year, or next. They are at flat production levels now and contribute 8.5%. More than 50% of the non-OPEC production will therefore have peaked. There are a great number of issues affecting when the whole world’s production peaks.  The demand for oil and, thus, pricing should continue to rise as other producing areas become less productive.   

Current Lower Cost Environment.

The oil and gas industry has experienced a decrease in drilling and production costs as equipment and services are oversupplied for the current drilling demand.  As the oil price settles in a normal range, between $60 and $80 per barrel, drilling costs are expected to return to pre-recession levels. Radiant expects to benefit from the current lower cost environment as a result of its "ready to drill" inventory.

Most oil & gas analysts and economists are predicting higher prices for oil and natural gas into the future.  With the growth of China and India the demand for oil is at an all time high.  Regardless of any consumption changes within the US, the worldwide demand for oil and gas will continue to utilize all available supply quantities for many years to come.  

Marketing and Customers

We intend to market substantially all of our oil and natural gas production from the properties we operate. The majority of our operated oil gas production will likely be sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Medco Energi US accounted for approximately 100 percent of our total oil and natural gas revenues during the years ended December 31, 2008 and 2009. We may also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Medco Energi US LLC curtailed its purchases.

We transport most of our oil and gas through third-party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is normally readily available. Our ability to market our oil and gas may at times be limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties could be adversely affected.

Competition

The oil and gas industry is intensely competitive. This is particularly true in the competition for acquisitions of prospective oil and natural gas properties and oil and gas reserves.  We believe that the location of our leasehold acreage, our exploration, drilling, and production expertise, and the experience and knowledge of our management and industry partners enable us to compete effectively in our core operating areas.  Notwithstanding our talents and assets, we still face stiff competition from a substantial number of major and independent oil and gas companies that have larger technical staffs and greater financial and operational resources than we do.  Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity.  We also compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for the drilling and completion of wells. We are seeing signs of loosening rig availability, although it is quite specific by region.

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Regulatory Matters

Regulation of Oil and Gas Production, Sales and Transportation

The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.

We intend to operate various gathering systems. The United States Department of Transportation and certain governmental agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities by prescribing standards. However, based on current standards concerning transportation and storage activities and any proposed or contemplated standards, we believe that the impact of such standards is not material to our operations, capital expenditures or financial position.

All of our sales of our natural gas are currently deregulated, although governmental agencies may elect in the future to regulate certain sales.

Environmental Regulation

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste materials, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations:

·

Clean Air Act, and its amendments, which governs air emissions;

·

Clean Water Act, which governs discharges of pollutants into waters of the United States;

·

Comprehensive Environmental Response, Compensation and Liability Act, which imposes strict liability where releases of hazardous substances have occurred or are threatened to occur (commonly known as “Superfund”);

·

Resource Conservation and Recovery Act, which governs the management of solid waste;

·

Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;

·

Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;

·

Safe Drinking Water Act, which governs underground injection and disposal activities; and

·

U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. To date, there are no known issues that have had a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.

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The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. For example, costs may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

We believe our operations are in substantial compliance with applicable environmental laws and regulations. We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. The insurance coverage maintained by us provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Employees

We will have approximately 7 employees and one consultant as of the date hereof.

General

Our principal place of business is at 9700 Richmond Avenue, Suite 124, Houston, Texas 77042.   

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Organizational History

Prior to the Reorganization, Radiant was an inactive public company seeking merger and business operations opportunities.  The Company was originally incorporated as a Colorado corporation in June 1973.  In April 2010, the Company reorganized from a Colorado corporation to a Nevada corporation, effected a 5 for 1 reverse split and changed its name from G/O Business Solutions, Inc. to Radiant Oil & Gas, Inc.

In July 2010, the Company entered into an exchange agreement with Jurasin, which closed in August 2010.  For legal purposes, Radiant is the surviving entity; however for accounting purposes, Jurasin is the survivor.  Jurasin was originally incorporated as a Louisiana corporation in October 1990.

Principles of Consolidation

We consolidate all investments in which we have exclusive control.  The accompanying consolidated financial statements include the accounts of Jurasin, Rampant Lion, and JOGop.  In accordance with established practice in the oil and gas industry, our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of Amber in which we have an interest.  We own a 51% interest in Amber as of March 31, 2010 and as of August 5, 2010.  

Results of Operations of Radiant (not giving effect to Jurasin)

During the year ended December 31, 2009, Radiant had no revenues, total expenses of $83,692 and a loss of $(83,692). During the year ended December 31, 2008, Radiant had no revenues, total expenses of $230,867 and a net loss of $(230,867).  During the quarter ended March 31, 2010, Radiant had no revenue, total expenses of $82,719 and a net loss of $(82,179).  During the quarter ended March 31, 2009, Radiant had no revenues, total expenses of $35,928 and a net loss of $35,928.  Our expenses have been primarily comprised of legal and accounting professional services.

Results of Operations of our wholly-owned subsidiary Jurasin

Years ended December 31, 2008 and December 31, 2009:

·

Revenue decreased from $519,183 for the year ended December 31, 2008 to $106,502 for the year ended December 31, 2009.  The decrease in revenue is due in part to decreased production volumes, but it is primarily due to decreases in selling prices for oil and gas.  

·

Total operating expenses decreased from $890,536 for the year ended December 31, 2008 to $843,282 for the year ended December 31, 2009.

·

Operating loss increased from $(371,353) for the year ended December 31, 2008 to $(736,780) for the year ended December 31, 2009 due primarily to the decreased revenue, as discussed above.

·

Net loss increased from $(771,994) for the year ended December 31, 2008 to $(1,054,470) for the year ended December 31, 2009 due primarily to the decreased revenue, as discussed above.

Quarters ended March 31, 2009 and March 31, 2010:

·

Revenues increased from $11,762 for the quarter ended March 31, 2009 to $44,854 for the quarter ended March 31, 2010.  The increase in revenue is due primarily to increased production levels.

·

Total operating expenses decreased from $396,707 for the quarter ended March 31, 2009 to $153,000 for the quarter ended March 31, 2010. The decrease in operating expenses is driven by a decrease in lease operating expense of approximately $195,000, which includes workover expenses incurred in 2009 which were not repeated in 2010, and a decrease in general and administrative expense of approximately $52,000.  

·

Operating loss decreased from $(384,945) for the quarter ended March 31, 2009 to $(108,146) for the quarter ended March 31, 2010 due to the factors discussed above.

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·

Net loss decreased from $(481,584) for the quarter ended March 31, 2009 to $(159,854) for the quarter ended March 31, 2010 due to the factors discussed above.

Liquidity and Capital Resources

At March 31, 2010, we had pro-forma current assets of $1,452,028, pro-forma current liabilities of $5,795,878 and $(4,343,850) of pro-forma negative working capital. As of this date, the Company has nominal current assets and working capital.  The Company intends to raise up to $6,000,000 in 2010 to fund operations.  In July and August 2010, the Company issued $600,000 of debentures.  The proceeds of the debentures were used for working capital purposes to discharge past due obligations.   The debentures mature on the earlier of July 31, 2011 or the closing of $2,000,000 of financing. The debentures provide that 30% of the gross proceeds from subsequent financings be used as a partial prepayment of principal.

Amber has a secured credit facility with MBL, of which approximately $2,270,000 of principal and accrued interest is owed as of the date hereof.  Interest accrues at the prime rate and is due upon maturity.  The Amber Credit Facility matures in March 2011.  All of Amber’s and Rampant Lion’s assets are secured by the Credit Facility and Amber has agreed to apply all revenue received from its projects to reduce the Credit Facility.  MBL has agreed to convert up to $510,000 ($1,000,000, on Amber’s stand-alone basis) of the Credit Facility into shares of common stock at a conversion price of $2.00 per share (subject to downward adjustment depending upon pricing in subsequent Company equity financings) pursuant to the Debt Conversion.  The 51% membership interest owned by the Company is pledged to MBL, and MBL owns the remaining 49% of Amber through its affiliate MAC.  MBL has agreed to release Amber’s assets, Amber’s pledged membership interest and convey back to Jurasin Amber membership interests and the Amber real property interest held by MBL, if the Credit Facility (both the Amber Credit Facility and Rampant Lion Credit Facility) is paid in full prior to March 15, 2011.

Rampant Lion has a secured credit facility with MBL, of which approximately $1,350,000 of principal and accrued interest is owed as of the date hereof.  Interest accrues at the rate of prime plus 8% per annum and is due monthly.  All of Rampant Lion’s assets are secured by the Credit Facility.  The facility matures in March 2011.

The Company is required to make monthly mandatory principal reduction payments to MBL on the Credit Facility on each of August 20, 2010 and September 20, 2010 in the aggregate amount of $100,000; and on each of October 20, 2010, November 20, 2010, December 20, 2010, January 20, 2011 and February 20, 2011 in the aggregate amount of $250,000; the loan also provides that the Company shall pay to MBL an amount equal to 1/6th of the gross proceeds raised by the Company through any equity raises, which amounts shall be credited against the monthly mandatory principal reduction payments.  Prior to the March 20, 2011 maturity date of the Credit Facility, the Company will be required to pay off or refinance the Credit Facility in the amount of approximately $4,000,000 (on a stand-alone basis, Rampant Lion and Amber owe approximately $5,800,000).The Company intends to refinance the Credit Facility on or before its maturity in March 2011; however there is no guarantee that the Company will be successful in this endeavor as it has no commitments as of the date hereof.  As part of the Credit Facility modification, the Company has agreed to guarantee $500,000 of the Credit Facility obligations.

While management believes that it possesses sufficient collateral to support a new credit facility for each of these existing credit facilities, there can be no assurance that the Company will be able to refinance the Amber Credit Facility and/or the Rampant Lion Credit Facility.  The failure to refinance the Credit Facility on acceptable terms, will cause the Company to curtail operations.  

We do not have any commitments for funding at this time and currently do not have credit facilities available with financial institutions or other third parties.  We provide no assurance we will be successful in seeking additional financing to refinance existing credit facilities or to finance existing and future operations.  Failure to obtain sufficient financing to accomplish these goals will likely result in curtailed operations.

Implementation of the Company’s business strategy will require approximately $10,000,000 of equity to be raised during 2011 (in addition to the $6,000,000 capital needed to fund working capital needed in 2010), and additional funds thereafter to implement the business plan. There can be no assurance that these best-efforts financings will result in required fundings on favorable terms, if at all.  The failure to raise needed funds would have a material adverse effect on our business, financial condition, operating results and prospects, and the Company may not survive.

Off-Balance Sheet Arrangements

None.

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Critical  Accounting Policies

Principles of Consolidation

We consolidate all investments in which we have exclusive control.  In accordance with established practice in the oil and gas industry, our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of a limited liability company, Amber Energy, LLC (“Amber”) in which we have an interest. We owned a 75% interest in Amber through October 9, 2009 and 51% after that date.

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our estimates include oil and natural gas proved reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties

We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the SEC. Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.

Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization. We evaluate unevaluated properties for inclusion in the amortization base at least annually.

Capitalized costs included in the amortization base are depleted using the units of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

We include our pro rata share of assets and proved reserves associated with an investment that is accounted for on a proportional consolidation basis with assets and proved reserves that we directly own in the appropriate cost center. We calculate the depletion and net book value of the assets based on the cost center’s aggregated values. Accordingly, the ratio of production to reserves, depletion and impairment associated with a proportionally consolidated investment does not represent a pro rata share of the depletion, proved reserves, and impairment of the proportionally consolidated venture.

The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

 

Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. 

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Asset Retirement Obligation

We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.

Revenue Recognition

We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.

Recent Accounting Pronouncements

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the un-weighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009.

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted ASU 2010-03 effective December 31, 2009.

In June 2008, the FASB issued Emerging Issues Task Force (EITF) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (ASC 260). ASC 260 clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends or dividend equivalents before vesting should be considered participating securities. The adoption of ASC 260 on January 1, 2009 did not have a significant impact on our operating results, financial position or cash flows.

In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. We adopted the provisions of ASU 2010-09 for the period ended March 31, 2010.

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RISK FACTORS

Risks Related to our Financial Condition

We currently have nominal revenues, have experienced losses, and anticipate that we will continue to incur losses for the foreseeable future.

During the twelve months ended December 31, 2008 and December 31, 2009, Jurasin generated net revenues of $519,183 and $106,502, respectively. For the twelve months ended December 31, 2008, Jurasin operating expenses were $890,536, resulting in a loss from operations of $(371,353). For the twelve months ended December 31, 2009, Jurasin operating expenses were $ 843,282, resulting in a loss from operations of $(736,780).  For the three months ended March 31, 2010, revenue was $44,854, operating expenses were $153,000 and the loss from operations was $(108,146).  Radiant has had no revenue during the last two fiscal years and incurred loss from operations of $(230,867) and $(83,692) for the years ended December 31, 2008 and December 31, 2009, respectively.  Radiant had no revenues during the three months ended March 31, 2010, and a loss from operations of $(82,719).  It should be expected that we will continue to experience operating losses at least through 2010. There can be no assurance that we will ever achieve net income from operations or otherwise become profitable.

We have negative cash flow from operations.

We have historically experienced losses and negative cash flows from operations and these conditions raise substantial doubt about our ability to continue as a going concern and management is attempting to raise additional capital to address our liquidity.  We believe that our negative cash flow from operations will continue at least through 2010.  There can be no assurance that we will ever be able to raise sufficient capital to generate positive cash flow from operations.  

We will need to raise significant capital during 2010.

At March 31, 2010, we had pro-forma current assets of $1,452,028, pro-forma current liabilities of $5,795,878 and $(4,343,850) of pro-forma negative working capital. As of this date, the Company has nominal current assets and a significant working capital deficit.  The Company intends to raise up to $6,000,000 during 2010 to fund working capital needs in 2010.  In July and August 2010, the Company borrowed $600,000 of indebtedness that matures on the earlier of July 31, 2011 and the closing of $2,000,000 of financing and that contain partial prepayment obligations from subsequent financings.  In March 2011, the Company will be required to pay off or refinance the Credit Facility in the amount of approximately $4,000,000 (on a stand-alone basis, Rampant Lion and Amber owed approximately $5,800,000). While management believes that it possesses sufficient collateral to support a new credit facility for each of these existing credit facilities, there can be no assurance that the Company will be able to refinance the Amber Credit Facility and/or the Rampant Lion Credit Facility.  MBL has agreed to convert $510,000 ($1,000,000 Amber’s stand-alone basis) of the Credit Facility into up to 1,000,000 shares of Company common stock pursuant to the Debt Conversion.  The failure to refinance the Credit Facility on acceptable terms will cause the Company to curtail operations.  Implementation of the Company business strategy will require approximately $10,000,000 of equity to be raised during 2011 (in addition to the $6,000,000 of capital needed to fund working capital needs in 2010), and additional funds thereafter to implement the business plan. There can be no assurance that these best-efforts financings will result in required fundings on favorable terms, if at all.  The failure to raise needed funds would have a material adverse effect on our business, financial condition, operating results and prospects, could cause us to curtail operations.

Debt to be repaid out of subsequent financings.

In July and August 2010, the Company issued debentures in the principal amount of $600,000, bearing interest at the rate of 18% per annum, that mature on the earlier of July 31, 2011 or the closing of a $2,000,000 financing, financing (to be partially pre-paid with 30% of the gross proceeds from subsequent financings equaling and exceeding $500,000).  In addition, in August 2010, the Company amended its Credit Facilities and it is obligated to pay to MBL an amount equal to 1/6^th of the gross proceeds raised by the Company through equity raised subsequent to the amendment date.  The Company owes approximately $4,000,000 on its Credit Facility.  Accordingly, the Company will need to raise a sufficient amount of subsequent financing to cover working capital needs in 2010 and 2011, as well as to pay down or refinance the Credit Facility.

We have a Going Concern

As of December 31, 2009, our auditor determined that our financial conditions raised substantial doubt as to our ability to continue as a going concern.  Management plans to raise equity financing and to restructure our Credit Facility. Our ability to continue as a going concern is dependent on our ability to raise additional capital and refinance our Credit Facility, of which there can be no assurance that we will be successful.  If we do not raise capital sufficient to fund our business plan, we may not survive.  

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The terms of Amber and Rampant Lion’s debt obligation subject us to the risk of foreclosure on all of Amber and Rampant Lion’s respective assets and imposes restrictions that may limit our ability to take certain actions.

Our subsidiaries Amber and Rampant Lion both have secured credit facilities with MBL.  All of the Rampant Lion and Amber assets secure the Credit Facility.  As of the date hereof, the outstanding principal and interest on the Credit Facility was approximately $4,000,000 (on a stand-alone basis, Rampant Lion and Amber owed approximately $5,800,000).  The Credit Facility matures in March 2011.  Radiant is prohibited from taking any material action without the consent of MBL including selling or disposing of any assets of Amber and Rampant Lion.  To secure the payment of all obligations owed pursuant to the Credit Facility, Amber and Rampant Lion, respectfully, granted the bank a security interest and lien on all of their respective assets. The occurrence of an event of default under any of our obligations would constitute a cross-default and would subject us to foreclosure to the extent necessary to repay any amounts due. If the bank were to foreclose on either Amber’s or Rampant Lion’s assets, such event would have a material adverse effect on our financial condition.

Failure to retire or refinance either the Amber Credit Facility or the Rampant Lion Credit Facility will adversely affect our financial condition.

We do not have sufficient funds to repay the Amber Credit Facility and the Rampant Lion Credit Facility when our debt obligations to them become due. Accordingly, we will be required to obtain funds to repay the Credit Facility either through refinancing or the issuance of additional equity or debt securities. As we have no commitment in place to effect such actions, there is no assurance that we can refinance such indebtedness.  The failure to refinance either the Amber Credit Facility or the Rampant Lion Credit Facility would adversely affect the Company and could cause us to curtail operations.

We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements will depend on numerous factors, and we cannot predict accurately the timing and amount of our capital requirements. We intend to primarily finance our capital expenditures through best efforts equity and debt offerings.  There is no assurance that we will be successful in these capital raising activities.  Adverse change in market conditions could make obtaining this financing economically unattractive or impossible.

The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, ceased to provide funding to borrowers.

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our credit facilities which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or not purse growth opportunities.

Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations.  As a result, we may lack the capital necessary to capitalize on business opportunities described herein and be successful in our business operations.  There is no assurance that we will be successful in raising the capital necessary to implement our business plan.

To service our indebtedness, we will require a significant amount of cash. Our ability to raise significant capital depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness (including the existing Credit Facility) and to fund planned capital expenditures and development and exploration efforts will depend on our ability to raise cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure you that future borrowings or other facilities will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

We may be required to:

·

obtain additional financing;

·

sell some of our assets or operations;

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·

reduce or delay capital expenditures, development efforts and acquisitions; or

·

revise or delay our strategic plans.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure you that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.

Potential claim for shares of common stock by a third party finder.

In April 2010, the Company entered into a reorganization agreement that terminated as conditions precedent to closing were not satisfied.  A third party finder was to receive shares pursuant to this agreement but as such agreement was terminated due to closing conditions not being satisfied, such party is not entitled to receive any shares of Company common stock.  While this party has stated to one of our directors that he is entitled to an unspecified number of shares, the Company intends to vigorously defend any claim made against the Company and any of its directors by this third party.  As no formal demand against the Company has been made, it is not possible to quantify such claim.

Risks Related to Our Business

Any extended moratorium on new drilling in the U.S. Gulf of Mexico, or any resulting additional regulations, could have a material adverse effect on any production revenue.

On April 30, 2010, officials in the Obama Administration indicated that federal agencies would not authorize new offshore drilling in U.S. waters pending review of the oil spill caused by the sinking of the Deepwater Horizon. This announcement stated that no additional drilling will be authorized until the administration completes its review of the cause of the explosion and determination of whether the explosion was unique and preventable. The administration subsequently amended the moratorium to apply only to tracts in water depths greater than 500 feet. While the Company does not own interests in any tract in the affected water depth, there is no guarantee that the restrictions will not be expanded in the future to include all tracts or to place additional bonding or other financial requirements on oil and gas producers operating in federal waters. Any such expansion of restrictions or similar  resultant federal legislation, policy, or regulations could cause delays or deter new drilling in the U.S. Gulf of Mexico, or may increase the costs of offshore production. Any production revenue payable to the Company relating to the Aquamarine Project (both the Marg A – Exclusive and Marg A – Non-Exclusive) could be thus materially adversely affected.  We cannot predict at this time what impact, if any, this incident may have on the operations of Aquamarine Project (both the Marg A – Exclusive and Marg A – Non-Exclusive).

Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would affect our financial results and impede growth.

Our future financial condition, revenues, profitability and carrying value of our properties will depend substantially upon the prices and demand for oil and natural gas.  The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth.

Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

·

domestic and foreign supplies of oil and natural gas;

·

price and quantity of foreign imports of oil and natural gas;

·

actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

·

level of consumer product demand;

·

level of global oil and natural gas exploration and productivity;

·

domestic and foreign governmental regulations;

·

level of global oil and natural gas inventories;

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·

political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

·

weather conditions;

·

technological advances affecting oil and natural gas consumption;

·

overall U.S. and global economic conditions; and

·

price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us, in future periods, having to make substantial downward adjustments to any estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

Our future business will involve many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities. Any such activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.

Our business involves a variety of inherent operating risks, including:

·

fires;

·

explosions;

·

blow-outs and surface cratering;

·

uncontrollable flows of gas, oil and formation water;

·

natural disasters, such as hurricanes and other adverse weather conditions;

·

pipe, cement, subsea well or pipeline failures;

·

casing collapses;

·

mechanical difficulties, such as lost or stuck oil field drilling and service tools;

·

abnormally pressured formations; and

·

environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

·

injury or loss of life;

·

severe damage to and destruction of property, natural resources and equipment;

·

pollution and other environmental damage;

·

clean-up responsibilities;

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·

regulatory investigations and penalties;

·

suspension of our operations; and

·

repairs to resume operations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our properties will materially affect the quantities and present value of those reserves.

Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions.  In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of any proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Unless we replace crude oil and natural gas reserves any future reserves and production will decline.

Our future crude oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace any reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.

Relatively short production periods or reserve life for Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the United States. Typically, 50 percent of the reserves of properties in the Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs.  A significant amount of our prospects are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

The Company may need to obtain bonds or other surety in order to maintain compliance with those regulations promulgated by the MMS.

For offshore operations, lessees must comply with the MMS regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Shelf and removal of facilities. To cover the various obligations of lessees on the U.S. Outer Continental Shelf of the Gulf of Mexico, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. We are currently reviewing whether we are exempt from the supplemental bonding requirements of the MMS. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

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The possible lack of business diversification may adversely affect our results of operations.

Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. By consummating acquisitions only in the offshore Gulf of Mexico and Gulf Coast onshore our lack of diversification may:

·

subject us to numerous economic, competitive and regulatory developments, any or all of which may have a substantial adverse impact upon the particular industry in which we operate; and

·

result in our dependency upon a single or limited number of reserve basins.

In addition, the geographic concentration of our properties in the Gulf of Mexico and Gulf Coast onshore means that some or all of the properties could be affected should the region experience:

·

severe weather;

·

delays or decreases in production, the availability of equipment, facilities or services;

·

delays or decreases in the availability of capacity to transport, gather or process production; and/or

 

·

changes in the regulatory environment.

Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we. We actively compete with other companies when acquiring new leases or oil and gas properties. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves.

We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

·

the volume, pricing and duration of our natural gas and oil hedging contracts

·

supply of and demand for natural gas and oil;

·

actual prices we receive for natural gas and oil;

·

our actual operating costs in producing natural gas and oil;

·

the amount and timing of our capital expenditures and decommissioning costs;

·

the amount and timing of actual production; and

·

changes in governmental regulations or taxation.

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The timing of any production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our offshore operations will involve special risks that could affect operations adversely.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.

Market conditions or transportation impediments may hinder access to oil and gas markets or delay production.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities.  We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.

We are not the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We currently operate or plan to operate approximately 88% percent of our properties, which includes the non-exclusive portion of Mustang Island 758, the Amber 3D shoot, the Ruby-Diamond-Coral complex and the to be acquired Garnet Project acreage. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

·

the timing and amount of capital expenditures;

·

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

·

the operator’s expertise and financial resources;

·

approval of other participants in drilling wells;

·

selection of technology; and

·

the rate of production of the reserves.

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Our insurance may not protect us against business and operating risks.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Although we will maintain insurance at levels we believe are appropriate and consistent with industry practice, we will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. Due to a number of catastrophic events such as the terrorist attacks on September 11, 2001 and Hurricanes Ivan, Katrina, Rita, Gustav and Ike, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Ivan, Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005 or 2008, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. We do not intend to put in place business interruption insurance due to its high cost. This insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf of Mexico and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

Our operations will be subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.

Oil and gas exploration and production operations in the United States and the Gulf of Mexico are subject to extensive federal, state and local laws and regulations. Companies operating in the Gulf of Mexico are subject to laws and regulations addressing, among others, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, environmental and safety matters, plugging and abandonment of wells and associated infrastructure after production has ceased, operational reporting and taxation. Failure to comply with such laws and regulations can subject us to governmental sanctions, such as fines and penalties, as well as potential liability for personal injuries and property and natural resources damages. We may be required to make significant expenditures to comply with the requirements of these laws and regulations, and future laws or regulations, or any adverse change in the interpretation of existing laws and regulations, could increase such compliance costs. Regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

·

require the acquisition of a permit before drilling commences;

·

restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

·

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

·

impose substantial liabilities for pollution resulting from operations.

Failure to comply with these laws and regulations may result in:

·

the imposition of administrative, civil and/or criminal penalties;

·

incurring investigatory or remedial obligations; and

·

the imposition of injunctive relief, which could limit or restrict our operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.

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We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, or if current or prior operations were conducted consistent with accepted standards of practice. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

We currently do not hedge but believe that we will hedge in the near future.  Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

We may be unable to successfully integrate the operations of the properties we acquire.

Integration of the operations of the properties we acquire with our existing business will be a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

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·

operating a larger organization;

·

coordinating geographically disparate organizations, systems and facilities;

·

integrating corporate, technological and administrative functions;

·

diverting management’s attention from other business concerns;

·

an increase in our indebtedness; and

·

potential environmental or regulatory liabilities and title problems.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

In addition, we face the risk of identifying, competing for and pursuing other acquisitions, which takes time and expense and diverts management’s attention from other activities.

We may not realize all of the anticipated benefits from our acquisitions.

We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.

If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our acquisitions.

We do not currently have commodity price risk; however, if we are able to produce oil and gas in the near future we may experience commodity price risk.  Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential. Inspections may not be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.

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If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether.

 

The construction and operation of energy projects require numerous permits and approvals from governmental agencies. We may not be able to obtain all necessary permits and approvals, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures and may create a risk of expensive delays or loss of value if a project is unable to function as planned due to changing requirements or local opposition.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Risks Related to our Common Stock

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our exploitation strategy as quickly as we would otherwise wish to do.

Future sales of our common stock in the public market could lower our stock price.

We will likely sell additional shares of common stock to raise capital.  We may also issue additional shares of common stock to finance future acquisitions, services rendered or equity raises. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock.  Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

We recently issued an aggregate of 7,086,409 shares for services rendered, which issuances may adversely affect the market value of our stock.

In July and August 2010, we issued 1,086,409 shares of common stock to an investor relations consultant, and 6,000,000 shares of common stock to an investment banker, both issuances for services to be rendered.  These issuances may be perceived as an overhang on the market and could depress any market that may develop for the Company common stock as well as the offering price of our equity securities in subsequent financings.

There is no assurance of continued public trading market and being a low priced security may affect the market value of stock.

To date, there has been only a limited public market for our common stock. Our common stock is currently quoted on the OTCBB. As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations as to the market value of our stock. Our stock is subject to the low-priced security or so called “penny stock” rules of the SEC that impose additional sales practice requirements on broker/dealers who sell such securities. Some of such requirements are discussed below.

A broker/dealer selling “penny stocks” must, at least two business (2) days prior to effecting a customer’s first transaction in a “penny stock,” provide the customer with a document containing information mandated by the SEC regarding the risks of investing in our stock, and the broker/dealer must receive a signed and dated written acknowledgement of the customer’s receipt of that document prior to effecting a customer’s first transaction in a “penny stock.”

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Subject to limited exceptions, a broker/dealer must obtain information from a customer concerning the customer’s financial situation, investment experience and investment objectives and, based on the information and any other information known by the broker/dealer, the broker/dealer must reasonably determine that transactions in “penny stocks” are suitable for the customer, that the customer has sufficient knowledge and experience in financial matters, and that the customer reasonably may be expected to be capable of evaluating the risks of transactions in “penny stocks.” A broker/dealer must, at least two business (2) days prior to effecting a customer’s first purchase of a “penny stock” send a statement of this determination, together with other disclosures required by the SEC, to the customer, and the broker/dealer must receive a signed and dated copy of the statement prior to effecting the customer’s first purchase of a “penny stock.”

A broker/dealer must also, orally or in writing, disclose prior to effecting a customer’s transaction in a “penny stock” (and thereafter confirm in writing):

·

the bid and offer price quotes in and for the “penny stock,” and the number of shares to which the quoted prices apply;

·

the brokerage firm’s compensation for the trade; and

·

the compensation received by the brokerage firm’s sales person for the trade.

In addition, subject to limited exceptions, a brokerage firm must send to its customers trading in “penny stocks” a monthly account statement that gives an estimate of the value of each “penny stock” in the customer’s account.  Accordingly, the Commission’s rules may limit the number of potential purchasers of the shares of our common stock.

Resale restrictions on transferring “penny stocks” are sometimes imposed by some states, which may make transaction in our stock more difficult and may reduce the value of the investment. Various state securities laws pose restrictions on transferring “penny stocks” and as a result, investors in our common stock may have the ability to sell their shares of our common stock impaired.

 

There can be no assurance we will have market makers in our stock. If the number of market makers in our stock should decline, the liquidity of our common stock could be impaired, not only in the number of shares of common stock which could be bought and sold, but also through possible delays in the timing of transactions, and lower prices for the common stock than might otherwise prevail. Furthermore, the lack of market makers could result in persons being unable to buy or sell shares of the common stock on any secondary market.

We have never paid dividends on our common stock.

We have never paid dividends on our common stock and do not presently intend to pay any dividends in the foreseeable future. We anticipate that any funds available for payment of dividends will be re-invested into the Company to further its business strategy.

We may issue preferred stock.

Our Articles of Incorporation authorizes the issuance of up to 5,000,000 shares of blank check preferred stock with designations, rights and preferences determined from time to time by the Board of Directors. Accordingly, our Board of Directors is empowered, without stockholder approval, to issue preferred stock with dividend, liquidation, conversion, voting, or other rights which could adversely affect the voting power or other rights of the holders of the common stock. In the event of issuance, the preferred stock could be utilized, under certain circumstances, as a method of discouraging, delaying or preventing a change in control of the Company. Although we have no present intention to issue any shares of its authorized preferred stock, there can be no assurance that the Company will not do so in the future.

Any trading market that may develop may be restricted by virtue of state securities “Blue Sky” laws which prohibit trading absent compliance with individual state laws. These restrictions may make it difficult or impossible for our security holders to sell shares of our common stock in those states.

There is no public market for our common stock, and there can be no assurance that any public market will develop in the foreseeable future. Transfer of our common stock may also be restricted under the securities regulations and laws promulgated by various states and foreign jurisdictions, commonly referred to as “Blue Sky” laws. Absent compliance with such individual state laws, our common stock may not be traded in such jurisdictions. Because the securities registered hereunder have not been registered for resale under the Blue Sky laws of any state, the holders of such shares and persons who desire to purchase them in any trading market that might develop in the future, should be aware that there may be significant state Blue Sky law restrictions upon the ability of investors to sell the securities and of purchasers to purchase the securities. These restrictions prohibit the secondary trading of our common stock.

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MANAGEMENT AND EXECUTIVE COMPENSATION

Executive Officers and Directors

Radiant’s directors and executive officers are:

Name	Age	Position
John M. Jurasin	53	Director, Chief Executive Officer, Chief Financial Officer and Chairman of the Board
Robert M. Gray	52	Director and Vice President - Land
Timothy N. McCauley	39	Vice President - Engineering and Exploratory Drilling
Arthur Thomas McCarroll	58	Vice President – Exploration
George R. Jarkesy, Jr.	35	Director
Brian Rodriquez	40	Director and Treasurer

Mr. Jurasin has served as the chairman, chief executive officer, chief financial officer and president of Jurasin since 1990, and of Radiant since August 2010.  Prior to establishing Jurasin, Mr. Jurasin was employed by Getty Oil Company, McMoRan Oil & Gas and Taylor Energy. Mr. Jurasin attended graduate classes in Economic Geology at the University of Arizona and completed Undergraduate studies in Geology at Rutgers University in New Jersey. Mr. Jurasin’s affiliations include The New Orleans Geological Society (past committee chair, member since 1980), the Lafayette Geological Society, the Society of Independent Professional Earth Scientists, member since 1987 (certified as a Professional Earth Scientist #1961), the American Association of Petroleum Geologists, member since 1984, recruited into the Division of Professional Affairs(DPA), member since 1990, and duly certified as a "certified petroleum geologist" # 4284 within the organization, the Dallas Geological Society, the Southern Geophysical Society and the American Petroleum Institute.

Mr. Gray has served as Land Manager for Jurasin since December 2007, and Director and Vice-President of Land of Radiant since August 2010.  Prior to Jurasin, Mr. Gray served as Land Manager for Americo Energy Resources, LLC since March 2007.  From 1998 until 2006, Mr. Gray was a consulting oil and gas Land Manager.  Mr. Gray received his degree from the University of Texas.  Mr. Gray is a member of the American Association of Professional Landmen, Houston Association of Professional Landmen, West Houston Association of Professional Landmen and Pioneer Oil Producers Society.  In addition, Mr. Gray was involved in Coastal Conservation Association – Former West Houston Chapter Executive Board Member, Fort Bend County Municipal Utility District No. 111 Board – Former Assistant Secretary/Treasurer (Elected Public Official) 1993 – 1998 and is a member of the board of the Texas Alpha Endowment Fund, Inc

Mr. McCauley has served as Vice President – Engineering and Exploratory Drilling since April 2009, and of Radiant since August 2010.  From 2008 to 2009, Mr. McCauley was the engineering manager for AGR Turn Key Drilling.  From 2005 through 2008, Mr. McCauley was a drilling engineer and a drilling manager for Applied Drilling Technology.  Mr. McCauley received his bachelor’s degree in petroleum engineering in 1996 from Texas A&M University. Mr. McCauley is a member of the Society of Petroleum Engineers, International Association of Drilling Contractors and Houston Sport and Social.

Mr. McCarroll has served as the Vice President - Exploration since May 2009, and of Radiant since August 2010.  From 2007 to 2009, Mr. McCarroll was vice president for Patriot Exploration.  From 2002 through 2007, Mr. McCarroll was vice president for Cheyenne Petroleum Company.  Mr. McCarroll received his bachelor in geology from the Louisiana State University and his masters in management from Stanford University  Mr. McCarroll is a  Certified Petroleum Geologist (CPG #4663), member of API, AAPG, Houston Geological Society (former member of the Executive Board), and Houston Geophysical Society.

Mr. Jarkesy has served as a director of the Company since April 2010.  Mr. Jarkesy has been engaged in the private equity and investment business for over five years, and currently serves as the managing member of John Thomas Capital Management Group, LLC, which has been the general partner for John Thomas Bridge & Opportunity Fund, L.P. since June 2007.  Mr. Jarkesy previously served as the chief operating officer and president of SH Celera Capital Corporation, an internally managed fund from March 2007 until March 2008.  Mr. Jarkesy has founded and built companies engaged in financial consulting, real estate investments, real estate management, employee leasing, light steel manufacturing, livestock management, oil field services and biotechnology during the last ten years.  Mr. Jarkesy has served as a director of America West Resources, Inc. since 2008.

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Mr. Rodriguez has served as a director since 2006, an executive officer of Radiant from 2006 through August 2010, and as president of Marathon Advisors LLC, a professional services firm providing accounting and business development services to micro-cap and small-cap companies for over five years. Mr. Rodriguez has served as interim chief financial officer of America West Resources, Inc., a publicly-held domestic coal mining company, during 2008 and during the period October 2009 to the present.  Since December 2007, Mr. Rodriguez has served on the board of directors of America West Resources.  From March 2006 through May 2007, Mr. Rodriguez served as chief financial officer of SH Celera Capital Corporation, an internally managed fund.  He served as an accounting and finance consultant for Jefferson Wells from October 2004 to the present. From March 2002 to October 2005, Mr. Rodriguez served as controller and then director of finance for JP Mobile, Inc., a privately held wireless software company based in Dallas. Mr. Rodriguez has been a Certified Public Accountant in the State of Texas since 1995.

Board Composition; Independence of Directors & Board Committees; Code of Ethics

The Company’s board of directors consists of four members, and Mr. Jurasin has a right to nominate and appoint an additional director, provided that a majority of the existing board members approve.  There are no family relationships between any of the Company’s officers and directors.  

The Company does not have any “independent directors” as that term is defined under independence standards used by any national securities exchange or an inter-dealer quotation system. The board of directors has not established any committees and, accordingly, the board of directors serves as the audit, compensation, and nomination committee.

Our Company has adopted a Code of Ethics governing the conduct of our executive officers.

Employment Agreements

The Company has entered into employment agreements with Robert M. Gray, John M. Jurasin, Arthur Thomas McCarroll, Allen W. Hobbs and Timothy N. McCauley.  

Pursuant to Mr. Gray’s employment agreement, he serves as the Company’s Vice President – Land, his annual salary is $125,000, and he was issued options to purchase 279,000 shares of the Company’s common stock at an exercise price of $.50 per share, which shall vest equally over the next three years.  

Pursuant to Mr. Jurasin’s employment agreement, he serves as the Company’s Chief Executive Officer and President and his annual salary is $200,000, which will be increased to $250,000 upon the Company receiving $10,000,000 in equity or debt financing and $300,000 upon the Company becoming cash flow positive.  

Pursuant to Mr. McCarroll’s employment agreement, he serves as Vice President – Exploration, his annual salary is $175,000, he is entitled to cash bonuses of $25,000 upon the funding of $3,600,000 and an additional $25,000 upon the funding of an additional $3,000,000, and was issued options to purchase 325,400 shares of the Company’s common stock at an exercise price of $.50 per share, which shall vest equally over the next three years.  

Pursuant to Mr. Hobbs’s employment agreement, he serves as the Company’s controller, his annual salary is $100,000, and he was issued options to purchase 93,000 shares of the Company’s common stock at an exercise price of $.50 per share, which shall vest equally over the next three years.  

Pursuant to Mr. McCauley’s employment agreement, he serves as the Company’s Vice President – Engineering and Exploration Drilling, his annual salary is $145,000, and he was issued options to purchase 597,243 shares of the Company’s common stock at an exercise price of $.50 per share, which shall vest equally over the next three years.  

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Summary Compensation Table

Name and Principal Position	Year	Salary ($)	Bonus ($)	Option Awards ($)	Other Compensation ($)	Total ($)
Brian Rodriguez (1)	2009	-0-	-0-	-0-	$22,500 (2)	$22,500
	2008	-0-	-0-	-0-	$114,750 (3)	$114,750
John M. Jurasin(4)	2009	$234,000	-0-	-0-	-0-	$234,000
	2008	$461,875	-0-	-0-	-0-	$461,875
Mark Witt(5)	2009	-0-	-0-	-0-	-0-	-0-
	2008	-0-	-0-	-0-	-0-	-0-
Robert M. Gray(6)	2009	$151,225	-0-	-0-	-0-	$151,225
	2008	$142,586	-0-	-0-	-0-	$142,586
Allen W. Hobbs(7)	2009	$104,400	-0-	-0-	-0-	$104,400
	2008	$68,200	-0-	-0-	-0-	$68,200
Jay King(8)	2009	$163,333	-0-	-0-	-0-	$163,333
	2008	$89,015	-0-	-0-	-0-	$89,015

(1)  Mr. Rodriguez served as Radiant’s chief executive officer in 2008 and 2009.

(2)  In March 2009, Mr. Rodriguez received 45,000 shares of our common stock as consideration for serving as a director and executive officer.

(3)  In February 2008, Brian Rodriguez received 45,000 shares of our common stock as consideration for serving as a director and executive officer.

(4) John M. Jurasin served as Jurasin’s chief executive officer and director in 2008 and 2009.

(5)  Mark Witt served as Jurasin’s chief financial officer in 2008 and 2009.

(6)  Robert M. Gray served as Jurasin’s Land Manager in 2008 and 2009.

(7)  Allen W. Hobbs served as Jurasin’s controller in 2008 and 2009.

(8)  Jay King served as Jurasin’s chief geologist in 2008 and 2009.

Outstanding Equity Awards at Fiscal Year-End Table

No options have been issued to our executive officers, other than as disclosed in “Employment Agreements” above.

Director Compensation

Our directors were not compensated for their services during 2009, other than as reflected in the “Summary Compensation Table” above.  

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STOCK OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information regarding beneficial ownership of our common stock as of August 5, 2010 (i) by each person who is known by us to beneficially own more than 5% of our common stock, (ii) by each of our named executive officers and directors, and (iii) by all of our executive officers and directors as a group.  The number of shares beneficially owned by each director or executive officer is determined under rules of the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose.  Under the SEC rules, beneficial ownership includes any shares as to which the individual has the sole or shared voting power or investment power. In addition, beneficial ownership includes any shares that the individual has the right to acquire within 60 days. Unless otherwise indicated, each person listed below has sole investment and voting power (or shares such powers with his or her spouse). In certain instances, the number of shares listed includes (in addition to shares owned directly), shares held by the spouse or children of the person, or by a trust or estate of which the person is a trustee or an executor or in which the person may have a beneficial interest.  As of August 5, 2010, there were 22,171,614 shares of common stock outstanding.

Name and Address of Owner	Number of Shares Owned	Percentage
John Thomas Bridge & Opportunity Fund, L.P. (1)	4,180,876	19%
John Thomas Financial, Inc. (2)	6,000,000	27%
Named Executive Officers and Directors:
John M. Jurasin (3)	9,013,535	41%
Brian Rodriguez(4)	262,653	1%
George R. Jarkesy, Jr. (5)	4,389,968	20%
Robert M. Gray (6)	150,000	*
Timothy N. McCauley(7)	428,131	2%
Arthur Thomas McCarroll (8)	150,000	*
Allen W. Hobbs(9)	41,667	*
Jay King	--	--
Mark Witt	--	--
All Executive Officers and Directors as a Group (6 persons)	14,394,287	65%

*

Less than one percent

(1)

The address for John Thomas Bridge & Opportunity Fund, L.P. (“Fund”) is 3 Riverway, Suite 1800, Houston, Texas 77056. The Fund is a limited partnership, and the John Thomas Capital Management Group, LLC is the general partner of the Fund (“GP”). George Jarkesy is the managing member of the GP.  Mr. Jarkesy and the GP may be deemed to have beneficial ownership of the securities reported herein.  

(2)

The address is 14 Wall Street, 5^th floor, New York, New York 10005.  Thomas Belesis is the President and sole shareholder of John Thomas Financial.  

(3)

The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042.  Does not include 1,802,708 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements.

(4)

The address is 2202 Bluebonnet Drive, Richardson, Texas 75082.  Does not include 100,000 shares issuable to Mr. Rodriguez in June 2011 pursuant to his director’s agreement.

(5)

Consists of (i) 85,092 shares owned of record by Mr. Jarkesy, (ii) 4,180,865 shares owned by the Fund, and (iii) presently exercisable warrants to purchase 125,000 shares of common stock at an exercise price of $.50 per share owned by John Thomas Bridge & Opportunity Fund II, L.P. of which Mr. Jarkesy is the managing member of the general partner and Mr. Jarkesy and the general partner may be deemed to have beneficial ownership of the securities owned by this fund.

(6)

The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042.  Does not include (i) 30,000 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements, and (ii) an option to purchase 279,000 shares of our common stock at an exercise price of $.50 per shares and which vest equally over the next three years.

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(7)

The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042.  Does not include (i) 85,626 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements, and (ii) an option to purchase 597,243 shares of our common stock at an exercise price of $.50 per share and which vest equally over the next three years.

(8)

The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042.  Does not include (i) 30,000 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements, and (ii) an option to purchase 325,400 shares of our common stock at an exercise price of $.50 per shares and which vest equally over the next three years.

(9)

The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042.  Does not include (i) 3,333 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements, and (ii) an option to purchase 93,000 shares of our common stock at an exercise price of $.50 per shares and which vest equally over the next three years.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Related Persons

In December 2007, John Thomas Bridge and Opportunity Fund L.P. (an entity that Mr. Jarkesy is the managing member of its general partner) acquired a total of 3,680,865 common shares for nominal consideration.  As of December 31, 2008, we had outstanding loans from George Jarkesy totaling $5,000, plus $1,745 in accrued interest, and $11,902 in expenses had been paid by Mr. Jarkesy on behalf of the Company, representing an advance.  Mr. Jarkesy is the fund manager of the John Thomas Bridge & Opportunity Fund, the majority shareholder of the Company, and during the years ended 2008 and 2009, we borrowed an aggregate of $55,000 from John Thomas Bridge and Opportunity Fund, LP.  The notes accrued interest at 8% per annum and matured on December 31, 2009. In April 2010, John Thomas Bridge and Opportunity Fund and Mr. Jarkesy converted all of their outstanding notes (approximately $108,504) and contributed $8,000 for consideration of 500,000 shares of our common stock.  In connection with the Reorganization, John Thomas Bridge and Opportunity Fund, LP personally indemnified Jurasin and John Jurasin for any misrepresentations by Radiant up to $500,000.  In connection with the indemnification agreement, the Company agreed to pay John Thomas Bridge and Opportunity Fund, LP $250,000 upon the closing a minimum of $10,000,000 in debt or equity financing.  The John Thomas Bridge & Opportunity Fund II, L.P. (an entity that Mr. Jarkesy is the managing member of its general partner) purchased (i) $125,000 of debentures in August 2010, issued as part of the $600,000 of bridge financing that matures on the earlier of July 31, 2011 and the closing of $2,000,000 financing (to be partially prepaid with 30% of the gross proceeds from subsequent financings equaling and exceeding $500,000), and (ii) four-year warrants to purchase 125,000 shares of common stock (with piggy back registration rights for the underlying shares of common stock at a purchase price of $.50 per share).  Mr. Jarkesy acquired 85,092 shares during 2007 for nominal consideration.

In connection with the Reorganization, the Company issued Mr. Jurasin 9,013,535 shares of our common stock (plus an additional 1,802,708 shares of common stock subject to the satisfaction of vesting requirements) for his shares of the issued and outstanding common stock of Jurasin (originally issued for nominal consideration).  In addition, the Company issued Mr. Jurasin a note in the principal amount of $884,000, which accrues interest at 4% per annum and is payable in three years.  The Jurasin note shall be prepaid upon the Company raising at least $10,000,000.  Also in connection with the Reorganization, an additional $165,000, which has no formal repayment terms, is also due to Mr. Jurasin.  The note and payable were treated as a deemed dividend to Mr. Jurasin.  Prior to the Reorganization, Jurasin transferred the following interests for nominal consideration to entities owned and controlled by John Jurasin (collectively, the “Transferred Interests”): (i) Ensminger- overriding royalty interest equal to approximately 2.0% in and to certain leases contained within the geographic confines of the Ensminger #1 Planulina D Reservoir A Unit located in St. Mary Parish, Louisiana –as of the date hereof, there is no production attributable to this interest; (ii) Aquamarine-  overriding royalty interest of 0.85% in and to oil & gas lease, serial number OCS-G 23135, dated effective October 1, 2001, by and between the United States of America, as lessor, to Paragon Petroleum, Inc. and DDD Energy, Inc. as lessees, covering all of Block 758, Mustang Island Area, OCS Leasing Map, Texas Map No. 3, describing 5,760 acres, more or less - this interest is currently producing after having been shut-in from October 2008 through December 2008 and from March 2009 through July 2009; (iii) Coral/Ruby/Diamond- an approximately 1.35% before payout and 0.75% after payout overriding royalty interest covering certain lands located in Louisiana State Waters in St. Mary Parish, Louisiana-  there is no production attributable to this interest; (iv) any and all overriding royalties to which Jurasin may be entitled under that certain area of mutual interest agreement, Baldwin Prospects, St. Mary Parish, Louisiana, dated January 22, 2010, by and between Jurasin and J&S Oil & Gas, LLC, and covering certain lands located in St. Mary Parish, Louisiana- there is no production attributable to this interest; and (v) all working interest, overriding royalty interest, or any other interest in the following wells operated by Zenergy, Inc. in the Charenton Field, St. Mary Parish, Louisiana: 3 TEC #1-41,  3 TEC #2, 3 TEC #4, 3 TEC #5, 3 TEC #5 SWD, 3 TEC #8, 3 TEC #7, 3 TEC #9, 3 TEC #11 and 3 TEC #11-A - these interests do not exceed more than a 1.5% working interest and a net revenue interest (yielding in 2009 gross working interests of $23,308 and net revenue interest of $1,266).  For the quarter ended March 31, 2010, Jurasin did not earn any net profits from the Transferred Interests.  During the year ended December 31, 2009, Jurasin earned approximately $26,000 net profits from the Transferred Interests.  During the year ended December 31, 2008, Jurasin earned approximately $69,000 net profits from the Transferred Interests.

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In connection with the Reorganization, we issued Mr. Gray 150,000 shares of our common stock (plus an additional 30,000 shares of common stock subject to the satisfaction of vesting requirements), Mr. McCauley 428,131 shares of our shares of common stock (plus an additional 85,626 shares of common stock subject to the satisfaction of vesting requirements), Mr. McCarroll 150,000 shares of our common stock (plus an additional 30,000 shares of common stock subject to the satisfaction of vesting requirements), Mr. Hobbs 41,667 shares of our common stock (plus an additional 8,333 shares of common stock subject to the satisfaction of vesting requirements), and Barry Rava 200,000 shares of our common stock (plus an additional 40,000 shares of common stock subject to the satisfaction of vesting requirements), all in exchange for their respective shares in Jurasin pre-Reorganization and for nominal consideration.  We entered into a consulting agreement with Mr. Rava that provides that he will provide between 20 to 40 hours per week of assistance to the Company, will be paid $100 per hour, and he received an option to purchase 186,000 shares of common stock at an exercise price of $.50 per share, which shall vest equally over the next three years.

In connection with the Reorganization, the Company entered into a director’s agreement with Mr. Rodriguez, in which the Company agreed to pay Mr. Rodriguez $3,000 per month beginning in June 2010, and issue to Mr. Rodriguez 200,000 shares of Company common stock, of which 100,000 shares were issued upon the closing of the Reorganization and the remaining 100,000 shares will be issued in June 2011.  Mr. Rodriguez personally indemnified Jurasin and John Jurasin for any misrepresentations by Radiant in the Reorganization up to $50,000.  In connection with the indemnification agreement, the Company agreed to pay Mr. Rodriguez $25,000 prior to the payment of any cash bonus to any employee, officer or director.  Mr. Rodriguez acquired an aggregate of 162,653 shares of common stock during 2008, 2009 and 2010 for nominal consideration.

John Thomas Financial will provide investment banking services to the Company, and pursuant to an investment banking agreement, the Company will pay John Thomas Financial in connection with equity financings (excluding the first $2,000,000 of debt or equity raised, of which $600,000 has been raised to date) cash sales commissions of up to 10% of the gross proceeds, non-accountable expense allowances of up to 3% of the gross proceeds and five-year warrants to purchase one share of common stock for each ten shares of common stock (including common stock equivalents) sold in the Offering at a purchase price of 105% of the offering price; and in connection with debt financings (excluding the first $2,000,000 of debt or equity raised, of which $600,000 has been raised to date), a cash fee equal to 5% of the first $10,000,000 of debt financing, 4% of the next $10,000,000 of debt financing, 3% of the next $10,000,000 of debt financing, 2% of the next $10,000,000 of debt financing, and 1% in excess of $40,000,000 of debt financing.  In August 2010, the Company issued to John Thomas Financial 6,000,000 shares of common stock as additional consideration for entering into the investment banking agreement, and John Thomas Financial is entitled to receive $75,000 of expense reimbursement once $2,000,000 is raised in an offering (of which $600,000 has been raised to date).  We have been advised by John Thomas Bridge & Opportunity Fund L.P. that John Thomas Bridge & Opportunity Fund L.P. and John Thomas Financial are not affiliates of one another.  We have further been advised by John Thomas Bridge & Opportunity Fund as follows, with respect to the relationship between John Thomas Financial and John Thomas Bridge & Opportunity Fund:

(a)  Neither John Thomas Financial nor any of its affiliates has any direct or indirect ownership or management interest in John Thomas Bridge & Opportunity Fund L.P. or John Thomas Bridge & Opportunity Fund II, L.P.;

(b)  Neither John Thomas Bridge & Opportunity Fund L.P. nor any of its affiliates has any direct or indirect ownership or management interest in John Thomas Financial;

(c)  From time to time John Thomas Financial has served as placement agent for John Thomas Bridge & Opportunity Fund L.P. in connection with offers and sales of John Thomas Bridge & Opportunity Fund L.P. securities;

(d)  Pursuant to a placement agent agreement, dated as of July 19, 2007, between John Thomas Financial and John Thomas Bridge & Opportunity Fund L.P., John Thomas Bridge & Opportunity Fund L.P. has been granted a trademark license to use the name “John Thomas” and variants thereof in connection with, among other things, the operation of John Thomas Bridge & Opportunity Fund L.P.; and

(e)  John Thomas Financial from time to time receives compensation with respect to companies it introduces to John Thomas Bridge & Opportunity Fund L.P. and which obtain loans from John Thomas Bridge & Opportunity Fund L.P.

LEGAL PROCEEDINGS

 

Other than routine litigation arising in the ordinary course of business that we do not expect, individually or in the aggregate, to have a material adverse effect on us, there is no currently pending legal proceeding and, as far as we are aware, no governmental authority is contemplating any proceeding to which we are a party or to which any of our properties is subject.  However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters that may arise from time to time may harm our business.

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MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

Our common stock is quoted on the National Association of Securities Dealers, Inc. Over-the-Counter Electronic Bulletin Board under the symbol “ROGI.”  Before our recent name change, our stock was quoted under the symbol “GOBS.”  

The market for our common stock on the OTCBB is limited, sporadic and highly volatile.  The following table sets forth the approximate high and low bid quotations per share of our common stock on the OTCBB for the periods indicated.  The quotations reflect inter-dealer prices, without retail markups, markdowns, or commissions and may not represent actual transactions.  Additionally, our common stock quotations are prior to the Reorganization and therefore do not reflect the acquisition of Jurasin.  Investors should not rely on these historical price quotes as they are not reflective of our current business operations.  The closing price for our common stock as reported by the OTCBB on August 5, 2010 was $.60 per share.  All quotations give effect to our 1-for-5 reverse stock split effected on April 16, 2010.

Period	High		Low
Fiscal Year Ended December 31, 2008
Quarter ended March 31	$5.00		$1.00
Quarter ended June 30   Quarter ended September 30	$1.00 $1.00		$1.00 $1.00
Quarter ended December 31	$1.00		$1.00
Fiscal Year Ended December 31, 2009
Quarter ended March 31	$1.00		$0.50
Quarter ended June 30   Quarter ended September 30	$2.55 $2.55		$0.50 $0.60
Quarter ended December 31	$0.60		$0.60
Fiscal Year Ended December 31, 2010
Quarter ended March 31	$0.60		$0.60
Quarter ended June 30	$0.60		$0.60

Holders

 

We had 802 stockholders of record of our common stock as of August 5, 2010, not including an indeterminate number who may hold shares in “street name”.

 

Dividends

 

We have not paid any cash dividends to stockholders.  It is not expected that we will pay any cash dividends in the foreseeable future, and our Credit Facility precludes such action.

Securities Authorized For Issuance under Equity Compensation Plans

 

We did not have any compensation plan under which equity securities are authorized for issuance as of our most recent fiscal year.  In connection with the Reorganization, we have adopted the 2010 Stock Option Plan, for which we have reserved 6,000,000 shares of common stock for issuance thereunder.

RECENT SALES OF UNREGISTERED SECURITIES

See the information set forth in Item 3.02 of this Current Report on Form 8-K which is incorporated herein by reference.

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DESCRIPTION OF SECURITIES

The following summary description of Radiant’s securities is qualified in its entirety by reference to Radiant’s Articles of Incorporation and Bylaws.  The authorized capital stock of Radiant consists of 100,000,000 shares of common stock and 5,000,000 shares of preferred stock.

Common Stock

As of August 5, 2010, there were 22,171,614 shares of common stock issued and outstanding. Each holder of common stock is entitled to one vote per share on all matters submitted to a vote of stockholders. The holders of common stock are entitled to share ratably in such dividends as may be declared by the Board of Directors and paid by Radiant out of funds legally available therefore and, upon dissolution or liquidation, to share ratably in the net assets available for distribution to stockholders. Holders of common stock have no conversion, redemption or sinking fund, preemptive, cumulative voting or subscription rights. The shares of common stock presently issued and outstanding are legally issued, fully paid and non-assessable.

Preferred Stock

Radiant is authorized to issue 5,000,000 of blank check authorized preferred stock of which none are issued and outstanding and Radiant has no present plans for the issuance thereof.  Our board of directors has the authority, without action by our stockholders, to designate and issue preferred stock in one or more series.  Our board of directors may also designate the rights, preferences, and privileges of each series of preferred stock, any or all of which may be greater than the rights of the common stock.  It is not possible to state the actual effect of the issuance of any shares of preferred stock on the rights of holders of the common stock until the board of directors determines the specific rights of the holders of the preferred stock.  However, these effects might include:

·

restricting dividends on the common stock;

·

diluting the voting power of the common stock;

·

impairing the liquidation rights of the common stock; and

·

delaying or preventing a change in control without further action by the stockholders.

Outstanding Option or Warrants

There are no outstanding options or warrants other than ten-year option to purchase an aggregate of 1,574,243 shares of Company common stock at an exercise price of $.50 per share issued to our employees and warrants, which were issued to investors, to purchase an aggregate of 600,000 shares of Company common stock at an exercise price of $.50 per share that expire no later than July 2014.  

Transfer Agent

Our transfer agent is American Registrar & Transfer Company.

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INDEMNIFICATION OF OFFICERS AND DIRECTORS

As permitted by Nevada law, our Articles of Incorporation, as amended, provide that we will indemnify its directors and officers against expenses and liabilities as they are incurred to defend, settle, or satisfy any civil or criminal action brought against them on account of their being or having been Company directors or officers unless, in any such action, they are adjudged to have acted with gross negligence or willful misconduct.  Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the Company pursuant to the foregoing provisions, the Company has been informed that, in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in that Act and is, therefore, unenforceable.

WHERE YOU CAN OBTAIN ADDITIONAL INFORMATION

We have filed reports, proxy statements and other information with the U.S. Securities and Exchange Commission, or the SEC. You may read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.W., Washington, D.C. 20549. You may obtain information on the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains the reports, proxy statements and other information we file electronically with the SEC. The address of the SEC website is http://www.sec.gov.

Item 3.02

Unregistered Sales of Equity Securities

In December 2007, we issued 3,680,805 shares of Company common stock to John Thomas Bridge & Opportunity Fund L.P. for nominal consideration.

In December 2007, we issued 85,092 shares of Company common stock to George Jarkesy for nominal consideration.

In February 2008, we issued 45,000 shares of common stock to Brian Rodriguez and 27,653 shares of common stock to a consultant for services provided. The shares were valued at an aggregate of $178,500.

In March 2009, the Company issued Brian Rodriguez 45,000 shares of common stock for services rendered valued at $22,500.

In January 2010, we issued 45,000 shares of common stock to Brian Rodriguez for services rendered valued at $27,000.

In April 2010, we issued 500,000 shares of Company common stock to John Thomas Bridge & Opportunity Fund for approximately $116,500.

In July 2010, we issued 1,086,409 shares of common stock to a consultant for nominal consideration.

In August 2010, we issued 6,000,000 shares of common stock to an investment banker for nominal consideration.

In August 2010, we issued 10,000,000 shares of common stock to the Jurasin Shareholders (an additional 2,000,000 shares may be issued upon satisfaction of certain conditions) in connection with the Reorganization in exchange for shares of Jurasin common stock originally issued for nominal consideration.

In August 2010, we issued 100,000 shares of common stock to Mr. Rodriguez pursuant to his director’s agreement, such shares valued at nominal consideration.

In August 2010, we issued options to purchase 1,574,243 shares of Company common stock at an exercise price of $.50 per share to employees.

The issuance of the securities as described in this Item 3.02 were made to accredited investors and employees only in reliance upon an exemption from registration under Section 4(2) of the Securities Act.  The Company paid no sales commissions in connection with the sale of these securities.

Item 3.03

Material Modification to Rights of Security Holders

In August 2010, the Company initiated a 2-for-1 reverse split that is expected to become effective on or about August 24, 2010.  The Company will announce the effectiveness of this reverse split in a press release and on Form 8-K, and none of the share or per share data in this report give effect to this anticipated reverse common stock split.

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Item 5.01

Changes in Control of Registrant

As a result of the Reorganization, the Jurasin Shareholders acquired a majority of the equity interest in the Company.  The information set forth in Item 2.01 under the caption “Stock Ownership Of Certain Beneficial Owners and Management and Related Stockholder Matters” is incorporated into this Item 5.01 by reference.

Item 5.02

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

Pursuant to the terms of the Reorganization Agreement, our new directors and officers are as set forth therein. Reference is made to the disclosure set forth under Item 2.01 of this Current Report on Form 8-K, which disclosure is incorporated herein by reference.

Item 5.06   

Change in Shell Company Status

As a result of the consummation of the Reorganization described in Items 1.01 and 2.01 of this Current Report on Form 8-K, the Company believes that it is no longer a “shell corporation,” as that term is defined in Rule 405 of the Securities Act and Rule 12b-2 of the Exchange Act.

Item 9.01   

Financial Statements and Exhibits

(a)

 Financial Statements of Business Acquired

The Audited Financial Statements of Jurasin Oil & Gas, Inc. for the fiscal years ended December 31, 2009 and 2008 and the Unaudited Financial Statements of Jurasin Oil & Gas, Inc. for the quarter ended March 31, 2010 are filed as Exhibit 99.1 to this Current Report and incorporated herein by reference.

(b)

Pro Forma Financial Information

The Audited Pro Forma Financial Statements of the Company for the fiscal year ended December 31, 2009 and the Unaudited Pro Forma Financial Statements of the Company for the quarter ended March 31, 2010 are filed as Exhibit 99.2 to this Current Report and incorporated herein by reference.

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(d)

Exhibits

*  Filed herewith.

†  Management contract or compensatory plan arrangement.

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SIGNATURES

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

Dated: August 16, 2010

RADIANT OIL & GAS, INC.

/s/ John Jurasin

John Jurasin, Chief Executive Officer,

Principal Accounting Officer, and

Chief Financial Officer

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