United States

Securities and Exchange Commission

Washington, D. C. 20549

FORM 10-K

  x   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

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

For the transition period from __________________ to __________________

Commission File No. 000-24688

RADIANT OIL & GAS, INC.

(Name of Small Business Issuer in its Charter)

Nevada	27-2425368
(State or Other Jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

9700 Richmond Ave., Suite 124

 Houston, Texas 77042

(Address of Principal Executive Offices)

Issuer’s Telephone Number: (832) 242-6000

Securities registered under Section 12(b) of the Act: None

Name of Each Exchange on Which Registered: None

Securities registered under Section 12(g) of the Act:

$0.01 par value common stock

Title of Class

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 Yes o  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

 Yes o   No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (1)

 Yes x   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 Yes o   No x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 Yes o     No x

On June 30, 2013, the last business day of the registrant’s most recently completed second fiscal quarter 9,862,897 shares of its common stock, $0.001 par value per share were held by non-affiliates of the registrant. The market value of those shares was 11,342,331 based on the last sale price of $1.15 per share of the common stock on that date. For this purpose, shares of common stock beneficially owned by each executive officer and director of the registrant, and each person known to the registrant to be the  beneficial owner of 10% of more of the common stock then outstanding, have been excluded because such person may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

(APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS)

Not applicable.

(APPLICABLE ONLY TO CORPORATE ISSUERS)

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:

Common shares outstanding as of May 2, 2014: 14,735,023

DOCUMENTS INCORPORATED BY REFERENCE

A description of “Documents Incorporated by Reference” is contained in Part IV, Item 15 of this Report.

Table of Contents
PART 1
ITEM 1	DESCRIPTION OF BUSINESS	6
ITEM 1A	RISK FACTORS	14
ITEM 1B	UNRESOLVED STAFF COMMENTS	26
ITEM 2	PROPERTIES	26
ITEM 3	LEGAL PROCEEDINGS	28
ITEM 4	RESERVED	28
PART II
ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITES	29
ITEM 6	SELECTED FINANCIAL DATA	30
ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION	30
ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	37
ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCE DISCLOSURE	37
ITEM 9A	CONTROLS AND PROCEDURES	37
ITEM 9B	OTHER INFORMATION	38
PART III
ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	39
ITEM 11	EXECUTIVE COMPENSATION	41
ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	42
ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	43
ITEM 14	PRINCIPAL ACCONTING FEES AND SERVICES	44
PART IV
ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	45
SIGNATURES		46
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two dimensional, seismic.

 “Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil and other liquid hydrocarbons.

“Bcf” One billion cubic feet of natural gas.

“Behind Pipe” Reserves which are expected to be recovered from zones behind casing in existing wells, which require additional completion work or a future recompletion prior to the start of production.

“Boe” Barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Boepd” Boe per day.

“Bopd” Bbls per day.

“Btu” One British thermal unit.

“Completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

“Development Well” A well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

“Dry Hole” An exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

“Exploratory Well” A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

“Farm-in” An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

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

“Gross Wells” Total number of producing wells in which we have an interest.

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“Held By Production” or “HBP” A provision in an oil and gas lease that perpetuates a company’s right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas.

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

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

“Lease Operating Expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

“LLS” Light Louisiana Sweet crude oil, being a high quality low-sulfur content premium crude oil.

“MBbl” One thousand barrels of oil or other liquid hydrocarbons.

“MBoe” Thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MBoepd” Thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids per day.

“Mcf” One thousand cubic feet of natural gas.

“Mcfpd” Mcf per day.

“MMBbl” One million barrels of oil or other liquid hydrocarbons.

“MMBoe” Million barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMBtu” One million British Thermal Units.

“MMcf” One million cubic feet of natural gas.

“Net Acre” Fractional ownership working interest multiplied by gross acres. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

“Net Revenue Interest” A share of production after all burdens, such as royalty and overriding royalty, have been deducted from the working interest. It is the percentage of production that each party actually receives.

“Net Wells” The sum of our fractional interests owned in gross wells.

“NGLs” Natural gas liquids.

“NYMEX” The New York Mercantile Exchange.

“Overriding Royalty Interest” A right to receive revenues, created out of the working interest, from the production of oil and gas from a well free of obligation to pay any portion of the development or operating costs of the well and limited in life to the duration of the lease under which it is created.

“Pay” The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

“PDP” Proved developed producing.

“PDNP” Proved developed nonproducing.

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

“Possible Reserves” Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

“Probable Reserves” Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

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

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

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

“Proved Developed Non-Producing Reserves (PDNP)”  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods that are not currently being produced.

“Proved Developed Producing Reserves (PDP)” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and that are currently being produced.

“Proved Reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable from known reservoirs under current economic and operating conditions, operating methods, and government regulations.

“Proved Undeveloped Reserves (PUD)” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“PV-10” The discounted present value of the estimated future gross revenue to be generated from the production of proved oil and gas reserves (using pricing assumptions consistent with, and after deducting estimated abandonment costs to the extent required by, SEC guidelines), net of estimated future development and production costs, before income taxes and without giving effect to non-property related expense, discounted using an annual discount rate of 10% and calculated in a manner consistent with SEC guidelines.

“Recompletion” After the initial completion of a well, the action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity.

“Reserve Life” A measure of the productive life of an oil and gas property or a group of properties, expressed in years.

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

“Royalties” The portion of oil and gas retained by the lessor on execution of a lease or the cash value paid by the lessee to the lessor based on a percentage of the gross production from the leased property free and clear of all costs except taxes.

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“Sand” A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

“Shut-in” To close valves on a well so that it stops producing; said of a well on which the valves are closed.

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

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

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

“Working Interest” The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

“Workover” The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

“WTI” West Texas Intermediate crude oil, being light, sweet crude oil with high API gravity and low sulfur content used as a benchmark for U.S. crude oil refining and trading.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, that are subject to risks and uncertainties.  These statements involve known and unknown risks, uncertainties and other factors that may cause our results, performance or achievements to be materially different from any future results, performance or achievements express or implied by these forward-looking statements.  In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential,” and similar expressions intended to identify forward-looking statements.  All statements, other than historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the nature and amount thereof), business strategy and measures to implement strategy, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements.

These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management.  These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.

Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control.  In addition, management’s assumptions about future events may prove to be inaccurate.  Management cautions all readers that the forward-looking statements in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events or circumstances will occur.  Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K.  All forward-looking statements speak only as of the date of this Form 10-K.  We do not intend to publicly update or revise any forward-looking statement as a result of new information, future events or otherwise, except as required by law.  These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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ITEM 1.  DESCRIPTION OF OUR BUSINESS

Radiant Oil and Gas, Inc. (“Radiant” or “the Company”) is an independent oil and gas exploration and production company that operates in the Gulf Coast region of the United States of America, specifically, onshore in Louisiana, Mississippi and Texas and the state waters of Louisiana, USA. The Company also has the capacity to operate in the federal waters offshore Texas and Louisiana in the Gulf of Mexico.

In August 2010, Jurasin Oil and Gas, Inc. (“JOG”) completed a reverse acquisition transaction (“Reorganization”) through an exchange agreement with the Company, whereby the Company acquired 100% of JOG’s issued and outstanding capital stock in exchange for 5,000,000 shares of the Company’s common stock.  The agreement provides for the issuance of up to an additional 1,000,000 shares of the Company’s common stock upon the satisfaction of certain performance conditions. The performance conditions have been met and 500,000 of the additional shares have been issued.

As a result of the reverse acquisition, JOG became the Company’s wholly-owned subsidiary and the former stockholders of JOG became the controlling stockholders of Radiant. The share exchange with Radiant was treated as a reverse acquisition, with JOG as the accounting acquirer and Radiant as the acquired party.

In March 2012 and June 2012, the Company entered into a joint venture agreement (“Shallow Oil Project”) with Grand Synergy Petroleum, LLC (“Grand”) and Black Gold Inc. (“Black Gold”), respectively. As a result of an agreement with Grand, two new Louisiana entities were formed, Charenton Oil Company, LLC (“Charenton”) on May 8, 2012 and Radiant Synergy Operating, LLC (“Synergy”) on June 28, 2012. Charenton is a wholly owned subsidiary of Radiant and Synergy is owned 50% by Radiant and 50 % by Grand.

Acquisitions and Financing

On October 9, 2013, the Company completed the purchase of oil and gas properties located in Louisiana and Mississippi for approximately $18,000,000 (“Vidalia”). The acquired properties contain over eighty (80) wells in Louisiana and Mississippi.  The Louisiana properties include over 39 wells and numerous leases located in Concordia, and La Salle Parishes. The Mississippi properties include over 41 wells and numerous leases located in Adams, Amite, Franklin and Wilkinson Counties. At the time of acquisition, the properties included up to 30 productive wells and up to 38 shut-in wells that have been evaluated for work-over and behind pipe opportunities which are expected to provide for cost-effective near-term production increases.

Effective October 4, 2013, the Company, through its wholly-owned subsidiary Radiant Acquisitions 1, LLC (“Radiant Acquisitions”), entered into a First Lien Credit Agreement (the “Credit Agreement”) with various financial institutions (the “Lenders”).  The maximum aggregate commitment of the Lenders to advance loans under this Agreement was $39,788,000, and the maximum aggregate principal amount to be repaid by the Borrower in respect thereof is $40,600,000 and for any given loan, the amount of funds advanced by any Lender shall be ninety-eight percent (98%) of the amount of principal required to be repaid by the Borrower in respect of such Loan.  The Credit Agreement has an original stated maturity date of September 2018.  As part of the amendment, the maturity date was extended to December 2018.  The outstanding principal balance of the Loans (as may have been advanced from time to time) bears interest at a per annum rate of twelve percent (12%).  Any outstanding indebtedness from the Credit Agreement was collateralized by substantially all of the assets of Radiant Acquisitions. In addition, the Company pledged its ownership interest in Radiant Acquisitions and executed a parent company guaranty as additional security.  The Credit Facility contains restrictive financial covenants.  The proceeds from the Credit Agreement were used to fund the closing of its recent acquisition of oil and gas properties located in  Louisiana and Mississippi, as well as to develop multiple re-entry, work-over and drilling opportunities on acquired acreage throughout south Louisiana and Mississippi.

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Core Areas of Operation and Certain Key Properties

Our proved oil and gas reserves are concentrated in the fields in the Louisiana Gulf Coast region. The fields tend to have stacked multiple producing horizons with production typically between 3,000 and 13,000 feet. Some of the fields have numerous available wellbores capable of providing workover and recompletion opportunities. We expect the characteristics of these fields to allow us to record significant proved behind pipe and PUD reserves in each annual year-end and mid-year reserve report. At August 1, 2013, our net proved developed producing, or PDP, reserves of 522.2 Mbbls of oil represented 9.3% of our 5,621.2 Mboe of total proved oil and natural gas reserves, our proved developed non-producing, or PDNP, reserves of 208.1 Mbbls were 3.7% of our total proved oil and natural gas reserves and our net proved undeveloped, or PUD, reserves of 4,890.9 Mboe were 87.0% of our total proved oil and natural gas reserves of 6,126.3Mboe. We sell substantially all of our current hydrocarbon production in the St. James market and receive premium Light Louisiana Sweet (LLS) pricing.

Type of Reserves	December 31, 2013		Mboe			December 31, 2012		Mboe
PDP		377.9		6.3	%		400.9		6.7	%
PDNP		121.6		2.0	%		121.6		2.0	%
PUD		5,472.4		91.7	%		5,472.4		91.3	%
Total		5,971.9		100.0	%		5,994.9		100.0	%

Properties

Vidalia

In October 2013, Radiant acquired the Vidalia properties, which include numerous leases in Concordia, and La Salle parishes in Louisiana and Adams, Amite, Franklin and Wilkinson counties in Mississippi.  We have an average working interest in these properties of 97.2% and an average net revenue interest of 72.4%.

The acquired leases represent 3,500 gross acres (2,964 net) and over 80 wells.  Productive zones range from 3,000 feet to 8,600 feet. The capital plan for Vidalia includes continued spending on work-over activity and drilling of PUD locations. When acquired, Vidalia had 24 productive wells and numerous shut in locations.  To date, we have worked over 18 wells, creating a total of 23 wells capable of production.  We intend to continue working on our wells with spending expected to continue through 2014.

Ensminger Project

The Company had a minority interest in a well (Ensminger #1) drilled on this prospect. The lease was abandoned in 2011 and agreements with participants in this prospect area expired in mid-2012. Between 2005 to 2007, the Ensminger #1 well produced from the lower Planulina 69 Sand at a maximum productive rate of 10.4 MMCF/D and 205 BO/D, with what we estimate to be cumulative production of over 3.25 BCF and 49 MBO (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 MMCF/D and 11 BO/D 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 MMCF/D. 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.

During the fourth quarter of 2013, the Company acquired a lease for materially the same area as the area leased and exploited in 2005 to 2007. The Ensminger Project covers 634 acres, in which we own a 100.0% working interest and have a net revenue interest of 75.0%.

We have developed a plan to side-track out of an existing well thereby saving on drilling costs. The Ensminger Project is located onshore in sugar cane fields in St. Mary Parish, Louisiana. The original Ensminger well (“Ensminger #1”), which we intend to side-track, was originally funded by management and was drilled in 2004 in partnership with Exxon Mobil Corp. and Century Exploration New Orleans, Inc. and it discovered a depletion-drive field from the Planulina Pay Sands at approximately 15,000’ Total Vertical Depth.

The estimated net cost to drill and complete the proposed sidetrack is $2.9 million.

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Coral Project

During fourth quarter 2013, The Company was a high bidder on two leases in this area covering approximately 1,405 acres. We have a 100% working interest and a 76.0% net revenue interest in the Coral Project. We intend to act as the operator of this project to re-enter and complete a well. Coral consists of 1,405 gross acres in shallow Louisiana state coastal waters of St. Mary Parish.

The Coral Project is a multiple well prospect in an old Shell Oil Company field, which has produced 509 BCF and 65 MMBO. The prospect includes drilling in a new fault block extension of the Eugene Island Block 18 field. The primary objective is the geopressured Tex. W. sands which have produced 103 BCF and 2.8 MMBC in the field proper. Three Tex W sands, ranging in depths from 12,300 feet to 12,800 feet are the specific prospect targets. The initial proposed well will be a re-entry from the inactive COCKRELL #1 SL 14354 borehole. The estimated net cost to re-enter and complete the proposed well is $3.4 million.

The secondary objective in the Coral Project 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. We do not expect to drill to the Cib Op in 2014 unless we are able to sell a portion of our interest and significantly reduce or eliminate our capital requirement.

Our Business Strategy

We intend to become a leading independent oil and gas producer by using our industry expertise and in-depth regional experience to increase reserves, production and cash flow. Key elements to our strategy include:

Focus on Mature Fields with Existing Infrastructure. We currently have in excess of 7,000 Gulf Coast region net acres held by production or under direct leasehold. Our primary focus is on the re-development of existing fields with substantial historical production and relatively low cost of entry.

Exploitation and Development of Our Properties. We will continue to focus on the development and exploration efforts in our Gulf Coast properties, which we recently acquired. We believe that our properties will allow us to grow through low-risk, in-fill and side-track drilling programs that present attractive opportunities to expand our reserve base and through workovers and recompletions, field extensions, delineating deeper formations within existing fields. We also intend to increase our acreage position in those areas in which we currently operate.

Pursue Opportunistic Acquisitions of Underdeveloped Properties. We intend to continually review opportunities to acquire producing properties that include significant drilling prospects in our core operating areas and throughout the Gulf Coast region. We will continue to evaluate acquisition opportunities that we believe will further enhance our operations and reserves in a cost-effective manner.

Actively Manage Our Drilling Program. Our strategy is to increase our oil and natural gas reserves and production while carefully managing the development and operating costs associated with our current and future production. We expect to implement this strategy through drilling relatively low-cost wells and actively managing our contractors and service providers.

Utilize Our Industry and Technological Expertise. On average, each member of our management team has over 30 years of experience in the oil and gas industry. The technical expertise of our management team has led to the discovery of over 300.0 million barrels of oil equivalent of new discoveries during the course of their collective careers. We employ technical advancements, including 3-D seismic data, pre-stack depth and reverse-time migration, to identify and exploit new opportunities in our asset base. We also employ the latest directional drilling, completion and stimulation technology in our wells to enhance recoverability and accelerate cash flows.

2014 Budget. For 2014, we have targeted an initial capital budget of approximately $14.0 million to $20.0 million (including dry-hole costs), primarily focused on our Vidalia, Ensminger, Shallow Oil and Coral field projects. The capital program will include several maintenance projects in addition to field exploitation within Vidalia. Approximately $8.0 million will be expended in the first half of 2014. Success on these programs will provide cash flow and availability under our credit facility to conduct a drilling program across several fields in the second half of 2014.

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Competition

We compete against other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. Our ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We believe that our expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus an oil-quality differential and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions.

Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production in Mississippi and Louisiana. We take an active role in determining the available pipeline alternatives for each property based on historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.

Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is subject to extensive regulation by federal, state and local authorities. Legislation affecting the oil and natural gas industry is frequently amended or reinterpreted, and may increase the regulatory burden on our industry and our company. In addition, numerous federal and state agencies are authorized by statute to issue rules, regulations and policies that are binding on the oil and natural gas industry and its individual participants. Some of these rules and regulations authorize the imposition of substantial penalties for failures to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, our profitability. However, this regulatory burden generally does not affect us any differently or to a greater or lesser extent than it affects other companies in the oil and natural gas industry with similar types, quantities and locations of oil and natural gas production.

Regulation of Sales and Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, the United States Congress, or Congress, could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates must be just and reasonable and may not be unduly discriminatory or confer undue preference upon any shipper. Rates generally are cost-based, although rates may be market-based or may be the result of settlement, if agreed to by all shippers. Some oil pipeline rates may be increased pursuant to an indexing methodology, whereby the pipeline may increase its rates up to a prescribed ceiling that changes annually based on the change from year to year in the Producer Price Index for Finished Goods. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

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Regulation of Sales, Transportation and Gathering of Natural Gas

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978 and regulations enacted under those statutes by the FERC. The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. In general, the interstate pipelines’ traditional roles as wholesalers of natural gas have been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open-access basis to others who buy and sell natural gas. Although the FERC’s orders generally do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. Failure to comply with the FERC’s regulations, policies and orders may result in substantial penalties. Under the Energy Policy Act of 2005, the FERC has civil authority under the NGA to impose penalties for violations of up to $1 million per day per violation.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the pro-competitive regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that intrastate natural gas transportation in the states in which we operate will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Gathering, which is distinct from transportation, is regulated by state regulatory authorities and is not subject to regulation by the FERC. Under certain circumstances, the FERC will reclassify jurisdictional transportation facilities as non-jurisdictional gathering facilities. This reclassification tends to increase our costs of getting natural gas to point-of-sale locations.

Regulation of Production

The production of oil and natural gas is subject to and affected by regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling of wells, drilling bonds and reports concerning operations. Each of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing and the plugging and abandonment of wells. The effect of these regulations may be to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Environmental Matters and Other Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

·   require the acquisition of various permits before drilling commences;

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

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

·   require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the United States Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

 The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently exempted from regulation under RCRA or state hazardous waste provisions, though our operations may produce waste that does not fall within this exemption. However, these oil and gas production wastes may be regulated as solid waste under state law or RCRA. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at or under them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed substances and wastes or released petroleum, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

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Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant to OPA impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

Air Emissions

The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides and hydrogen sulfide.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes, the EPA had adopted regulations under existing provisions of the Federal Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and also could trigger permit review for GHG emissions from certain stationary sources. The EPA has asserted that the motor vehicle GHG emission standards triggered Federal Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA published its final rule to address the permitting of GHG emissions from stationary sources under the prevention of significant deterioration, or PSD, and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHGs that have yet to be developed. With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore oil and natural gas production activities, which may include certain of our operations. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption and implementation of any legislation or regulations imposing reporting obligations with respect to, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

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National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species, Wetlands and Damages to Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize or disclose information about hazardous materials stored, used or produced in our operations.

Private Lawsuits

In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas or oil and gas wastes has occurred, private parties or landowners may bring lawsuits against oil and gas companies under state law. The plaintiffs may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated property, soil, groundwater or surface water. In some cases, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.

Employees

As of May 7, 2014, we had 5 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.

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ITEM 1A.  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.

For the period reported within this 10-K, both as the Successor and the Predecessor, the Company generated nominal oil and gas revenues within each period.  Combined with the Company’s operating expenses, the Company generated cumulative operating losses over the reported periods.  It should be expected that we will continue to experience operating losses at least through 2014. There can be no assurance that we will ever achieve net income from operations or otherwise become profitable.

We may 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 may continue at least through 2014. There can be no assurance that we will ever be able to raise sufficient capital to generate positive cash flow from operations.

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

Our subsidiaries Amber Energy, LLC (“AE”) and Rampant Lion Energy, LLC (“RLE”) both have secured credit facilities with Macquarie Bank Ltd. (“MBL”). All of the RLE and AE assets secure the Credit Facility. As of December 31, 2013, the outstanding balance on its RLE Credit Facility was $818,309.  Accrued interest related to this credit facility amounted to $367,757 and $-0- as of December 31, 2013 and 2012, respectively. The Credit Facility matured in September 2011. As of December 31, 2013, the Company had the outstanding balance on its AE of $2,032,188. Accrued interest related to this credit facility amounted to $413,829 as of December 31, 2013. The Credit Facility matured in September 2011.

As of the date of this filing, there are substantially no assets remaining in AE and RLE and we are working with MBL to settle all outstanding amounts owed to MBL.

Failure to retire or refinance either the AE Credit Facility or the RLE Credit Facility could adversely affect our financial condition.

We do not have sufficient funds to repay the AE Credit Facility and the RLE Credit Facility which are now in default. 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 AE Credit Facility or the RLE Credit Facility would adversely affect the Company and could cause us to curtail operations. MBL has been working with management on these issues.

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.

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 conditions in the credit market and debt and equity capital market at the time 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.

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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 make payments on and to refinance our indebtedness and to fund planned capital expenditures and development efforts will depend on 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 cash flow generated from our operations and drilling programs, 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;

·   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 our various debt instruments.

Risks Related to Our Business

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;

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·   Domestic and foreign governmental regulations;

·   Level of global oil and natural gas inventories;

·   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 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.

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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;

·   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.

The nature and age of our wells may result in fluctuations in our production resulting from mechanical failures and other factors.

The majority of our recently acquired wells has been in operation and has produced for many years. As a result of the age of those wells, they typically experience higher maintenance requirements than newer wells. As a result, some of our wells may periodically be shut-in to perform maintenance or to restore optimal production levels or as a result of maintenance by third parties that operate facilities that serve our wells. Due to the periodic need to shut-in wells, we experience routine fluctuations in production levels with production declining below normal operating capacity during periods of maintenance. Further, we sometimes experience delays in identifying and addressing production declines.

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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.

Our offshore operations, when and should they commence, 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.

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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. While we do serve as operator on substantially all of our recently acquired properties and planned development prospects, we can provide no assurance that will always be the case in the future. 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.

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.

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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.

Climate change legislation, regulation and litigation could materially adversely affect us.

 There is an increased focus by local, state and national regulatory bodies on greenhouse gas (“GHG”) emissions and climate change. GHGs are certain gases, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes.  Various regulatory bodies have announced their intent to regulate GHG emissions, including the United States Environmental Protection Agency, which promulgated several GHG regulations in 2010 and late 2009. As these regulations are under development or are being challenged in the courts, we are unable to predict the total impact of these potential regulations upon our business, and it is possible that we could face increases in operating costs in order to comply with GHG emission legislation.

 Passage of legislation or regulations that regulate or restrict emissions of GHG, or GHG-related litigation instituted against us, could result in direct costs to us and could also result in changes to the consumption and demand for natural gas and carbon dioxide produced from our oil and natural gas properties, any of which could have a material adverse effect on our business, financial position, results of operations and prospects.

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

In conjunction with the closing of the Credit Agreement, we entered into hedges on the acquired producing properties and we believe we will continue to enter into hedges in the future, and may be required to do so in the future. On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act regulates derivative transactions, which include certain instruments used in some risk management activities we may consider using in the future.

The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a CFTC- or SEC-registered clearing facility and executed on a designated exchange or swap execution facility.

Among the other provisions of the Dodd-Frank Act that may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants; establishment of business conduct standards, recordkeeping and reporting requirements; and imposition of position limits.

The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.

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.” We do not currently anticipate decommissioning any facilities within the next year.  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.

Risks Related to Our Acquisition Strategy

Our acquisitions may be stretching our existing resources.

We recently acquired our principal properties in October 2013 and may make acquisitions in the future. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely intensify these risks.

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 is 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:

·   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;

·   diverting financial resources away from existing operations;

·   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.

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.

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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 officer and chairman of the board, John Jurasin. The loss of the services of this key employee 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. Furthermore, we have and may continue to issue equity incentives, including stock options, to attract key personnel which may be dilutive to our stockholders and negatively affect our stock price. 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. To mitigate this risk, the Company has entered into an employment agreement with Mr. Jurasin, and will periodically monitor and adjust such contracts as necessary.

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.  Moreover, any such sales may be dilutive to our existing stockholders.

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 Pink OTC Market, Inc. 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.”

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”.

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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 for the foreseeable future any funds available for payment of dividends will be re-invested into the Company to further its business strategy.

Because the public market for shares of our common stock is limited, investors may be unable to resell their shares.

Currently, there is only a limited public trading market for our common stock on the “pink sheets” and investors may be unable to resell their shares of our common stock. The development of an active public trading market depends upon the existence of willing buyers and sellers who are able to sell their shares as well as market makers willing to create a market in such shares.  Under these circumstances, the market bid and ask prices for the shares may be significantly influenced by the decisions of the market makers to buy or sell the shares for their own account.  Such decisions of the market makers may be critical for the establishment and maintenance of a liquid public market in our common stock.  Market makers are not required to maintain a continuous two-sided market and are free to withdraw firm quotations at any time.  We cannot give you any assurance that an active public trading market for the shares will develop or be sustained.

The price of our common stock is volatile, which may cause investment losses for our stockholders.

The market for our common stock has the potential to be highly volatile, having ranged in the last twelve months from a low of $0.75 to a high of $1.15 on the “pink sheets.”  The trading price of our common stock on the “pink sheets” is subject to wide fluctuations in response to, among other things, the limited number of shares traded, and general economic and market conditions.  In addition, statements or changes in opinions, ratings, or earnings estimates made by brokerage firms or industry analysts relating to our market or relating to us could result in an immediate and adverse effect on the market price of our common stock.  The highly volatile nature of our stock price may cause investment losses for our stockholders.  In the past, securities class action litigation has often been brought against companies following periods of volatility in the market price of their securities.  If securities class action litigation is brought against us, such litigation could result in substantial costs while diverting management’s attention and resources.

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Securities analysts may elect not to report on our common stock or may issue negative reports that adversely affect the price of our common stock.

At this time, no securities analyst provides research coverage of our common stock.  Further, securities analysts may never provide this coverage in the future.  Rules mandated by the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and other restrictions led to a number of fundamental changes in how analysts are reviewed and compensated.  In particular, many investment banking firms are required to contract with independent financial analysts for their stock research.  It may remain difficult for a company with a smaller market capitalization such as ours to attract independent financial analysts that will cover our common stock.  If securities analysts do not cover our common stock, the lack of research coverage may adversely affect our actual and potential market price and trading volume.

If one or more analysts elect to cover us and then downgrade our common stock, the stock price would likely decline rapidly.  If one or more of these analysts cease coverage of us, we could lose visibility in the market, which in turn could cause our stock price to decline.  This could have a negative effect on the market price of our shares.

Directors, executive officers and principal stockholders own a significant percentage of our capital stock, and they may make decisions that you do not consider to be in the best interests of our stockholders.

As of May 1, 2014, our directors, executive officers and principal stockholders beneficially owned, in the aggregate, approximately 78.8% of our outstanding voting securities.  As a result, if some or all of them acted together, they would have the ability to exert substantial influence over the election of our Board of Directors and the outcome of issues requiring approval by our stockholders.  This concentration of ownership also may have the effect of delaying or preventing a change in control of the Company that may be favored by other stockholders.  This could prevent transactions in which stockholders might otherwise recover a premium for their shares over current market prices.

Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and operating results.

If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act regarding internal control over financial reporting or to remedy any material weaknesses in our internal controls that we may identify, such failure could result in material misstatements in our financial statements, cause investors to lose confidence in our reported financial information and have a negative effect on the trading price of our common shares.

 Pursuant to Section 404 of the Sarbanes-Oxley Act and current SEC regulations, we are required to prepare assessments regarding internal controls over financial reporting.  In connection with our on-going assessment of the effectiveness of our internal control over financial reporting, we may discover “material weaknesses” in our internal controls as defined in standards established by the Public Company Accounting Oversight Board, or the PCAOB.  A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.  The PCAOB defines “significant deficiency” as a deficiency that results in more than a remote likelihood that a misstatement of the financial statements that is more than inconsequential will not be prevented or detected.  We determined that our disclosure controls and procedures over financial reporting are not effective and were not effective as of December 31, 2013 and 2012.

The process of designing and implementing effective internal controls is a continuous effort that requires us to anticipate and react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain a system of internal controls that is adequate to satisfy our reporting obligations as a public company.  We cannot assure you that we will implement and maintain adequate controls over our financial process and reporting in the future or that the measures we will take will remediate any material weaknesses that we may identify in the future.

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Our failure to timely file certain periodic reports with the SEC poses significant risks to our business, each of which could materially and adversely affect our financial condition and results of operations.

We failed to timely file our Annual Reports on Form 10-K for the fiscal years ended December 31, 2013, December 31, 2012 and 2011 and our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011, June 30, 2011, September 30, 2011, March 31, 2012, June 30, 2012, September 30, 2012, March 31, 2013, June 30, 2013 and September 30, 2013. Consequently, we were not compliant with the periodic reporting requirements under the Exchange Act.  Our failure to timely file those and possibly future periodic reports with the SEC could subject us to enforcement action by the SEC and shareholder lawsuits. Any of these events could materially and adversely affect our financial condition and results of operations and our ability to register with the SEC public offerings of our securities for our benefit or the benefit of our security holders.  Additionally, our failure to file our past periodic reports and future periodic reports has resulted in and could result in investors not receiving adequate information regarding the Company with which to make investment decisions.

We do not expect to be able to access the public U.S. capital markets until all of its periodic reporting with the SEC is up to date.

We will be unable to register our common stock with the SEC to access the U.S. public securities markets until we have filed its prior periodic reports and financial statements with the SEC. This precludes us from raising debt or equity financing in registered transactions in the U.S. public capital markets to support growth in its business plan.

Our common stock is quoted on the OTC “pink sheets” market which does not provide investors with a meaningful degree of liquidity.

Bid quotations for our common stock are available on the OTC “pink sheets,” an electronic quotation service for securities traded over-the-counter. Bid quotations on the pink sheets can be sporadic and the pink sheets do not provide any meaningful liquidity to investors. An investor may find it difficult to dispose of shares or obtain accurate quotations as to the market value of the common stock. There can be no assurance that our common stock will be listed on a national exchange such as The NASDAQ Stock Market, the New York Stock Exchange or another securities exchange once we become current in our filing obligations with the SEC.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

Vidalia

In October 2013, Radiant acquired the Vidalia properties, which include numerous leases in Catahoula, Concordia, La Salle and St. Mary’s parishes in Louisiana and Adams, Franklin and Wilkinson counties in Mississippi.  We have an average working interest in these properties of 97.2% and an average net revenue interest of 72.4%.

The acquired leases represent about 3,500 gross acres (2,964 net acres) and over 80 wells.   The Louisiana properties include over 39 wells and numerous leases located in Concordia and La Salle Parishes. The Mississippi properties include over 41 wells and numerous leases located in Adams, Amite, Franklin, and Wilkinson Counties. The properties include up to 30 productive wells and up to 38 shut-in wells that have been evaluated for work-over and behind pipe opportunities which are expected to provide for cost-effective near-term production increases.

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Ensminger Project

The Company had a minority interest in a well (Ensminger #1) drilled on this prospect. The lease was abandoned in 2011 and agreements with participants in this prospect area expired in mid-2012. Between 2005 to 2007, the Ensminger #1 well produced from the lower Planulina 69 Sand at a maximum productive rate of 10.4 MMCF/D and 205 BO/D, with what we estimate to be cumulative production of over 3.25 BCF and 49 MBO (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 MMCF/D and 11 BO/D 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 MMCF/D. 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.

During fourth quarter 2013, the Company has acquired a lease for materially the same area as the area leased and exploited in 2005 to 2007. The Ensminger Project covers 634 acres, in which we own a 100.0% working interest and have a net revenue interest of 75.0%.

We have developed a plan to side-track out of an existing well thereby saving on drilling costs. The Ensminger Project is located onshore in sugar cane fields in St. Mary Parish, Louisiana. The original Ensminger well (“Ensminger #1”), which we intend to side-track, was originally funded by management and was drilled in 2004 in partnership with Exxon Mobil Corp. and Century Exploration New Orleans, Inc. and it discovered a depletion-drive field from the Planulina Pay Sands at approximately 15,000’ Total Vertical Depth.

The estimated net cost to drill and complete the proposed sidetrack is $2.9 million.

Coral Project

All four leases comprising this prospect expired in 2011.

During fourth quarter 2013, The Company was a high bidder on two leases in this area covering approximately 1,405 acres. We have a 100% working interest and a 76.0% net revenue interest in the Coral Project. We intend to act as the operator of this project to re-enter and complete a well. Coral consists of 1,405 gross acres in shallow Louisiana state coastal waters of St. Mary Parish.

The Coral Project is a multiple well prospect in an old Shell Oil Company field, which has produced 509 BCF and 65 MMBO. The prospect includes drilling in a new fault block extension of the Eugene Island Block 18 field. The primary objectives are the geopressured Tex. W. sands which have produced 103 BCF and 2.8 MMBC in the field proper. Three Tex W sands, ranging in depths from 12,300 feet to 12,800 feet are the specific prospect targets. The initial proposed well will be a re-entry from the inactive COCKRELL #1 SL 14354 borehole. The estimated net cost to drill and complete the proposed sidetrack is $3.4 million.

The secondary objective in the Coral Project 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 feet. The prospect is covered with 3-D seismic. We do not expect to drill to the Cib Op in 2014 unless we are able to sell a portion of our interest and significantly reduce or eliminate our capital requirement.

Acreage Data

As of December 31, 2013, we controlled approximately in excess of 7,000 Gulf Coast region net acres held by production or in primary term.

General

Our principal place of business is at 9700 Richmond Avenue, Suite 124, Houston, Texas 77042. The Company leases its office space on a month-to-month basis.

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ITEM 3.  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 material 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.

ITEM 4.  RESERVED

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PART II

ITEM 5.  MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is quoted on the Pink OTC Market, Inc. under the symbol “ROGI.”  The market for our common stock on the Pink OTC Market, Inc. is limited, sporadic and potentially highly volatile.  The following table sets forth the approximate high and low bid quotations per share of our common stock on the Pink OTC Market for the periods indicated.  The closing price of our common stock on December 31, 2013 was $1.04.  The quotations reflect inter-dealer prices, without retail markups, markdowns, or commissions and may not represent actual transactions.

Period	High		Low
Fiscal Year Ended December 31, 2013
Quarter ended March 31	$	1.15	$	1.15
Quarter ended June 30	$	1.15	$	1.15
Quarter ended September 30	$	1.15	$	0.75
Quarter ended December 31	$	1.04	$	1.04
Fiscal Year Ended December 31, 2012
Quarter ended March 31	$	1.75	$	1.50
Quarter ended June 30	$	1.50	$	0.26
Quarter ended September 30	$	0.26	$	0.10
Quarter ended December 31	$	1.15	$	0.10

Holders of Record

We had 960 stockholders of record of our common stock as of May 2, 2014 not including an indeterminate number who may hold shares in “street name.”

Dividend Policy

We have never paid dividends on our common stock.  We currently intend to retain all earnings to fund our operations. Therefore we do not intend to pay any cash dividends on the common stock in the foreseeable future.  

Securities Authorized For Issuance under Equity Compensation Plans

 In connection with the Reorganization, we have adopted the 2010 Stock Option Plan, for which we have reserved 3,000,000 shares of common stock for issuance thereunder. As of April 30, 2014, there were 1,658,071 stock options issued and outstanding.

Recent Sale of Unregistered Securities

Other than described below, all securities sold by us during the fiscal years ended December 31, 2013 that were not registered under the Securities Act were previously disclosed in our quarterly reports on Form 10-Q or our current reports on Form 8-K.

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In August 2013, we entered into a Bridge Loan Agreement with various individuals whereby we borrowed $600,000, and also issued to the note holder warrants to purchase 1,500,000 shares of our common stock at a purchase price of $0.01 per share.

In February 2013, the Company received $100,000 from a third party investor for the sale of 86,956 shares of common stock at a price of $1.15 per share and warrants to purchase additional 86,956 shares of common stock at a price of $1.16. Warrants expire on February 21, 2016.

In January and February 2013, the Company received $90,000 from Black Gold in accordance with the Shallow Oil agreement, in which $45,000 was for the sale of common stock (see Note 2 - Oil & Gas Properties). In accordance with provisions of Shallow Oil agreement, the Company issued 90,000 shares of its stock to Black Gold at a price of $0.50 per share.

We issued all of these securities to persons who were either “accredited investors,” or “sophisticated investors” who, by reason of education, business acumen, experience or other factors, were fully capable of evaluating the risks and merits of an investment in our company; and each had prior access to all material information about us. We believe that the offer and sale of these securities were exempt from the registration requirements of the Securities Act, pursuant to Sections 4(2) and 4(6) thereof, and Rule 506 of Regulation D of the Securities and Exchange Commission and from various similar state exemptions. No sales commissions were paid in connection with such issuances.

ITEM 6.  SELECTED FINANCIAL DATA

Not Required.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. This discussion contains forward-looking statements that involve risks, uncertainties and assumptions. See “Note Regarding Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors discussed in “Risk Factors” and elsewhere in this report.

Overview

We are an independent oil and gas exploration and production company that operates in the Gulf Coast region of the United States of America, specifically, onshore and the state waters of Louisiana, USA and the federal waters offshore Texas in the Gulf of Mexico.  We currently have oil and gas lease interests throughout Louisiana and Mississippi.

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Results of Operations

Effective October 9, 2013, the Company acquired oil and gas properties located in Louisiana and Mississippi (the “Vidalia Properties”). Successor references herein are referring to the consolidated information pertaining to the Company and its wholly owned subsidiaries and investments in which the Company has exclusive control. Predecessor references herein relate to the operations of the Vidalia Properties.

The Company has presented the Statement of Operations for the period of October 9, 2013 through December 31, 2013 for Successor, January 1, 2013 through October 8, 2013 for Predecessor and the year ended December 31, 2012 for Predecessor. For comparison purposes, the Predecessor and Successor were combined for the year ended December 31, 2013 as follows:

RADIANT OIL AND GAS, INC.

Consolidated Statements of Operations

	Successor			Predecessor			Pro Forma
	For the Period from October 9, 2013 to December 31, 2013			For the Period from January 1, 2013 to October 8, 2013			For the Year Ended December 31, 2013
OIL AND GAS REVENUES	$	696,661		$	1,742,512		$	2,439,173
OPERATING EXPENSES:
Lease operating expenses		483,680			2,355,118			2,838,798
Depreciation, depletion, amortization and accretion		60,950			28,659			89,609
General and administrative expense		1,158,032			-			1,158,032
TOTAL OPERATING EXPENSES		1,702,662			2,383,777			4,086,439
OPERATING LOSS		(1,006,001	)		(641,265	)		(1,647,266	)
OTHER INCOME (EXPENSE):
Unrealized loss on stock and warrant derivative liabilities		(1,192,523	)		-			(1,192,523	)
Unrealized gain on commodity derivative		146,420			-			146,420
Interest expense		(1,664,342	)		-			(1,664,342	)
Other income and expense, net		19,375			-			19,375
Total other expense		(2,691,070	)		-			(2,691,070	)
NET LOSS	$	(3,697,071	)	$	(641,265	)	$	(4,338,336	)

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Oil and gas revenues for the year ended December 31, 2013 decreased by $1,526,844 or 38.5% compared to the year ended December 31, 2012. This decrease was due to shut down of various wells during 2013 that were producing in 2012. The Company is currently undertaking an effort to work over these wells in order to bring them back to producing status.

Lease operating expenses for the year ended December 31, 2013 decreased by $921,639 or 24.5% compared to the year ended December 31, 2012. This decrease was due to shut down of various wells during 2013 that were producing in 2012. The Company is currently undertaking an effort to work over these wells in order to bring them back to producing status.

Depreciation, depletion and amortization expense for the year ended December 31, 2013 was $52,254 compared to $-0- for the year ended December 31, 2012. No information other than revenue and lease operating expenses is available to Radiant regarding Predecessor operations during the year ended December 31, 2012.

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Accretion expense for the year ended December 31, 2013 was $37,355 compared to $-0- for the year ended December 31, 2012. No information other than revenue and lease operating expenses is available to Radiant regarding Predecessor operations during the year ended December 31, 2012.

General and administrative expenses for the year ended December 31, 2013 was $1,158,032 compared to $-0- for the year ended December 31, 2012. No information other than revenue and lease operating expenses is available to Radiant regarding Predecessor operations during 2012.

The net loss on derivative liabilities for the year ended December 31, 2013 was $1,046,103, which included a gain on commodity derivative of $146,420, compared to $-0-  for the year ended December 31, 2012. No information other than revenue and lease operating expenses is available to Radiant regarding Predecessor operations during 2012.

Interest expense for the year ended December 31, 2013 was $1,664,342 compared to $-0- for the year ended December 31, 2012. No information other than revenue and lease operating expenses is available to Radiant regarding Predecessor operations during 2012.

Other income for the year ended December 31, 2013 was $19,375 compared to $-0- for the year ended December 31, 2012. No information other than revenue and lease operating expenses is available to Radiant regarding Predecessor operations during 2012.

The above mentioned factors resulted in a net loss for the year ended December 31, 2013 of $4,338,336 compared to net income of $205,580 for the year ended December 31, 2012.

Liquidity and Capital Resources

At December 31, 2013, we have current assets of $3,831,067 current liabilities of $9,645,574, and a working capital deficit of $5,814,507.  

At December 31, 2013 and 2012, our cash and cash equivalents balance was $1,019,582 and $-0-, respectively. As of December 31, 2013 and 2012, restricted cash balance was $2,067,225 and $-0-, respectively.

In late 2013, we, through our wholly-owned subsidiary Radiant Acquisitions 1, LLC (“Radiant Acquisitions”), entered into a First Lien Credit Agreement (the “Credit Agreement”) with various financial institutions (the “Lenders”).  The maximum aggregate commitment of the Lenders to advance loans under this Agreement was $39,788,000, and the maximum aggregate principal amount to be repaid by the Borrower in respect thereof is $40,600,000 and for any given loan, the amount of funds advanced by any Lender shall be ninety-eight percent (98%) of the amount of principal required to be repaid by the Borrower in respect of such Loan.  The proceeds from the Credit Agreement were used to fund the closing of our recent acquisition of oil and gas properties located in Louisiana and Mississippi, as well as to develop multiple re­ entry, work-over and drilling opportunities on acquired acreage throughout south Louisiana and Mississippi.

Concurrent with the closing of the Credit Agreement, a total of $27,050,428 was disbursed to acquire the Vidalia Properties.  The Lenders have the right to approve future draw requests made by the Company.

We have significant cash requirements over the next twelve months and anticipate that our cash and cash equivalents balances in conjunction with advances under the Credit Agreement will substantially allow us to meet these requirements.

We intend to raise additional funds through public or private sale of our equity or debt securities, borrowing funds from private or institutional lenders, the sale of our interests in certain oil and gas properties, or farm out of oil and gas interests.  If we raise additional funds through the issuance of debt securities, these securities would have rights that are senior to holders of our common stock and could contain covenants that restrict our operations. Any additional equity financing would likely be substantially dilutive to our stockholders, particularly given the prices at which our common stock has been recently trading. In addition, if we raise additional funds through the sale of equity securities, new investors could have rights superior to our existing stockholders. This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity.

If we raise funds through a farm-out or sale of any of our rights, we may be required to relinquish, on terms that are not favorable to us, our interests in those projects.  Our need to raise capital soon may require us to accept terms that may harm our business or be disadvantageous to our current stockholders, particularly in light of the current illiquidity. There can be no assurance that we will be successful in obtaining additional funding, or selling or farming-out assets, in sufficient amounts or on terms acceptable to us, if at all.

If we are unable to raise sufficient additional funds when needed, we would be required to further reduce operating expenses by, among other things, curtailing significantly or delaying or eliminating part or all of our operations and properties.

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Our ability to obtain additional financing is dependent on the state of the debt and/or equity markets, and such markets’ reception of us and our offering terms. In addition, our ability to obtain financing may be dependent on the status of our oil and gas exploration activities, which cannot be predicted. There is no assurance that capital in any form will be available to us, and if available, that it will be on terms and conditions that are acceptable.

Consolidated Statements of Cash Flows Data

	October 9, 2013 to December 31, 2013 (Successor)			January 1, 2013 to October 8, 2013 (Predecessor)			Year Ended December 31, 2013 (Pro Forma)
Net cash used in operating activities	$	(1,438,290	)	$	(539,282	)	$	(1,977,572	)
Net cash used in investing activities		(18,247,675	)		-			(18,247,675	)
Net cash provided by financing activities		20,588,447			539,282			21,127,729

Cash Used in Operating Activities

Net cash used in operating activities was $1,977,572 for the year ended December 31, 2013 compared to net cash provided by operating activities of $291,611 for the year ended December 31, 2012. In 2013, the Company used its cash mostly to fund its operations related to newly acquired oil & gas properties as well as other overhead expenses.

Cash Used in Investing Activities

For the year ended December 31, 2013, net cash used in investing activities of $18,247,675 was the result of the purchase of oil and gas properties amounting to $16,153,522 and purchase of equipment amounting to $26,928.

For the year ended December 31, 2012, there was no cash used in investing activities.

Cash Provided by Financing Activities

For the year ended December 31, 2013, net cash provided by financing activities of $21,127,729 was primarily attributable to borrowings on notes payable, amounting to $27,525,947 and proceeds from issuance of common stock of $750,000 offset by payments on notes payable and deferred financing costs amounting to $6,445,065.

For the year ended December 31, 2012, there was no cash used in financing activities.

Off-Balance Sheet Arrangements

For the period of October 9, 2013 through December 31, 2013, the period from January 1, 2013 to October 8, 2013 and the year ended December 31, 2012, the Company did not have any off-balance sheet arrangements.

Related Party Transactions

Patriot Agreement

On December 28, 2013, the Company entered into an agreement (the “Patriot Agreement”) with Patriot Bridge & Opportunity Fund, L.P. (f/k/a John Thomas Bridge & Opportunity Fund, L.P.) and Patriot Bridge & Opportunity Fund II, L.P., together referred to as the “Funds,” Patriot 28, LLC, the Managing Member of the Funds, and George Jarkesy, individually and as Managing Member of Patriot 28. The Patriot 28 Agreement restructured the outstanding $150,000 due to the Funds in the form of general liability promissory note. The maturity date of the Note shall be the earlier of an equity infusion of not less than ten million ($10,000,000) dollars or December 1, 2014. Interests shall be paid monthly at the rate of six percent (6%) per annum.

To the extent any payments are not made timely in accordance with the repayment schedule described in the Patriot 28 Agreement, the Company shall issue 500 shares of Company stock to Fund I and 500 shares of Company stock to Fund II for each default occurrence. This provision does not apply if the Company cures its default within ten (10) days following receipt of written notice that a payment has not been timely made.

The Company, upon execution and delivery of the Patriot Agreement, paid to the Funds the sum of $15,000 in reimbursement for all legal fees and expenses of the Funds related to the Loan and the January 1, 2014 payment for $14,115.

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Critical Accounting Policies

We prepare our consolidated financial statements in accordance with generally accepted accounting principles of the United States (“U.S. GAAP”).  U.S. GAAP represents a comprehensive set of accounting and disclosure rules and requirements.  The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.  We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis of making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates under different assumptions or conditions, however, in the past the estimates and assumptions have been materially accurate and have not required any significant changes. Should we experience significant changes in the estimates or assumptions that would cause a material change to the amounts used in the preparation of our financial statements, material quantitative information will be made available to investors as soon as it is reasonably available.

We believe the following critical accounting policies, among others, affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

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. The Company bases its 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. The Company’s estimates include estimates of oil reserves, future cash flows from oil properties, depreciation, depletion, amortization, impairment of oil properties, asset retirement obligations, and calculations related to stock and warrant derivative liabilities and commodity derivative instruments.. 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.

Cash and Cash Equivalents

Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value. The Company and its subsidiaries maintain its cash in institutions insured by the Federal Deposit Insurance Corporation (FDIC), which insures the balances up to $250,000 per depositor.

Concentrations

Financial instruments which potentially subject us to concentrations of credit risk consist of cash. We periodically evaluate the credit worthiness of financial institutions, and maintain cash accounts only with major financial institutions thereby minimizing exposure for deposits in excess of federally insured amounts. We believe that credit risk associated with cash is remote.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are reflected at net realizable value. The Company establishes provisions for losses on accounts receivable if the Company determines that the Company will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Substantially all of accounts receivable balance relates to the most recent crude oil revenue sales.

Deferred Financing Charges

Deferred finance charges consist of legal and other fees incurred in connection with the issuance of notes payable and are capitalized and shown in the consolidated balance sheets. These charges are being amortized using the effective interest method over the term of the related notes.

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Property and Equipment

Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset: furniture and fixtures - 7 years; vehicles - 5 years; computer equipment and software - 3 to 5 years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. The Company performs ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting, as prescribed by the United States Securities and Exchange Commission (“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 full cost pool. 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 the Company determines 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. The Company evaluates unevaluated properties for inclusion in the amortization base at least annually.  The Company assesses properties on an individual basis, or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.

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.

The Company includes its 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 the Company directly owns. The Company calculates the depletion and net book value of the assets based on the full cost pool’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, 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.

Impairment of Long-Lived Assets

The Company periodically reviews non-oil and gas long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. The Company recognizes an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value.

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Asset Retirement Obligation

The Company records 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. The Company records an asset retirement obligation to reflect its legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. The Company estimates the expected cash flow associated with the obligation and discounts the amount using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates 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), the Company will accordingly update its assessment.  Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.

Derivative Financial Instruments

For derivative financial instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then re-valued at each reporting date, with changes in the fair value reported as charges or credits to non-operating income. For warrants and convertible derivative financial instruments, the Company uses the Black-Scholes model to value the derivative instruments at inception and subsequent valuation dates. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period, in accordance with FASB ASC Topic 815, Derivatives and Hedging. Derivative instrument liabilities are classified in the balance sheet as current or non-current based on whether or not net-cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

Revenue Recognition

The Company recognizes revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenues, and recognizes 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 the Company has an imbalance on a specific property greater than the expected remaining proved reserves.

Income Taxes

The Company accounts for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

FASB ASC-740 establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. In periods when losses are reported, the diluted weighted-average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive.

 Recent Accounting Pronouncements

The Company does not expect the adoption of recently issued accounting pronouncements to have a significant impact on its results of operations, financial position or cash flows.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK

Not required under Regulation S-K for “smaller reporting companies.”

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

The information required by this item appears beginning on page F-1 following the signature page of this Report

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On April 7, 2014, (the “Dismissal Date”), the Board of Directors of Radiant Oil & Gas, Inc. (“Radiant Oil & Gas” or the “Company”) voted to dismiss Malone Bailey (“MB”), terminating its relationship as the Registrant’s independent registered public accounting firm.

MB had been engaged by the Company to audit the balance sheet of the Company as of December 31, 2012 and December 31, 2011, and related statements of operations, stockholders’ equity, and cash flows for the years then ended, and had performed reviews of ROGI 2013 Form 10-Q filings.  None of MB’s reports on the Registrant’s financial statements during this period (a) contained an adverse opinion or disclaimer of opinion, or (b) was modified as to uncertainty, audit scope, or accounting principles, or (c) contained any disagreements on any matters of accounting principles or practices, financial statements disclosure, or auditing scope or procedures, which disagreements if not resolved to the satisfaction of MB, would have caused it to make reference to the subject matter of the disagreements in connection with its reports.  None of the reportable events set forth in Item 304(a)(1)(IV) OF regulation S-K occurred during the period in which MB served as the Registrant’s principal independent accountants.

However, while the reports of MB on the financial statements of the Registrant for the years ended December 31, 2012 and 2011 did not contain any adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles, the reports indicated that there was a substantial doubt as to the Registrant’s ability to continue as a going concern and that the financial statements did not include any adjustments that might result from the outcome of this uncertainty.

On April 7, 2014, the Company announced that its Audit Committee of the Board of Directors appointed GBH CPAs, PC (“GBH”) as the Company’s independent registered public accounting firm.  GBH replaced MB.  The change in auditors was not due to any disagreement between the Company and MB on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedures.  The appointment of GBH was effective immediately.  In deciding to select GBH, the Audit Committee reviewed auditor independence issues and existing commercial relationships with GBH and concluded that GBH had no commercial relationship with the Company that would impair its independence for the two most recent fiscal years and through the date of GBH’s engagement.  During the Company’s two most recent fiscal years and the subsequent interim periods through April 7, 2014, the Company did not consult GBH with respect to any of the matters or events listed in Regulation S-K Item 304(a)(2).

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the year ended December 31, 2013 covered by this Form 10-K. Based upon such evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures were not effective as required under Rules 13a-15(e) and 15d-15(e) under the Exchange Act.

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Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of the fiscal year ended December 31, 2013. In making this assessment, we utilized the criteria set forth in Internal Control—Integrated Framework and the Internal Control over Financial Reporting – Guidance for Smaller Public Companies both issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). A material weakness is a deficiency or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Based on the evaluation, we concluded that our disclosure controls and procedures were not effective and we have identified the following material weaknesses.  These material weaknesses affected our ability to make our periodic SEC compliance filings within the prescribed time periods.

Due to a lack of adequate systems, processes, and resources with sufficient GAAP knowledge, experience, and training, we did not maintain effective controls over day-to-day accounting and financial reporting obligations as well as the period-end financial close and reporting processes as of December 31, 2013.  Due to the actual and potential effect on financial statement balances and disclosures and the importance of the financial closing and reporting processes, we concluded that, in the aggregate, these deficiencies constituted a material weakness in our internal control over financial reporting.  The specific deficiencies contributing to the material weakness were as follows:

a)	Inadequate segregation of duties.  In various accounting processes, applications and systems we did not design, establish and maintain procedures and controls to adequately segregate job responsibilities for initiating, authorizing and recording transactions, nor were there adequate mitigating or monitoring controls in place.
b)	Inadequate policies and procedures.  We did not design, establish and maintain effective GAAP compliant financial accounting policies and procedures.
c)	Inadequate personnel.  We had a lack of experienced personnel with relevant accounting experience, due in part to our limited financial resources.

Changes in Internal Control over Financial Reporting

There were no changes made to our internal control over financial reporting since our last filing for the quarterly period from September 30 2013 through December 31, 2013, nor were any changes made to our internal control over financial reporting from January 1, 2014 through the date of this report.  We will continue to monitor and evaluate the effectiveness of our internal controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow we will remediate material weaknesses. We have engaged additional subject matter experts to assist in the development of the needed financial and operational accounting processes, procedures, as well as manpower resources in conjunction with our expanded operations in the fourth quarter of 2013 and 2014.

Limitations on the Effectiveness of Controls

The Company’s management, including the CEO and CFO, does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all error and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of the control system must reflect that there are resource constraints and that the benefits must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls effectiveness to future periods are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, OFFICERS AND CORPORATE GOVERNANCE

As of May 6, 2014, the Company’s directors and executive officers are:

Name	Age	Position
John M. Jurasin	58	Director, Chief Executive Officer, and Chairman of the Board
C. Scott Wilson	61	Chief Financial Officer

Mr. Jurasin has over 30 years of experience in the oil and gas business and has served as the chairman, chief executive officer, chief financial officer and president of JOG since 1990 and of Radiant since August 2010. Prior to establishing JOG, 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. Jurasin’s day-to-day leadership of JOG prior to the Reorganization provides him with detailed strategic perspective and knowledge of our planned operations and industry that are critical to the Board’s effectiveness. Mr. Jurasin’s specific experience, qualifications, attributes and skills described above led the Board to conclude that Mr. Jurasin should serve as our Chairman and member of the Board of Directors.

Mr. Wilson has more than 35 years of financial services experience focused on the energy sector, including work with oil and gas producers, gathering and transportation pipelines, refineries, and oilfield service providers. He has served as President, CEO and director of a public oil and gas company, and as chief financial officer for privately-held oilfield service and oil and gas producing companies where his responsibilities included equity and debt sourcing, financial forecasting, cash management, SEC and financial reporting, and strategic planning. Through his consulting practice, Mr. Wilson has worked with small-cap oilfield service and upstream producing companies and energy focused financial institutions on restructuring, asset divestment and business development strategies.  Prior to his corporate experience, he held senior-level positions at Sterling Bank (energy lending group), CIBC World Markets (energy corporate finance/underwriting & distribution), and First City National Bank of Houston (petroleum & minerals division). Mr. Wilson holds a Master of International Management degree from the Thunderbird School of Global Management and a BA from Ohio Wesleyan University.

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

As of December 31, 2013, the Company’s board of directors consists of one member, Mr. Jurasin. It is anticipated that the board of directors will not be expanded to include any additional members.

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.

We have not adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer, or persons performing similar functions, because of the small number of persons involved in the management of the Company. 

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Involvement in Certain Legal Proceedings

Except as described in the next paragraph, to the best of our knowledge, during the past ten years from the date of this report, none of the following occurred with respect to a director or executive officer of the Company: (1) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (2) any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses); (3) being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of any competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his or her involvement in any type of business, securities or banking activities; (4) being found by a court of competent jurisdiction (in a civil action), the SEC or the Commodity Futures Trading Commission to have violated a Federal or State securities or commodities law, and the judgment has not been reversed, suspended or vacated; (5) being subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any Federal or State securities or commodities law or regulation or any law or regulation respecting financial institutions or insurance companies or prohibiting mail or wire fraud or fraud in connection with any business entity; or (6) being subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization, any registered entity of the Commodity Exchange Act, or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

On March 22, 2013, George R. Jarkesy, was a named party in a Notice and Hearing and Order Instituting Administrative and Cease-And-Desist Proceedings Pursuant to Section 8A of the Securities Act of 1933, Sections 15(b)(4), 15(b)(6) and 21C of the Securities Exchange Act of 1934, Sections 203(e), 203(f), and 203(k) of the Investment Advisers Act of 1940 and Section 9(b) of the Investment Company Act of 1940. The SEC alleged that among other things, that Mr. Jarkesy, as manager and adviser of John Thomas Bridge and Opportunity Fund LP I and John Thomas Bridge and Opportunity Fund LP II (together, the “Funds”): (1) recorded arbitrary valuations without any reasonable basis for certain of the Funds’ largest holdings, thus causing the Funds’ performance figures to be false and misleading and their own compensation to be inflated; (2) marketed the two hedge funds on the basis of false representations about, among other things, the identities of their auditor and prime broker and (3) breached his fiduciary duty of full and fair disclosure to the Funds by failing to disclose his repeated favoring of the pecuniary interests of Anastasios Belesis, the Chief Executive Officer of John Thomas Financial (JTF), and JTF, which served as the Funds’ placement agent. On December 5, 2013, the SEC entered an order of settlement, whereby Mr. Jarkesy was censured and agreed to cease and desist from committing or causing any violations and any future violations of Section 206(2) of the Advisers Act. Mr. Jarkesy resigned as a director from the Company on December 30, 2013.

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.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the Company’s directors and executive officers, and persons who beneficially own more than ten percent of a registered class of our equity securities, to file with the SEC initial reports of beneficial ownership and reports of changes in beneficial ownership of our common stock. The rules promulgated by the SEC under Section 16(a) of the Exchange Act require those persons to furnish us with copies of all reports filed with the SEC pursuant to Section 16(a). The information in this section is based solely upon a review of Forms 3, 4, and 5 received by us.

Based solely on our review of the reports filed with the SEC, we believe that all persons subject to Section 16(a) of the Exchange Act timely filed all required reports in fiscal year 2013, except that reports were not filed by the following persons:

Name	Number of Late Reports		Transactions Not Timely Reported		Known Failures to File a Required Form
George Jarkesy		1		0		1
John Thomas Financial, Inc.		1		0		1

40

ITEM 11.  EXECUTIVE COMPENSATION

Summary Compensation Table

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		Other Compensation ($)			Total ($)
John M. Jurasin Chief Executive Officer (1)	2013		250,000		-0-		-0-		-0-		30,573	(2)		280,573
	2012		200,000		-0-		-0-		-0-		44,372	(2)		244,372
C. Scott Wilson Chief Financial Officer (3)

(1) John M. Jurasin served as JOG’s chief executive officer and director in 2008 through August 2010 and Radiant’s chief executive officer,chief financial officer and director beginning August 2010.

(2) Mr. Jurasin received notes totaling $1,049,000 as dividends at the closing of the Reorganization in 2010. The notes accrued $30,573 and $44,372 of interest in 2013 and 2012, respectively.  

(3) Mr. Wilson became Radiant’s chief financial officer on January 30, 2014.

The value attributable to any stock or option awards described in the table above represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718.  

Outstanding Equity Awards at Fiscal Year-End Table

Name	Number of securities underlying unexercised options (#) exercisable		Number of securities underlying unexercised options (#) un-exercisable (1)		Option exercise price ($)		Option expiration date		Number of shares or units of stock that have not vested (#)		Market value of shares or units of stock that have not vested ($)
John M. Jurasin		-0-		-0-		-0-		-0-		-0-		-0-
Timothy N. McCauley (2)		-0-		298,622	$	1.00	8/5/2020			298,622	$	-0-

(1)       Options were granted on August 5, 2010 and vest equally on each of the first three anniversaries of the grant date.

(2)       298,622 options at $1.00 expire on August 5, 2020; a total of 199,081 options vested.

Employment Agreements   

The Company has entered into employment agreements with John M. Jurasin.  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 was increased to $250,000 in the fourth quarter 2013.

Director Compensation

Our directors were not compensated for their services during 2013 and 2012, other than as reflected in the “Summary Compensation Table” above.

41

ITEM 12.  SECURITY 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 May 2, 2014 (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 May 2, 2014, there were 14,735,023 shares of common stock outstanding.

Name and Address of Owner	Number of Shares Owned		Percentage of Voting Power
George Jarkesy (1)(2)		2,775,406		18.5	%
John Thomas Financial, Inc. (3)(4)		3,121,500		21	%
Rock Exploration LLC (6)		1,135,127		7.7	%
Named Executive Officers and Directors:
John M. Jurasin (3)(5)		4,957,445		33.6	%
C. Scott Wilson		-			-
All Executive Officers and Directors as a Group (2 persons)		4,957,445		33.6	%

* Less than one percent

(1)

Mr. Jarkesy is the record owner of 41,564 shares. He is the beneficial owner of Patriot Bridge & Opportunity Fund, L.P., Patriot Bridge & Opportunity Fund II, L.P. and Patriot 28, LLC. These entities combined own 2,472,342 shares of common stock. The address for Patriot Bridge & Opportunity Fund, L.P. (“Fund I”) (f/k/a John Thomas Bridge & Opportunity Fund, L.P.), Patriot Bridge & Opportunity Fund II, L.P. (“Fund II”) (f/k/a John Thomas Bridge & Opportunity Fund, L.P.) (together, referred to as the “Funds”) and Patriot 28, LLC (the General Partner of the Funds)  is 3 Riverway, Suite 1800, Houston, Texas 77056. The Funds are limited partnerships, and the Patriot 28, LLC is the general partner of the Funds (“Patriot 28”).

(2)

Mr. Jarkesy owns  (i) presently exercisable warrants to purchase 50,000 shares of common stock at an exercise price of $4.00 per share owned by Fund I, (ii) presently exercisable warrants to purchase 50,000 shares of common stock at an exercise price of $3.00 per share owned by Fund I, (iii) presently exercisable warrants to purchase 50,000 shares of common stock at an exercise price of $4.00 per share owned by Fund II, (iv) presently exercisable warrants to purchase 50,000 shares of common stock at an exercise price of $3.00 per share owned by Fund II, (v)  presently exercisable warrants to purchase 62,500 shares of common stock at an exercise price of $1.00 per share owned by Fund I.

42

(3)   The address is 14 Wall Street, 5th floor, New York, New York 10005. Thomas Belesis is the President and sole shareholder of John Thomas Financial.  On February 24, 2014, Mr. John Jurasin entered into an Equity Compensation Settlement, whereby John Thomas Financial transferred 2,000,000 shares of common stock to Mr. Jurasin.  Upon completion of this transfer and transaction, Mr. Jurasin will be the beneficial owner of 6,957,445 shares, or 41.7% of voting power and Mr. Belesis will be 5.9%.

(4)	Mr. Belesis is the beneficial owner of John Thomas Financial and  2008 ANASTASIOS BELESIS IRR TR UA DTD SEPT 2008, ANASTASIOS BELESIS (GRANTOR) GEORGE BELESIS TTEE. John Thomas Financial also currently owns 121,500 warrants issued on October 10, 2010. These warrants are exercisable at $1.05.
(5)	The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042. This number does not include 450,677 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements.
(6)	The address of Rock Exploration LLC is One Information Way, Ste 400, Little Rock, Arkansas 72202.  The shares were acquired as part of the sale of the Vidalia properties.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Related Persons

Related parties include (i) Macquarie Americas Corp. (“MAC”), the owner of 49% equity interest in Amber, (ii) John Jurasin, the Company’s CEO and formerly the sole stockholder of JOG, (iii) JTBOF, David R. Strawn, and David M. Klausmeyer, the Company’s stockholders, and (iv) Robert M. Gray, the Company’s director and former employee. Related party balances as of December 31, 2013 and 2012 are as follows:

	Successor		Predecessor
	December 31,		December 31,
	2013		2012
Due from related parties:
MAC	$	358,226	$	-
	$	358,226	$	-
Due to related parties:
John Jurasin	$	842,303	$	-
Robert R. Gray		50,606		-
David M. Klausmeyer		12,193		-
David R. Strawn		12,193		-
	$	917,295	$	-

Successor

MAC

Amber is partially owned by MAC, an affiliate of the Company’s lender, MBL, and Radiant uses the proportionate consolidation method to consolidate Amber. JOG, Radiant’s wholly owned subsidiary, pays for goods and services on behalf of Amber and passes those charges on to Amber through intercompany billings. Periodically, Amber will reimburse JOG for these expenses, or potentially pays for goods and services on behalf of JOG. These transactions are recorded as a due to/from Amber in JOG’s records and as a due to/from JOG in Amber’s records. Due to the fact that Radiant only consolidates its proportionate share of balance sheet and income statement amounts, the portion of the amount due from Amber related to the other interest owner does not eliminate and is carried as amounts due from Amber until the balance is settled through a cash payment. Due from related party was $358,226 as of December 31, 2013.

John Jurasin

Effective March 2010, Radiant assigned certain legacy overriding royalty interests (“ORRI”) in various projects, including the Baldwin AMI, the Coral, Ruby and Diamond Project, the Aquamarine Project, and the Ensminger Project to a related party entity owned by John M. Jurasin.  Radiant retained its working interests in these projects.  Additionally, Radiant assigned its working interest in a project, Charenton, to the related party entity. Radiant did not receive any proceeds for the conveyances and the interests assigned had a historical cost basis of $0.

43

From time to time, John Jurasin advances the Company various amounts in order to pay operating expenses, with no formal repayment terms. The total balance due on these advances was $104,878 as of December 31, 2013.

Additionally, two notes totaling $1,049,000 were issued to Mr. Jurasin in lieu of payment of dividends from JOG, which in turn represented funds advanced by JOG to its subsidiaries Amber and RLE to fund operations.  Interest is accrued at a rate of 4% per year.  The first note of $884,000, issued on August 5, 2010, matured on May 31, 2013. The additional note for $165,000, issued on October 12, 2010, is due and payable on demand at any time subsequent to the repayment in full of all outstanding indebtedness of the Credit Facilities (Note 4).  The balance due on these notes totaled $737,425 as of December 31, 2013. Accrued interest on these notes was $125,015 as of December 31, 2013.

David R. Strawn and David M. Klausmeyer

Mr. Strawn and Mr. Klausmeyer, shareholders of the Company, each loaned the Company a total of $12,193 between March 2002 and June 2005. The notes accrue interest at 8% per annum. The total accrued interest was $36,056 as of December 31, 2013.

Robert M. Gray

As of December 31, 2013, Mr. Gray was owed $50,606 for consulting services rendered prior to becoming an employee of Radiant. This liability is non-interest bearing.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The aggregate fees billed to us by our principal accountants for services rendered during the fiscal years ended December 31, 2013 and 2012, are set forth in the table below:

Fee Category	2013		2012
Audit fees (1)	$	124,000	$	50,000
Audit-related fees (2)		35,000		-
Tax fees (3)		-		-
All other fees (4)		-		-
Total fees	$	159,000	$	50,000

(1)	Audit fees consists of fees incurred for professional services rendered for the audit of consolidated financial statements, for reviews of our interim consolidated financial statements included in our quarterly reports on Forms 10-Q and for services that are normally provided in connection with statutory or regulatory filings or engagements.
(2)	Audit-related fees consist of fees billed for professional services that are reasonably related to the performance of the audit or review of our consolidated financial statements, but are not reported under “Audit fees.”
(3)	There were no tax fees incurred during the year ended December 31, 2013.
(4)	There were no other fees incurred during the year ended December 31, 2013.

Audit Committee Pre-Approval Policies

Our Board of Directors reviewed the audit and non-audit services rendered by the principal accountant during the last two fiscal years and concluded that such services were compatible with maintaining the auditors’ independence.  All audit and non-audit services performed by our principal independent accountant are pre-approved by our Board of Directors to assure that such services do not impair the auditors’ independence from us.

44

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this report:

(1) Financial Statements

Consolidated Balance Sheets as of December 31, 2013 (Successor) and 2012 (Predecessor)

Consolidated Statements of Operations for the period from October 9, 2013 to  December 31, 2013 (Successor) and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor)

Consolidated Statements of Changes in Stockholders’ Deficit for the period from October 9, 2013 to December 31, 2013 (Successor) and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor).

Consolidated Statements of Cash Flows for the period from October 9, 2013 to December 31, 2013 (Successor) and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor).

(2) Financial Statement Schedules

All schedules are omitted because they are not applicable, or not required, or because the required information is included in the consolidated financial statements or notes thereto.

(3) Exhibits

Exhibit No.	Description
2.1	Exchange Agreement, dated as of July 23, 2010, by and among Radiant Oil & Gas, Inc, Jurasin Oil & Gas, Inc., and the shareholders of Jurasin.  Previously filed on Form 8-K dated November 8, 2010. Company agrees to furnish to the SEC, upon request, a copy of any omitted schedule.
2.2	Amendment No. 1 to Reorganization Agreement, effective July 31, 2010, by and among Radiant Oil & Gas, Inc., Jurasin Oil & Gas, Inc., and the JOG Shareholders.  Previously filed on Form 8-K dated August 16, 2010.
3.1	Amended Articles of Incorporation of the Registrant (Incorporated by reference to the Current Report on Form 8-K filed with the SEC on August 16, 2010 as Exhibit 3.1).
3.2	By-Laws of the Registrant (Incorporated by reference to the Current Report on Form 8-K filed with the SEC on August 16, 2010 as Exhibit 3.2)
10.1	First Lien Credit Agreement, dated October 4, 2013, by and among the Company, through its wholly subsidiary Radiant Acquisitions 1, LLC with various Lenders.
10.2	First Amendment to First Lien Credit Agreement, dated February 24, 2014, by and among the Company, through its wholly subsidiary Radiant Acquisitions 1, LLC with various Lenders.
10.3	Forbearance Agreement, dated February 28, 2014, by and among the Company, through its wholly subsidiary Radiant Acquisitions 1, LLC with various Lenders.
31.1	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Label Linkbase Document

45

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: May 7, 2014

RADIANT OIL & GAS, INC.

/s / John M. Jurasin                                    

John M. Jurasin, Chief Executive Officer,

Principal Accounting Officer, and

Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following person on behalf of Radiant Oil & Gas, Inc. and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ John M. Jurasin	Chief Executive Officer,	May 7, 2014
John M. Jurasin	Principal Accounting Officer and Chairman of the Board
/s/ C. Scott Wilson	Chief Financial Officer,	May 7, 2014
C. Scott Wilson

46

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2013 (Successor) and 2012 (Predecessor)	F-3
Consolidated Statements of Operations for the period from October 9, 2013 to December 31, 2013 (Successor) and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor)	F-4
Consolidated Statements of Changes in Stockholders’ Deficit for the period from October 9, 2013 to December 31, 2013 (Successor) and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor)	F-5
Consolidated Statements of Cash Flows for the period from October 9, 2013 to December 31, 2013 (Successor) and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor)	F-6
Notes to Consolidated Financial Statements	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Radiant Oil & Gas, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Radiant Oil and Gas, Inc. and its subsidiaries (collectively, the “Company”) as of December 31, 2013 (Successor) and 2012 (Predecessor) and the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for the period from October 9, 2013 to December 31, 2013 (Successor) the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor).  These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Radiant Oil and Gas, Inc. and its subsidiaries as of December 31, 2013 (Successor) and 2012 (Predecessor) and the consolidated results of their operations and their cash flows for the periods described above, in conformity with accounting principles generally accepted in the United States of America.

/s/ GBH CPAs, PC

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

May 5, 2014

F-2

 RADIANT OIL AND GAS, INC.

Consolidated Balance Sheets

	Successor			Predecessor
	December 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,019,582		$	-
Restricted cash		2,067,225			-
Accounts receivable – oil and gas		271,550			237,216
Commodity derivative asset		33,330			-
Other current assets		81,154			-
Due from related parties		358,226			-
TOTAL CURRENT ASSETS		3,831,067			237,216
PROPERTY AND EQUIPMENT
Properties subject to amortization, accounted for using the full cost method of accounting, net of accumulated depletion of $44,714 and $-0-, respectively		19,758,681			-
Properties not subject to amortization, accounted for using the full cost method of accounting		-			331,219
Property and equipment, net of accumulated depreciation of $188,370 and $-0-, respectively		25,769			-
TOTAL PROPERTY AND EQUIPMENT		19,784,450			331,219
Commodity derivative asset		113,090			-
Deferred financing costs		6,841,640			-
TOTAL ASSETS	$	30,570,247		$	568,435
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	1,681,423		$	323,247
Cash advance obligation on acquisition option		35,580			-
Notes payable		5,004,834			-
Convertible notes payable		142,500			-
Accrued interest		1,389,047			-
Due to related parties		917,295			-
Stock and warrant derivative liabilities		474,895			-
TOTAL CURRENT LIABILITIES		9,645,574			323,247
Deferred gain		900,628			-
Asset retirement obligations		455,296			331,219
Stock and warrant derivative liabilities		4,000,817			-
Long-term debt, net of unamortized discount of $522,993		25,475,264			-
TOTAL LIABILITIES		40,477,579			654,466
Commitments and contingencies (Note 14)		50,000			-
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock, $0.01 par value, 100,000,000 shares authorized, 13,784,408 shares issued and outstanding		137,845			-
Additional paid-in capital		6,114,133			(291,611	)
Accumulated earnings (deficit)		(16,209,310	)		205,580
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)		(9,957,332	)		(86,031	)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$	30,570,247		$	568,435

The accompanying footnotes are an integral part of these consolidated financial statements.

F-3

RADIANT OIL AND GAS, INC.

Consolidated Statements of Operations

	Successor			Predecessor
	For the Period from October 9, 2013 to December 31, 2013			For the Period from January 1, 2013 to October 8, 2013			For the Year Ended December 31, 2012
OIL AND GAS REVENUES	$	696,661		$	1,742,512		$	3,966,017
OPERATING EXPENSES:
Lease operating expenses		483,680			2,355,118			3,760,437
Depreciation, depletion, amortization and accretion		60,950			28,659			-
General and administrative expense		1,158,032			-			-
TOTAL OPERATING EXPENSES		1,702,662			2,383,777			3,760,437
OPERATING INCOME (LOSS)		(1,006,001	)		(641,265	)		205,580
OTHER INCOME (EXPENSE):
Unrealized loss on stock and warrant derivative liabilities		(1,192,523	)		-			-
Unrealized gain on commodity derivative		146,420			-			-
Interest expense		(1,664,342	)		-			-
Other income and expense, net		19,375			-			-
Total other expense		2,691,070			-			-
NET INCOME (LOSS)	$	(3,697,071	)	$	(641,265	)	$	205,580
INCOME (LOSS) PER COMMON SHARE - Basic and diluted	$	(0.27	)	$	(0.52	)	$	0.17
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -
Basic and diluted		13,680,130			1,240,102			1,240,102

The accompanying footnotes are an integral part of these consolidated financial statements.

F-4

RADIANT OIL AND GAS, INC.

Consolidated Statements of Stockholders’ Equity (Deficit)

For the period from October 9, 2013 to December 31, 2013 (Successor)

and for the period from January 1, 2013 to October 8, 2013 (Predecessor) and

for the year ended December 31, 2012 (Predecessor) 

											Total
	Common Stock				Additional			Accumulated			Stockholders'
	Shares		Amount		Paid-in Capital			Earnings (Deficit)			Equity (Deficit)
Predecessor
Balance at December 31, 2011		-	$	-	$	-		$	-		$	-
Predecessor distributions		-		-		(291,611	)		-			(291,611	)
Net income for the year		-		-		-			205,580			205,580
Balance at December 31, 2012		-		-		(291,611	)		205,580			(86,031	)
Predecessor contributions		-		-		539,282			-			539,282
Net loss for the period		-		-		-			(641,265	)		(641,265	)
Balance at October 8, 2013		-	$	-	$	247,671		$	(435,685	)	$	(188,014	)
Successor
Balance at October 9, 2013		12,024,769	$	120,248	$	3,660,956		$	(12,512,239	)	$	(8,731,035	)
Common stock issued for cash		375,000		3,750		746,250			-			750,000
Common stock issued for acquisition of properties		1,240,102		12,401		1,277,305			-			1,289,706
Common stock issued for settlement of accounts payable		69,537		696		138,378			-			139,074
Stock-based compensation		75,000		750		291,244			-			291,994
Net loss for the period		-		-		-			(3,697,071	)		(3,697,071	)
Balance at December 31, 2013		13,784,408	$	137,845	$	6,114,133		$	(16,209,310	)	$	(9,957,332	)

The accompanying footnotes are an integral part of these consolidated financial statements.

F-5

RADIANT OIL AND GAS, INC.

Consolidated Statements of Cash Flows

	Successor			Predecessor
	For the Period from October 9, 2013 to December 31, 2013			For the Period from January 1, 2013 to October 8, 2013			For the Year Ended December 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(3,697,071	)	$	(641,265	)	$	205,580
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation, depletion, amortization, and accretion		60,950			28,659			-
Amortization of deferred financing costs		231,859			-			-
Amortization of debt discount		588,074			-			-
Unrealized loss on stock and warrant derivative liabilities		1,192,523			-			-
Unrealized gain on commodity derivatives		(146,420	)		-			-
Stock-based compensation		291,994			-			-
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		(170,263	)		135,929			(237,216	)
Other current assets		107,858			-			-
Accounts payable and accrued expenses		129,409			(62,605	)		323,247
Deferred gain		(27,203	)		-			-
Net cash provided by (used in) operating activities		(1,438,290	)		(539,282	)		291,611
CASH FLOWS FROM INVESTING ACTIVITIES:
Change in restricted cash		(2,067,225	)		-			-
Cash paid for oil and gas properties		(1,188,977	)		-			-
Cash paid for business acquisition – Vidalia		(14,964,545	)		-			-
Purchase of equipment		(26,928	)		-			-
Net cash used in investing activities		(18,247,675	)		-			-
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on notes payable		27,525,947			-			-
Payments on notes payable		(634,791	)		-			-
Original issue discount on notes payable		(550,519	)		-			-
Deferred financing costs		(6,445,065	)		-			-
Predecessor contributions (distributions)		-			539,282			(291,611	)
Loans to/from owners, net		(57,125	)		-			-
Proceeds from issuance of common stock		750,000			-			-
Net cash provided by financing activities		20,588,447			539,282			(291,611	)
INCREASE IN CASH		902,482			-			-
CASH, BEGINNING OF PERIOD		117,100			-			-
CASH, END OF PERIOD	$	1,019,582		$	-		$	-

The accompanying footnotes are an integral part of these consolidated financial statements.

F-6

RADIANT OIL AND GAS, INC.

Consolidated Statements of Cash Flows

(Continued)

	Successor		Predecessor
	For the Period from October 9, 2013 to December 31, 2013		For the Period from January 1, 2013 to October 8, 2013		For the Year Ended December 31, 2012
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Income taxes	$	-	$	-	$	-
Interest	$	545,210	$	-	$	-
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued oil and gas development costs	$	283,676	$	-	$	-
Common stock issued for business acquisition – Vidalia	$	1,289,706	$	-	$	-
Warrants issued for business acquisition – Vidalia	$	1,539,098	$	-	$	-
Warrants issued for deferred financing cost	$	628,434	$	-	$	-
Common stock issued for settlement of accounts payable	$	139,074	$	-	$	-
Change in asset retirement obligations	$	13,278	$	-	$	331,219

The accompanying footnotes are an integral part of these consolidated financial statements.

F-7

RADIANT OIL AND GAS, INC.

Notes to Consolidated Financial Statements

December 31, 2013

Note 1 – General Organization and Business and Summary of Significant Accounting Policies

General Organization and Business

Radiant Oil and Gas, Inc. (“Radiant” or “the Company”) is an independent oil and gas exploration and production company that operates in the Gulf Coast region of the United States of America, specifically, onshore and the state waters of Louisiana, USA, and the federal waters offshore Texas in the Gulf of Mexico.  Effective October 9, 2013, the Company closed on the purchase of oil and gas properties located in Louisiana and Mississippi (the “Vidalia Properties” or “Vidalia”).  The Vidalia Properties contain over eighty (80) wells in Louisiana and Mississippi.

The Company determined Vidalia to be its predecessor entity as the latter’s historical operations were significantly larger than the historical operations of the Company. For the purposes of financial statement presentation, designation of an acquired business as a predecessor is required if a registrant succeeds to the business of another entity and the registrant’s own operations prior to the succession appear insignificant relative to the operations assumed or acquired. As such, the Company has included the historical financial results of Vidalia as its predecessor entity.

Principles of Consolidation

The Company consolidates all of its investments in which the Company has exclusive control. The accompanying financial statements include the accounts of Radiant and the Company’s wholly owned subsidiaries, Jurasin Oil and Gas, Inc. (“Jurasin”) Rampant Lion Energy, LLC (“RLE”), Radiant Oil and Gas Operating Company, Inc. (“ROGop”), Radiant Acquisitions 1, Inc. (“Radiant Acquisitions”), Radiant Synergy Operating LLC. (“Radiant Synergy”) and Charenton Oil Company LLC. (Charenton).

In accordance with established practices in the oil and gas industry, the Company’s consolidated financial statements include pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of Amber Energy, LLC. (“Amber”), in which the Company has an interest. The Company owned a 51% interest in Amber as of December 31, 2013.

The financial statements presented herein contain information for Vidalia for the period from January 1, 2013 through October 8, 2013 and for the year ended December 31, 2012.

All material intercompany balances and transactions have been eliminated in consolidation.

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. The Company bases its 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. The Company’s estimates include estimates of oil reserves, future cash flows from oil properties, depreciation, depletion, amortization, impairment of oil properties, asset retirement obligations, and calculations related to stock and warrant derivative liabilities and commodity derivative instruments. 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.

Cash and Cash Equivalents

Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value. The Company and its subsidiaries maintain its cash in institutions insured by the Federal Deposit Insurance Corporation (FDIC), which insures the balances up to $250,000 per depositor. At December 31, 2013 and 2012, the Company had a cash balance of $2,017,241 and $0, respectively, in excess of FDIC insurance limits. The Company has not incurred losses related to these deposits and believes no significant concentration of credit risk exists with respect to these cash investments.

As of December, 31, 2013, Radiant had a restricted cash balance of $2,067,225. This amount was restricted by the lender in accordance with Centaurus financing agreement (see Note 4 “Debt” for more detail on this financing).

F-8

Concentrations

Financial instruments which potentially subject us to concentrations of credit risk consist of cash. We periodically evaluate the credit worthiness of financial institutions, and maintain cash accounts only with major financial institutions thereby minimizing exposure for deposits in excess of federally insured amounts. We believe that credit risk associated with cash is remote.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are reflected at net realizable value. The Company establishes provisions for losses on accounts receivable if the Company determines that the Company will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Substantially all of accounts receivable balance relates to the most recent crude oil revenue sales.

Deferred Financing Charges

Deferred finance charges consist of legal and other fees incurred in connection with the issuance of notes payable and are capitalized and shown in the consolidated balance sheets. These charges are being amortized using the effective interest method over the term of the related notes.

Property and Equipment

Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset: furniture and fixtures - 7 years; vehicles - 5 years; computer equipment and software - 3 to 5 years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. The Company performs ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting, as prescribed by the United States Securities and Exchange Commission (“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 full cost pool. 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 the Company determines 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. The Company evaluates unevaluated properties for inclusion in the amortization base at least annually.  The Company assesses properties on an individual basis, or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.

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.

The Company includes its 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 the Company directly owns. The Company calculates the depletion and net book value of the assets based on the full cost pool’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.

F-9

The net book value of all capitalized oil and natural gas properties, 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.

As of December 31, 2013 and 2012, the Company had oil and gas property balance of $19,758,681 and $331,219, respectively.

Impairment of Long-Lived Assets

The Company periodically reviews non-oil and gas long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. The Company recognizes an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. During the period from October 9, 2013 to December 31, 2013, the period from January 1, 2013 to October 8, 2013 and the year ended December 31, 2012, there was no impairment recorded by the Company.

Asset Retirement Obligation

The Company records 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. The Company records an asset retirement obligation to reflect its legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. The Company estimates the expected cash flow associated with the obligation and discounts the amount using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates 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), the Company will accordingly update its assessment.  Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.

Derivative Financial Instruments

For derivative financial instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then re-valued at each reporting date, with changes in the fair value reported as charges or credits to non-operating income. For warrants and convertible derivative financial instruments, the Company uses the Binomial Option Pricing model to value the derivative instruments at inception and subsequent valuation dates. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period, in accordance with FASB ASC Topic 815, Derivatives and Hedging. Derivative instrument liabilities are classified in the balance sheet as current or non-current based on whether or not net-cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

Revenue Recognition

The Company recognizes revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenues, and recognizes 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 the Company has an imbalance on a specific property greater than the expected remaining proved reserves.

Income Taxes

The Company accounts for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

F-10

FASB ASC-740 establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. In periods when losses are reported, the diluted weighted-average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive. There was no difference between basic and diluted income (loss) per share for all periods presented. 

Recent Accounting Pronouncements

The Company does not expect the adoption of recently issued accounting pronouncements to have a significant impact on its results of operations, financial position or cash flows.

Subsequent Events

The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration and there are no reportable events.

Note 2 – Business Combination

Purchase of Vidalia Properties

On October 9, 2013, the Company completed the purchase of the Vidalia Properties located in Louisiana and Mississippi for $17,274,116. As a result of this acquisition, the Company issued 1,615,102 shares of common stock as well as 1,500,201 warrants with an exercise price of $2.02 per share. The warrants expire on October 8, 2016. The acquired properties contain over eighty (80) wells in Louisiana and Mississippi.  The Company’s Louisiana properties include over 39 wells and numerous leases located in Concordia, and La Salle Parishes. The Company’s Mississippi properties include over 41 wells and numerous leases located in Adams, Amite, Franklin, and Wilkinson Counties. The Vidalia properties include approximately 38 productive wells and up to 38 shut-in wells that continue to be evaluated for work-over and behind pipe opportunities which is expected to provide for cost-effective near-term production increases.

The Company acquired net assets with an aggregate fair value of $17,274,116 in exchange for cash payment of $14,964,545, issuance of 1,240,102 common shares of the Company valued at $1,289,706 and 1,500,201 warrants valued at $1,539,098, as well as other assets acquired and liabilities assumed (see table below) resulting in an acquisition price of $17,274,116. The acquisition price of the Vidalia Properties was allocated to the assets acquired and liabilities assumed based upon their estimated fair values.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

Assets acquired:
Oil and gas properties	$	17,793,349
Accrued revenue		101,287
Total asset acquired		17,894,636
Liabilities assumed:
Accrued lease operating expenses		(260,642	)
Asset retirement obligations		(359,878	)
Total liabilities assumed		(620,520	)
Net assets acquired	$	17,274,116

F-11

Note 3 – Oil and Gas Properties

The table below summarizes the Company’s capitalized costs related to proved oil and gas properties which were subject to depreciation, depletion and amortization at December 31, 2013 and 2012 were:

	Successor			Predecessor
	December 31, 2013			December 31, 2012
Proved oil and gas properties	$	19,803,395		$	-
Accumulated depreciation, depletion, amortization and valuation adjustments		(44,714	)		-
Net capitalized costs	$	19,758,681		$	-

Substantially all of the Company’s oil and gas properties are proved as of December 31, 2013 and 2012 in accordance with the definition of proved reserves.

Detail Project Descriptions - Successor

Ensminger

In 2010, Radiant had a minority interest in a well drilled in this prospect. In 2011, the well was temporarily abandoned in a manner that would allow re-entry at a later date.

During 2013, the Company has acquired a lease for materially the same area as the area leased and exploited in 2005 to 2007 for the same area covering this prospect (approximately 634 acres). The Company controls 100% of the working interest in this prospect. The plan is to re-enter the well that was abandoned in 2004 and twin by–passed pay in the well drilled in 2014 that is located in a nearby reservoir.

The Ensminger Project is located in St. Mary’s Parish, Louisiana. Currently, there are no producing wells in this area currently.

Coral

In December 2013, the Company acquired   two Louisiana State Waters of St. Mary’s parish leases totaling approximately 1,405 acres. As of December 31, 2013, the Company capitalized a total of $617,835.   Radiant controls 100% of the working interest.

Shallow Oil - Black Gold

On March 1, 2012, Radiant entered into a project agreement (the “Shallow Oil Phase 1 Agreement”) with Black Gold, Inc. (“Black Gold”) for joint acquisition and exploration of certain oil and gas leases and related assets located in St. Mary Parish, Louisiana (the “Phase 1 Lease”).   Black Gold did not fund its Phase 1 Initial Drilling Commitment and no drilling commenced. In accordance with the Shallow Oil Phase 1 Agreement, Radiant issued to Black Gold 150,000 shares of its common stock at $0.50 per share.

On June 1, 2012, Radiant entered into another project agreement (the “Shallow Oil Phase 2 Agreement”) with Black Gold, for joint acquisition and exploration of certain oil and gas leases and related assets located in St. Mary Parish, Louisiana (the “Phase 2 Lease”).  Black Gold did not fund its Phase 1 Initial Drilling Commitment and no drilling commenced. In accordance with the Shallow Oil Phase 2 Agreement, Radiant issued to Black Gold 250,000 shares of its common stock at $0.50 per share.

In January and February 2013, Black Gold funded $90,000 as part of its drilling commitment. In accordance with the Shallow Oil Phase 2 Agreement, Radiant issued to Black Gold 90,000 shares of its common stock at $0.50 per share.

Effective February 24, 2014, the agreement with Black Gold was terminated. Due to the fact that Black Gold did not fully fund its commitment, the amount received from Black Gold of $245,000 will be recorded as other income in the consolidated statement of operations during 2014.

F-12

Shallow Oil - Grand Synergy

Effective June 1, 2012, Radiant entered into a project agreement (the “Shallow Oil Phase 3 and 4 Agreement”) with Grand Synergy Petroleum, LLC (“Grand”) for joint acquisition and exploration of certain oil and gas leases and related assets located in St. Mary Parish, Louisiana (the “Phase 3 and 4 Leases”).  As a result of this agreement, two new Louisiana entities were formed, Charenton Oil Company, LLC (“Charenton”) on May 8, 2012 and Radiant Synergy Operating, LLC (“Synergy”) on June 28, 2012. Charenton is a wholly owned subsidiary of Radiant and Synergy was owned 50% by Radiant and 50% by Grand.

The initial project cost of $300,000 received from Grand in July 2012 and the $1,000,000 received from Grand in November 2012 for drilling costs are recorded as a deferred gain and related drilling costs of $644,372 was netted in this deferred gain balance as of December 31, 2013. This amount was recorded as a deferred gain due to the fact that Grand Synergy did not fully fund its commitment and therefore did not receive ownership of the Shallow Oil properties. At the time the remaining funds are received from Grand, the Company will transfer the ownership of the leases to Charenton and will recognize the gross amount received, less the $300,000 as drilling revenue. The $300,000 was recognized as revenue from the sale of leases. Related costs, including the amount currently deferred, will be recognized as drilling cost and leasehold costs, respectively.

As Grand did not fulfil its obligations outlined in the agreement, Radiant effectively became a 100% owner of Radiant Synergy in the fourth quarter of 2013.

Detail Project Descriptions – Predecessor

Vidalia Properties

As discussed in Notes 1 and 2, on October 9, 2013, the Company completed the purchase of Vidalia.  The  acquired  properties  contain  over  eighty (80)  wells  in  Louisiana  and  Mississippi.  The Louisiana properties include over 39 wells and numerous leases located in Catahoula, Concordia, La Salle and St. Mary's Parishes. The Mississippi properties include over 41 wells and numerous leases located in Adams, Amite, Franklin, and Wilkinson Counties. The properties include up to 30 productive wells and up to 38 shut-in wells.

Note 4 – Notes Payable

Notes payable as of December 31, 2013 and 2012 consisted of the following:

	Successor			Predecessor
	December 31, 2013			December 31, 2012
First Lien Credit Facility (Centaurus)	$	27,525,947		$	-
Senior credit facility (AE)		2,032,188			-
Senior credit facility (RLE)		818,309			-
Fermo Jaeckle note		475,000			-
Debentures (Patriot Notes)		150,705			-
Line of credit (Capital One Bank)		942			-
Total notes payable		31,003,091			-
Less: unamortized discount		(522,993	)		-
Less: current portion		(5,004,834	)		-
Long-term portion	$	25,475,264		$	-

First Lien Credit Facility (“Centaurus facility”)

Effective October 4, 2013, the Company, through its wholly-owned subsidiary Radiant Acquisitions, entered into a First Lien Credit Agreement (“Centaurus Facility” or “Facility”) with various financial institutions (the “Lenders” or “Centaurus”). The maximum aggregate commitment of the Lenders to advance loans under this Agreement is $39,788,000, and the maximum aggregate principal amount to be repaid by the Borrower is $40,600,000 and for any given loan, the amount of funds advanced by any Lender shall be ninety-eight percent (98%) of the amount of principal required to be repaid by the Borrower. The Company also sold a 12.5% net profits interest to Centaurus for $75,000 for specific proved wells as part of the Credit Facility Agreement.  The net profits interest was subsequently increased to 17.0% for the specified proved wells and remained at 12.5% for all other wells when the Credit Facility was amended on February 28, 2014.  The Credit Agreement has an original stated maturity date of September 2018.  As part of the amendment, the maturity date was extended to December 2018. The outstanding principal balance of the Loans (as may have been advanced from time to time) bears interest at a per annum rate of twelve percent (12%). Any outstanding indebtedness from the Credit Agreement was collateralized by substantially all of the assets of Radiant Acquisitions. In addition, the Company pledged its ownership interest in Radiant Acquisitions and executed a parent company guaranty as additional security. The Credit Facility contained restrictive financial covenants. The proceeds from the Credit Agreement were used to fund the closing of its recent acquisition of oil and gas properties located in Louisiana and Mississippi, as well as to develop multiple re-entry, workover and drilling opportunities on acquired acreage throughout south Louisiana and Mississippi.

F-13

As of December 31, 2013, the Company had an outstanding balance on its Centaurus Facility of $27,525,947. Interest expense was $769,681 for the period from October 9, 2013 to December 31, 2013 and accrued interest was $246,891 at December 31, 2013.  The Centaurus Facility contains restrictive financial covenants. As of December 31, 2013, the Company was not in compliance with some of its reporting covenants, including timely delivery of audited financial statements and other reporting requirements.  Effective February 28, 2014, the lender agreed to forbear from exercising its rights and remedies against the Company, as allowed by the Facility.  The lender has specifically agreed to not initiate proceedings to collect on the obligation, discontinue lending under the Credit Agreement, initiate or join in any involuntary bankruptcy petition, repossess or dispose of any collateral under the Credit Agreement or similar actions because of the existing defaults until notice by the Agent of the Credit Agreement or October 1, 2014.

The Centaurus Facility included a 2% Original Issue Discount of $550,519.  This discount is being amortized over the five-year life of the note using the effective interest rate method.  The Company recorded $27,526 in discount amortization during the period from October 9, 2013 to December 31, 2013.  The unamortized balance of the discount is $522,993 at December 31, 2013.

Effective February 28, 2014, the Company amended the Centaurus Credit Agreement.  The Amendment increased the maximum aggregate commitment from the Lenders from $39,788,000 to $41,748,000, increased the principal amount to be repaid by the Company from $40,600,000 to $42,600,000 plus any deferred interest, and increased the net profits interest conveyed to Centaurus on specific proved wells from 12.5% to 17.0%.  Advances under the Facility are available with the approval of the Agent.  There was no change in interest rate or collateral.  Repayments are based on cash flow from Company properties and are schedule to begin no later than October 2014.  Should the Company default on any provisions in the Agreement other than those existing defaults, the Lenders have the right to exercise its rights and remedies against the Company, as contained in the facility agreement and the Amendment.

Senior Credit Facility of Amber (“Amber Credit Facility”)

In October 2007, Amber entered into the Amber Credit Facility with Macquarie Bank Limited (“MBL”) for up to $10 million, originally maturing on September 9, 2009. The note was collateralized by substantially all assets of Amber. The loan contained reporting and other standard covenants and accrued interest at the Wall Street Journal Prime Rate.  Payment was at maturity.  The agreement provided that Macquarie Americas Corp. (“MAC”), an affiliate of MBL, would receive up to 49% of Amber, 25% at the inception of the note and an additional 24% on October 9, 2009 if the balance on the note exceeded $1.5 million. Radiant contributed certain lease interests to Amber. Amber’s company agreement provided for board representation for MBL and joint consent was required for certain transactions. Because of the shared control of Amber, Radiant proportionately consolidates Amber.  The consolidated financial statements include the Company’s pro-rata 51% share of assets, liabilities, income and lease operating and general and administrative costs and expenses of Amber.

In April 2008, the note was modified to accommodate Radiant’s contribution of the Ensminger project to Amber. Modifications included increasing the threshold for the step up of MBL’s equity interest to 49% from $1.5 million to $2 million, reclassifying tranches available within the facility, and extending the maturity date to March 20, 2011. The borrowing capacity of the facility was unchanged.

In February 2010, Radiant entered into a supplementary agreement with MBL under which, a partial release of mortgage in certain assets was affected in order to facilitate the sub-lease of a portion of our working interest in the Ensminger project; the bulk of the proceeds of the sub-lease are committed to repayment of principal and interest on the note.

On March 20, 2011, Radiant and MBL entered into a Second Amendment to the Credit Agreement (Amber 2nd Credit Agreement Amendment), which extended the maturity date to September 9, 2011.

In 2010 and through the amendment of the credit facility, the Company was not in compliance with certain of the reporting covenants contained within the credit facility.  At expiration of the Amber 2nd Amendment the note became due and payable.  As a result, the Amber Credit Facility was in payment default which is uncured as of December 31, 2013.   As of December 31, 2013, the Company had an outstanding balance on its Amber Credit Facility of $2,032,188. Accrued interest related to this credit facility amounted to $413,829 as of December 31, 2013. For the period of the period from October 9, 2013 to December 31, 2013, the Company recognized interest expense on the Amber Credit Facility of $16,174.  No payments have been made since September 2006.  Management intends to negotiate a settlement of the Amber Credit Facility with MBL.

F-14

Senior Credit Facility of RLE (“RLE Credit Facility”)

In September 2006, RLE entered into the RLE Credit Facility with MBL for up to $25 million, advanced through multiple tranches and, originally maturing on September 9, 2009. The note contained financial, reporting and other standard covenants and accrued interest at the Wall Street Journal Prime Rate plus 4%.  The note was collateralized by substantially all of the assets of RLE and was to be repaid through dedication of a percentage of net operating cash flow of the RLE assets.  In addition, Radiant pledged its ownership interest in RLE and executed a parent company guarantee to pay up to $500,000 of the outstanding indebtedness as additional security.  On March 20, 2011, Radiant and MBL entered into a Fourth Amendment to the Credit Agreement (“RLE 4th Credit Agreement Amendment”), which extended the maturity date to September 9, 2011.  The loan has matured and the outstanding balance of the RLE Credit Facility is currently in uncured payment default. 

As of December 31, 2013, the Company had an outstanding balance on its RLE Credit Facility of $818,309.  Accrued interest related to this credit facility amounted to $367,757 as of December 31, 2013. The RLE Credit Facility contained restrictive financial covenants. Interest accrued at the default interest rate of 11.25% during 2013.  For the period of the period from October 9, 2013 to December 31, 2013, the Company recognized interest expense on the RLE Credit Facility of $41,021.  No payments have been made since September 2006.  Management intends to negotiate a settlement of the RLE Credit Facility with MBL.

Fermo Jaeckle Note

In February 2011, Radiant issued a convertible promissory note to Fermo Jaeckle (“10% Convertible Note”) in the principal amount of $475,000.  Additionally, Radiant issued to Mr. Jaeckle 475,000 shares of its common stock valued at $237,500 on the date of grant.  The note bears interest at 10% per annum and matured on July 31, 2011.  As of December 31, 2013, the Company had an outstanding balance on this note of $475,000.  Interest expense was $12,139for the period from October 9, 2013 to December 31, 2013 and accrued interest was $142,694 at December 31, 2013.  Management intends to contact Mr. Jaeckle and his representatives to negotiate a settlement of the 10% Convertible Note.

Patriot Agreement

On December 28, 2013, the Company entered into an agreement (the “Patriot Agreement”) with Patriot Bridge & Opportunity Fund, L.P. (f/k/a John Thomas Bridge & Opportunity Fund, L.P.) and Patriot Bridge & Opportunity Fund II, L.P., together referred to as the “Funds,” Patriot 28, LLC, the Managing Member of the Funds, and George Jarkesy, individually and as Managing Member of Patriot 28. The Patriot 28 Agreement restructured the outstanding $150,000 due to the Funds in the form of a general liability promissory note. The maturity date of the Note shall be the earlier of an equity infusion of not less than $10,000,000 or December 1, 2014. Interest shall be paid monthly at the rate of six percent (6%) per annum.  The Company incurred $820 of interest expense during the period from October 9, 2013 to December 31, 2013.  Accrued interest was zero at December 31, 2013.

To the extent any payments are not made timely in accordance with the repayment schedule described in the Patriot 28 Agreement, the Company shall issue 500 shares of Company stock to Fund I and 500 shares of Company stock to Fund II for each default occurrence. This provision does not apply if the Company cures its default within ten (10) days following receipt of written notice that a payment has not been timely made.

The Company, upon execution and delivery of the Patriot Agreement paid to the Funds $15,000 in reimbursement for all legal fees and expenses of the Funds related to the Loan and the January 1, 2014 payment for $14,115.  The general liability note amortizes with a monthly payment of $13,425.  The final payment is due on the earlier of an equity infusion of not less than $10,000,000 or December 1, 2014.

As part of the Patriot Agreement, due to a variety of factors, the outstanding obligations under the Loan from the Company to the Funds and other considerations, Mr. Jarkesy resigned from the Board of Directors of the Company on December 30, 2013.

Line of Credit

The Company has a line of credit from the Capital One Bank for up to $25,000 that carries a 7% fixed interest rate.  As of December 31, 2013, the outstanding balance on the line of credit was $942.

F-15

Convertible Debt

Convertible notes payable as of December 31, 2013 and 2012 consisted of the following:

	Successor			Predecessor
	December 31, 2013			December 31, 2012
Asher Note # 1	$	90,000		$	-
Asher Note # 2		52,500			-
Total convertible notes payable		142,500			-
Less: current portion		(142,500	)		-
Long-term portion	$	-		$	-

Asher Convertible Notes

On June 27, 2011 and July 2011, Radiant issued convertible promissory notes to Asher Enterprises Inc. (“Asher Convertible Notes”), in which Asher loaned $60,000 (“Asher Note # 1”) and $35,000 (“Asher Note # 2), respectively, at 8% interest, both convertible into the Company’s common stock. The loans are convertible after 180 days from the date of issuance and until the later of maturity date or the date of payment of default amount. The conversion price equals to 61% of the average of the lowest 3 trading prices for the common stock during the ten trading day period ending on the latest complete trading day prior to the conversion date. Because of this floating rate feature, these notes are considered a derivative liability – see Note 7 for more detail.

The notes are unsecured and originally matured on March 29, 2012 and April 26, 2012, respectively. Radiant defaulted on both notes on November 16, 2011.  According to provisions of the credit agreement, in case of a default, the principal of the notes increases 150%. As such, the total principal of the notes increased from $95,000 to $142,500. Accrued interest was $51,042 as of December 31, 2013.

The aggregate payments due on the notes payable in each of the next five years are as follows:

2014	$	5,147,334
2015		7,803,606
2016		9,826,763
2017		6,647,516
2018		1,720,372
Thereafter		-
	$	31,145,591

Note 5 – Commodity Derivative

In connection with First Lien Credit Facility (“Centaurus facility”), the Company and Centaurus entered into an International Swaps and Derivatives Association (“ISDA”) Master Agreement that provides Centaurus with the ability to hedge its future price risk from time to time utilizing a series of price swap agreements for the period from 2014 through 2018.  Each contract will be settled in net cash on settlement date.

The following table shows the monthly volumes and average floor prices per the ISDA Master Agreement:

Start Month	End Month	Volume BBL/Month		Average Floor $/BBL
Nov. ‘13	Dec. ‘13		4,000	$	102.40
Jan. ‘14	Dec. ‘14		3,000	$	96.45
Jan. ‘15	Dec. ‘15		3,000	$	89.41
Jan. ‘16	Dec. ‘16		3,000	$	84.61
Jan. ‘17	Dec. ‘17		2,000	$	82.10
Jan. ‘18	Sept. ‘18		2,000	$	80.81

For the three months ended December 31, 2013, the Company has recognized realized a gain on the commodity derivative of $48,960 in its consolidated statements of operations as other income.

F-16

The Company has elected not to apply hedge accounting to this derivative but will, instead, recognize unrealized gain (losses) associated derivative in its consolidated statements operations in the period for which such unrealized gain (losses) occur.

The price swap agreements have an aggregate fair market value of $146,420 as of December 31, 2013. Accordingly, the Company has presented a short term derivative asset of $33,330 and long term derivative asset of $113,090 on its balance sheet as of December 31, 2013 and recognized an unrealized gain associated with the price swap agreements of $146,420 for the three months ended December 31, 2013.

Note 6 – Deferred Financing Charge

In order to obtain the Centaurus Facility (see Note 4 above) the Company incurred $7,073,499 of legal, banking, insurance and other professional fees.  These fees were capitalized and are being amortized over the five year term of the Centaurus Facility using the effective interest method.  For the year ended December 31, 2013, $231,859 was amortized.

Note 7 – Stock and Warrant Derivative Liabilities

Agent Warrants

In November 2010, Radiant issued to John Thomas Financial, Inc. (“JTF”) warrants to purchase 121,500 shares of the Company’s common stock at an exercise price of $1.05 per share. The warrants were given as additional compensation for placing an offering of common stock. The warrants had a contractual term of 5 years and vested immediately. The warrants had an exercise price reset provision clause that triggered derivative accounting.  The fair value of these warrants was calculated as $121,566 as of December 31, 2013.

Tainted Warrants

In May 2011, Radiant issued convertible promissory notes to JTBOF and JTBOF II in the principal amount of $75,000 each (see more detail in Note 4).  Additionally, Radiant issued warrants to purchase 150,000 shares of its common stock each to JTBOF and JTBOF II.  Warrants to purchase 50,000 shares of its common stock each to JTBOF and JTBOF II have an exercise price of $2.50 per share and a term of up to 2 years, $3.00 per share and a term of up to 3 years, and $4.00 per share and a term of up to 4 years.  Upon the issuance of Asher convertible notes and as a consequence of its floating rate feature, these warrants and other existing warrants previously classified as equity have become tainted and are considered a derivative liability.  Warrants to purchase 50,000 shares of common stock each issued to JTBOF and JTBOF II that had an exercise price of $2.50 expired.  The fair value of these warrants was calculated as $1,092,505 as of December 31, 2013.

The following is a summary of the assumptions used in the Lattice option pricing model to estimate the fair value of the total Company’s stock and warrant derivative liabilities as of December 31, 2013:

	December 31,
	2013
Common stock issuable upon exercise of warrants					420,706
Estimated market value of common stock on measurement date	$	0.59		-	1.03
Exercise price	$	0.12		-	4.00
Risk free interest rate (1)		0.10		-	0.38	%
Expected dividend yield		0	%		0	%
Expected volatility (2)		212	%	-	307	%
Expected exercise term in years		0.38		-	2.14

(1)   The risk-free interest rate was determined by management using the Treasury bill yield as of December 31, 2013.

(2)   The volatility was determined by referring to the average historical volatility of a peer group of public companies because we do not have sufficient trading history to determine our historical volatility.

Asher Convertible Notes

The Asher Convertible Notes are convertible at 61% of the average lowest three-day trading price of common stock during the during the ten trading day period ending on the latest complete trading day prior to the conversion date. The Company analyzed these conversion options, and determined that these instruments should be classified as liabilities and recorded at fair value due to there being no explicit limit as to the number of shares to be delivered upon settlement of the aforementioned conversion options.

F-17

As of December 31, 2013, the fair value of the derivatives was $167,048.  As of December 31, 2013, the discount on the Asher Convertible Notes has been fully amortized.

The fair value of stock and warrant derivative liabilities related to the conversion options of the Asher Convertible Notes has been estimated as of December 31, 2013 using the Lattice option pricing model, under the following assumptions:

	Asher			Asher
	Note # 1			Note # 2
Common stock issuable upon exercise of warrants		195,652			114,130
Estimated market value of common stock on measurement date	$	1.04		$	1.04
Exercise price	$	0.46		$	0.46
Risk free interest rate (1)		0.01	%		0.01	%
Expected dividend yield		0	%		0	%
Expected volatility (2)		224	%		224	%
Expected exercise term in years		0.00			0.00

(1)   The risk-free interest rate was determined by management using the one month Treasury bill yield as of the issuance dates.

(2)   The volatility was determined by referring to the average historical volatility of a peer group of public companies because we do not have sufficient trading history to determine our historical volatility.

Bridge Loan Warrants

In August 2013, Radiant entered into a bridge loan agreement with various individuals, totaling $600,000, along with warrants to purchase 1,500,000 shares of the Company’s common stock at $0.01 per share.  The related proceeds were received by Radiant on September 6, 2013, and as such, the aforementioned warrants were deemed to be issued on that date.  The warrants have a contractual term of 5 years and vest immediately.  The warrants were tainted and considered a derivative.  The fair value of these warrants was calculated as $1,559,697 at the balance sheet date of December 31, 2013.  

The following is a summary of the assumptions used in the Lattice option pricing model to estimate the fair value of the total Company’s warrant Stock and warrant derivative liabilities as of the balance sheet date at December 31, 2013:

	December 31,
	2013
Common stock issuable upon exercise of warrants		1,500,000
Estimated market value of common stock on measurement date	$	1.04
Exercise price	$	0.01
Risk free interest rate (1)		1.51	%
Expected dividend yield		0	%
Expected volatility (2)		289	%
Expected exercise term in years		4.68

(1)   The risk-free interest rate was determined by management using the Treasury bill yield as of December 31, 2013.

(2)   The volatility was determined by referring to the average historical volatility of a peer group of public companies because we do not have sufficient trading history to determine our historical volatility.

Vidalia Warrants

As a result of this acquisition of the Vidalia Properties (see Note 2), the Company issued 1,500,201 warrants to purchase an equivalent number of shares of the Company’s common stock with an exercise price of $2.02 per share. The warrants expire on October 8, 2016. The warrants were tainted and considered a derivative.  The fair value of these warrants was calculated as $1,539,098 on the initial valuation date of October 9, 2013 and $1,534,897 at December 31, 2013.

F-18

The following is a summary of the assumptions used in the Lattice option pricing model to estimate the fair value of the total Company’s warrant Stock and warrant derivative liabilities as of the balance sheet date at December 31, 2013 and on the initial valuation date at October 9, 2013, respectively:

	December 31,			October 9,
	2013			2013
Common stock issuable upon exercise of warrants		1,500,201			1,500,201
Estimated market value of common stock on measurement date	$	1.02		$	1.02
Exercise price	$	2.02		$	2.02
Risk free interest rate (1)		0.78	%		0.78	%
Expected dividend yield		0	%		0	%
Expected volatility (2)		301	%		295	%
Expected exercise term in years		2.77			3.00

(1)   The risk-free interest rate was determined by management using the Treasury bill yield as of December 31, 2013 and October 9, 2013.

(2)   The volatility was determined by referring to the average historical volatility of a peer group of public companies because we do not have sufficient trading history to determine our historical volatility.

The following tables set forth the changes in the fair value measurements of our Level 3 stock and warrant derivative liabilities during the period from October 9, 2013 to December 31, 2013:

					Increase
					(Decrease) in
			New		Fair Value of
	October 9,		Derivative		Derivative		December 31,
	2013		Liabilities		Liability		2013
Derivative liability - warrants	$	53,717	$	-	$	67,849	$	121,566
Derivative liability - tainted warrants		180,534		681,596		230,375		1,092,505
Derivative liability - convertible debt		83,004		-		84,044		167,048
Derivative liability - bridge loan		749,442		-		810,255		1,559,697
Derivative liability – Vidalia warrants		-		1,534,896		-		1,534,896
		1,066,697	$	2,216,492	$	1,192,523		4,475,712
Current Portion		1,066,697						474,895
Long-term portion	$	-					$	4,000,817

Note 8 – Fair Value Measurements

The Company measures fair value in accordance with FASB ASC Topic 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Three levels of inputs that may be used to measure fair value are:

Level 1 – Quoted prices in active markets for identical assets or liabilities.

Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 – Unobservable inputs that are supported by little or no market activity and that are financial instruments whose values are determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant judgment or estimation.

If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level of input that is significant to the fair value measurement of the instrument.

F-19

The following table sets forth by level within the fair value hierarchy our financial liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013:

	Fair Value Measurements at December 31, 2013
	Quoted Prices
	In Active		Significant
	Markets for		Other		Significant		Total
	Identical		Observable		Unobservable		Carrying
	Assets		Inputs		Inputs		Value
Description	(Level 1)		(Level 2)		(Level 3)
Derivative liability – agent warrants	$	-	$	-	$	121,566	$	121,566
Derivative liability – tainted warrants		-		-		1,092,505		1,092,505
Derivative liability – convertible debt		-		-		167,048		167,048
Derivative liability – bridge loan		-		-		1,559,697		1,559,697
Derivative liability – Vidalia warrants		-		-		1,534,896		1,534,896
Total		-		-	$	4,475,712	$	4,475,712
Current portion		-		-		474,895		474,895
Long-term portion	$	-	$	-	$	4,000,817	$	4,000,817

The following table sets forth by level within the fair value hierarchy our financial assets that were accounted for at fair value on a recurring basis as of December 31, 2013:

	Fair Value Measurements at December 31, 2013
	Quoted Prices
	In Active		Significant
	Markets for		Other		Significant		Total
	Identical		Observable		Unobservable		Carrying
	Assets		Inputs		Inputs		Value
Description	(Level 1)		(Level 2)		(Level 3)
Commodity derivative	$	-	$	146,420	$	-	$	146,420
Total	$	-	$	146,420	$	-	$	146,420

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 2 in the fair value hierarchy during the period from October 9, 2013 to December 31, 2013:

Beginning balance	$	-
Total loss		-
Settlements		-
Additions		146,420
Transfers		-
Ending balance	$	146,420
Change in unrealized gain included in earnings relating to derivatives still held as of December 31, 2013	$	146,420

F-20

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy during the period from October 9, 2013 to December 31, 2013:

Beginning balance	$	1,066,697
Unrealized loss		1,192,523
Settlements		-
Additions		2,216,492
Transfers		-
Ending balance	$	4,475,712
Change in unrealized losses included in earnings relating to derivatives still held as of December 31, 2013	$	(1,192,523	)

Note 9 – Cash Advance Obligation on Acquisition Option

In June 2011, Radiant entered into a purchase and sale agreement with Blacksands Petroleum (“Blacksands”) whereby Radiant granted Blacksands 20% of the interests in certain oil and gas properties. In partial consideration for this agreement, Blacksands delivered to Radiant a refundable deposit of $50,000. Due to various matters, Radiant elected not to pursue this transaction. On November 12, 2012, Blacksands filed a lawsuit against Radiant for breach of contract. In December 2012, Blacksands obtained a judgment against Radiant in the amount of $55,565 which included $50,000 of the original payment, $3,750 of attorney fees and $1,815 of judgment interest. In late 2013, the Company made payments to Blacksands on the total amount of $19,985. As of December 31, 2013, the outstanding liability to Blacksands is $35,580 with accrued interest of $2,200.

Note 10 – Asset Retirement Obligation

The following table reflects the changes in the asset retirement obligation (“ARO”):

Predecessor:	Amount
Asset retirement obligation as of December 31, 2012	$	331,219
Additions		-
Current period revision to previous estimates		-
Current period accretion		28,659
Asset retirement obligation as of October 8, 2013	$	359,878

Successor:	Amount
Asset retirement obligation as of October 9, 2013	$	100,000
Additions		346,600
Current period revision to previous estimates		-
Current period accretion		8,696
Asset retirement obligation as of December 31, 2013	$	455,296

Effective October 9, 2013, the Company completed the purchase of the Vidalia Properties located in Louisiana and Mississippi. These properties contain over eighty (80) wells in Louisiana and Mississippi. The Company recorded an asset retirement obligation related to these properties on the amount of $346,600.  

Note 11 – Stockholders’ Deficit

As of December 31, 2013, there were 13,784,408 shares of common shares issued and outstanding.

Sale of Common Stock

In October 2013, the Company received proceeds from the sale of 375,000 shares of common stock for cash for a total consideration of $750,000.

In October 2013, the Company issued 1,240,102 shares of common stock as part of the purchase price for the Vidalia Properties in an acquisition entered into by the Company in October 2013 (see Note 2). The fair value of these shares was determined as $1,289,706 based on share price of $1.04 on the date of the acquisition.

F-21

Common Stock Issued for Settlement of Accounts Payable

In December 2013, the Company issued 69,537 shares of common stock in order to settle accounts payable of $139,074 with two third party service providers.

Stock-Based Compensation

In December 2013, the Company issued 75,000 shares of common stock to a former director as compensation in the amount of $25,000.

For the period from October 9, 2013 to December 31, 2013, Radiant recorded $266,994 of share-based compensation related to the amortization of options granted to employees and a consultant.

2010 Equity Incentive Plan

The Company’s 2010 Equity Incentive Plan (the “2010 Plan”) provides for the grant of incentive stock options and stock warrants to employees, directors and consultants of the Company. The 2010 Plan provides for the issuance of both non-statutory and incentive stock options and other awards to acquire, in the aggregate, up to 3,000,000 shares of the Company’s common stock.

Stock Options

Stock option activity summary covering options granted to the Company’s employees and consultants is presented in the table below:

	Number of Shares			Weighted-average Exercise Price		Weighted-average Remaining Contractual Term (Years)		Aggregate Intrinsic Value
Outstanding at October 9, 2013		694,122		$	1.00		6.95	$	27,765
Granted		1,056,949			1.16		5.00		-
Exercised		-			-		-		-
Forfeited		(93,000	)		-		-		-
Outstanding at December 31, 2013		1,658,071		$	1.10		5.34	$	24,045
Exercisable at December 31, 2013		786,226		$	1.04

During the period from October 9, 2013 to December 31, 2013, the Company recognized stock-based compensation expense of $266,994 related to stock options to employees.  As December 31, 2013, unrecognized share-based compensation cost totaled $383,394.

Effective October 9, 2013, the Company entered into employment contracts with three individuals, a geophysicist, a petroleum engineer and a financial analyst to help in the operation of the oil and gas properties acquired.  The employment contracts provide for incentive payments based on financial performance of the Company and, in addition, for two of the employees include stock option agreements, considered together, provide for the purchase of up to a total of 4.5% of the fully diluted shares outstanding at the time of the closing of the financing at an option price of $1.16 per share.  For one employee, one third of the total amount of options vested upon the closing of the Centaurus Facility in October 2013 and the remaining options vest at the rate of one third of the total amount per year on the first and second anniversaries of employment.  For the second employee, the option shares vest at the rate of one third of the total amount per year beginning on the first anniversary of their employment.  The shares are exercisable at any time from the vesting date for a period of five years from the commencement of their employment.

F-22

Warrants

A summary of information regarding common stock warrants outstanding is as follows:

	Number of Shares			Weighted-average Exercise Price		Weighted-average Remaining Contractual Term (Years)		Aggregate Intrinsic Value
Outstanding at October 9, 2013		755,250		$	1.83		1.03
Issued		3,695,568		$	1.21		3.92
Exercised		-		$	-		-
Expired		-			-		-
Forfeited		(100,000	)	$	-		-
Outstanding at December 31, 2013		4,350,818		$	1.29		3.43	$	1,588,050
Exercisable at December 31, 2013		4,350,818		$	1.29

Upon the issuance of Asher convertible notes (discussed above in Note 5 – Stock and warrant derivative liabilities above) and as a consequence of its floating rate feature, these warrants and other existing warrants previously classified as equity have become tainted and are considered derivatives.  See Note 5 – Stock and warrant derivative liabilities for additional information.

Note 12 – Related Party Transactions

Related parties include (i) Macquarie Americas Corp. (“MAC”), the owner of 49% equity interest in Amber, (ii) John Jurasin, the Company’s CEO and formerly the sole stockholder of JOG, (iii) JTBOF, David R. Strawn, and David M. Klausmeyer, the Company’s stockholders, and (iv) Robert M. Gray, the Company’s director and former employee. Related party balances as of December 31, 2013 and 2012 are as follows:

	Successor		Predecessor
	December 31,		December 31,
	2013		2012
Due from related parties:
MAC	$	358,226	$	-
	$	358,226	$	-
Due to related parties:
John Jurasin	$	842,303	$	-
Robert R. Gray		50,606		-
David M. Klausmeyer		12,193		-
David R. Strawn		12,193		-
	$	917,295	$	-

Successor

MAC

Amber is partially owned by MAC, an affiliate of the Company’s lender, MBL, and Radiant uses the proportionate consolidation method to consolidate Amber. JOG, Radiant’s wholly owned subsidiary, pays for goods and services on behalf of Amber and passes those charges on to Amber through intercompany billings. Periodically, Amber will reimburse JOG for these expenses, or potentially pays for goods and services on behalf of JOG. These transactions are recorded as a due to/from Amber in JOG’s records and as a due to/from JOG in Amber’s records. Due to the fact that Radiant only consolidates its proportionate share of balance sheet and income statement amounts, the portion of the amount due from Amber related to the other interest owner does not eliminate and is carried as amounts due from Amber until the balance is settled through a cash payment. Due from related party was $358,226 as of December 31, 2013.

F-23

John Jurasin

Effective March 2010, Radiant assigned certain legacy overriding royalty interests (“ORRI”) in various projects, including the Baldwin AMI, the Coral, Ruby and Diamond Project, the Aquamarine Project, and the Ensminger Project to a related party entity owned by John M. Jurasin.  Radiant retained its working interests in these projects.  Additionally, Radiant assigned its working interest in a project, Charenton, to the related party entity. Radiant did not receive any proceeds for the conveyances and the interests assigned had a historical cost basis of $0.

From time to time, John Jurasin advances the Company various amounts in order to pay operating expenses, with no formal repayment terms. The total balance due on these advances was $104,878 as of December 31, 2013.

Additionally, two notes totaling $1,049,000 were issued to Mr. Jurasin in lieu of payment of dividends from JOG, which in turn represented funds advanced by JOG to its subsidiaries Amber and RLE to fund operations.  Interest is accrued at a rate of 4% per year.  The first note of $884,000, issued on August 5, 2010, matured on May 31, 2013. The additional note for $165,000, issued on October 12, 2010, is due and payable on demand at any time subsequent to the repayment in full of all outstanding indebtedness of the Credit Facilities (Note 4).  The balance due on these notes totaled $737,425 as of December 31, 2013. Accrued interest on these notes was $125,015 as of December 31, 2013.

David R. Strawn and David M. Klausmeyer

Mr. Strawn and Mr. Klausmeyer, shareholders of the Company, each loaned the Company a total of $12,193 between March 2002 and June 2005. The notes accrue interest at 8% per annum. The total accrued interest was $36,056 as of December 31, 2013.

Robert M. Gray

As of December 31, 2013, Mr. Gray was owed $50,606 for consulting services rendered prior to becoming an employee of Radiant. This liability is non-interest bearing.

Note 13 – Income Taxes

As of December 31, 2013, we had approximately $12,715,908 of U.S. federal and state net operating loss carry-forward available to offset future taxable income, which begins expiring in 2023, if not utilized.

IRC Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its Tax Attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The limitation under the IRC is based on the value of the corporation as of the emergence date. As a result, our future U.S. taxable income may not be fully offset by the Tax Attributes if such income exceeds our annual limitation, and we may incur a tax liability with respect to such income. In addition, subsequent changes in ownership for purposes of the IRC could further diminish the Company’s Tax Attributes.

The Company’s deferred income taxes reflect the net tax effects of operating loss and tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.

On October 8, 2013, the Company completed the purchase of Vidalia Properties located in Louisiana Mississippi. The Company followed Rule 11-01 of Reg. S-X and determined the working interest acquisition as business acquisition and applied ASC 805.  The acquisition is treated as asset acquisition for tax purpose and predecessors are of unincorporated entities, therefore no deferred tax assets were disclosed for predecessor. The income tax provision for the Predecessor was prepared as if the predecessor was a corporation for prior period comparative purpose only.

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The Components of the income tax provision are as follow:

	Successor			Predecessor
	For the Period from October 9, 2013 to December 31, 2013			For the Period from January 1, 2013 to October 8, 2013			For the Year Ended December 31, 2012
Current
Federal	$	-		$	-		$	69,897
State		-			-
Total current	$			$	-		$	69,897
Deferred
Federal	$	(1,149,448	)	$	(361,188	)	$	(69,897	)
State		(135,229	)		-			-
	$	(1,284,677	)	$	(361,188	)	$	(69,897	)
Change in valuation allowance		1,284,677			361,188
Total deferred, net	$	-		$	-		$	(69,897	)
Income tax expense	$	-		$	-		$	-

Components of deferred tax assets as of December 31, 2013 (Successor) are as follows:

	Successor
	December 31, 2013
Net operating loss – Federal	$	4,323,409
Net operating loss - State		213,570
Contingent liabilities		17,000
Valuation allowance for deferred tax assets		(4,553,979	)
Net deferred tax assets	$	-

The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty that the Company will be able to realize the benefit from it.

The reconciliation of income tax provision at the statutory rate to the reported income tax expense is as follows:

	Successor 2013
Tax provision at statutory		34.00	%
State taxes		4.00	%
Permanent differences		(0.06	)%
Change in valuation allowance		(37.94	)%
Effective tax rate		-	%

The valuation allowance is evaluated at the end of each period, considering positive and negative evidence about whether the deferred tax asset will be realized.  The Company has no positions for which it is reasonable that the total amounts of unrecognized tax benefits at December 31, 2013 will significantly increase or decrease within 12 months.  Therefore, the deferred tax asset resulting from net operating loss carry forwards has been fully reserved by a valuation allowance.

Generally, the Company’s income tax years 2010 through 2013 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where the Company has its principal operations. In certain jurisdictions, The Company operates through more than one legal entity, each of which may have different open years subject to examination. No material amounts of the unrecognized income tax benefits have been identified to date that would impact the Company’s effective income tax rate.

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Note 14 – Commitments and Contingencies

Contingencies

From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on our best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be predicted with certainty, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on its consolidated operating results, financial position or cash flows.

Radiant, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

Commitments

In connection with our Reorganization in August 2010, Radiant entered into the following agreements:

·   An employment agreement with Mr. Jurasin, who will continue as President and Chief Executive Officer, under which he will receive $250,000 per year as base salary. The base salary has increased to $250,000 effective October 8, 2013, after at least $10 million in debt or equity funding is raised and $300,000 after the Company becomes cash flow positive;

·   Employment agreements and a consulting agreement under which Radiant was obligated to pay approximately $549,000 for each of the first, second year, and third years after the closing of the Reorganization agreement.  One of the employees covered by the employment agreement resigned in March 2011 and two other employees resigned in December 2011. Although, no lawsuit was filed, the Company has accrued $50,000 as a possible settlement.

The Company currently leases office space in Houston, Texas. The Company’s office lease expired on September 30, 2012 and is currently paid on month-to-month basis. Lease expense for the period from October 9, 2013 to December 31, 2013 was $13,732.

Note 15 – Subsequent Events

In January 2014, the Company issued 50,000 shares of common stock at $0.50 per share to Black Gold in accordance with the Shallow Oil agreement.

In March 2014, the Company issued 875,000 shares of common stock in connection with the exercise of warrants and stock options.  The Company received $8,750 in proceeds from these exercises.

Effective January 15, 2014, the Company granted 198,874 stock options to an employee with an aggregate fair value of $307,904. The stock options vest over 3 years.

Effective January 23, 2014, Asher Enterprises, Inc, the holder of Radiant’s convertible debt converted the principal amount of notes of $25,000 into 25,615 shares of common stock with effective price of $0.976 per share.

Effective February 28, 2014, the Company amended the Centaurus Credit Agreement.  The Amendment increased the maximum aggregate commitment from the Lenders from $39,788,000 to $41,748,000, increased the principal amount from $40,600,000 to $42,600,000 plus any deferred interest, and increased the net profits interest conveyed to Centaurus on specific proved wells from 12.5% to 17.0%.

The Company was in multiple defaults on the Centaurus Credit Agreement, including timely delivery of audited financial statements and other reporting requirements.  Effective February 28, 2104 the lender has agreed to forbear from exercising its rights and remedies against the Company, as allowed by the Credit Agreement and related agreements for the then-existing defaults.  The lender has specifically agreed to not initiate proceedings to collect on the obligation, discontinue lending under the Credit Agreement, initiate or join in any involuntary bankruptcy petition, repossess or dispose of any collateral under the Credit Agreement or similar actions because of the existing defaults.  Should the Company default on any provisions in the Agreement other than those existing defaults, the Lenders have the right to exercise its rights and remedies against the Company, as contained in the facility agreement and through the amendment of the Facility.

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Note 16 – Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

The estimates of proved oil and gas reserves utilized in the preparation of these statements were prepared by Ralph E. Davis Associates, Inc., an external petroleum engineering firm, using reserve definitions and pricing requirements prescribed by the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to the proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2013. The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of the Company’s proved reserves are proved developed non-producing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

All of the Company’s reserves are located in the United States.

	December 31,
	2013			2012
Proved oil and gas properties	$	19,803,395		$	-
Unproved oil and gas properties		-			331,219
Accumulated depreciation, depletion and amortization		(44,714	)		-
Total acquisition, development and exploration costs	$	19,758,681		$	331,219

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

At December 31, 2013 and 2012, there were no unevaluated costs, which have been excluded from the depletion base.

	December 31,
	2013 Successor		2012 Predecessor
Acquisition of properties – proved	$	17,724,116	$	-
Acquisition of properties – unproved		-		-
Exploration costs		-		-
Development costs		1,732,679		-
Total costs incurred	$	19,456,795	$	-

Add Results of Operations for Producing Activities

For the period from October 9 to December 31, 2013 (Successor), from January 1, 2013 to October 8, 2013 (Predecessor) and for the year ended December 31, 2012, the results of operations for producing activities were as follows:

	Successor			Predecessor
	October 9, 2013 - December 31, 2013			January 1, 2013 to October 8, 2013			January 1, 2012 to December 31, 2012
Sales	$	696,661		$	1,742,512		$	3,966,017
Production costs		(483,680	)		(2,355,118	)		(3,760,437	)
Depreciation, Depletion and Amortization		(44,714	)		-			-
Income tax expense		-			-			-
Standardized measure of discounted future net cash flows	$	168,267		$	(612,606	)	$	205,580

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Estimated Quantities of Proved Oil and Gas Reserves

The following table sets forth proved oil and gas reserves together with the changes therein, proved developed reserves and proved undeveloped reserves for the years ended December 31, 2013 and 2012. Units of oil are in thousands of barrels (MBbls) and units of gas are in millions of cubic feet (MMcf). Gas is converted to barrels of oil equivalents (MBoe) using a ratio of six Mcf of gas per Bbl of oil.

	Successor					Predecessor
	October 9, 2013 to December 31, 2013					January 1, 2013  to October 8, 2013					January 1, 2012 to December 31, 2012
	Oil			Gas		Oil			Gas		Oil			Gas
	(MBbls)			(MMcf)		(MBbls)			(MMcf)		(MBbls)			(MMcf)
Beginning of the period		1,606			24,089		1,623			24,089		1,661			24,089
Revisions of previous estimates		(138	)		2,978		-			-		-			-
Extensions and discoveries		-			-		-			-		-			-
Improved recovery		-			-		-			-		-			-
Production		(7	)		-		(16	)		-		(38	)		-
Purchases of minerals in place		-			-		-			-		-			-
Uneconomical Wells		-			-		-			-		-			-
Sales of minerals in place		-			-		-			-		-			-
End of period		1,461			27,067		1,606			24,089		1,623			24,089

	December 31, 2013				December 31, 2012
Type of Reserves	Mboe				Mboe
PDP		377.9	6.3	%		400.9	6.7	%
PDNP		121.6	2.0	%		121.6	2.0	%
PUD		5,472.4	91.7	%		5,472.4	91.3	%
Total		5,971.9	100.0	%		5,994.9	100.0	%

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by the Company’s independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of future production of reserves. Revisions of previous period estimates may have a significant impact on these results. Also, exploration costs in one period may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties.

Future cash inflows for 2013 were computed by applying the average price for the period to the period-end quantities of proved reserves. The 2013 average price for the period was calculated using the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period. Adjustment in this calculation for future price changes is limited to those required by contractual arrangements in existence at the end of each reporting period. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing and producing proved oil and natural gas reserves at the end of the period, based on period-end costs, assuming continuation of period-end economic conditions. Future income tax expense was computed by applying statutory rates, less the effects of tax credits for each period presented, and to the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties, after consideration of available net operating loss and percentage depletion carryovers. Discounted future net cash flows have been calculated using a ten percent discount factor. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

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The estimated present value of future cash flows relating to proved reserves is extremely sensitive to prices used at any measurement period.

The information provided in the tables set out below does not represent management’s estimate of the Company’s expected future cash flows or of the value of the Company’s proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under ASC No. 932 requires assumptions as to the timing and amount of future development and production costs. The calculations should not be relied upon as an indication of the Company’s future cash flows or of the value of its oil and gas reserves.

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves (stated in thousands):

	Successor			Predecessor
	October 9, 2013 - December 31, 2013			January 1, 2013 to October 8, 2013			January 1, 2012 to December 31, 2012
Future cash inflows	$	141,373		$	170,288		$	172,111
Future production costs		(56,655	)		(68,144	)		(68,866	)
Future development		(16,544	)		(18,787	)		(18,787	)
Income taxes		-			-			-
Future net cash flows		68,174			83,357			84, 458
Discounted for estimated timing of cash flows at 10%		49,634			40,341			40,550
Standardized measure of discounted future net cash flows	$	117,808		$	123,698		$	125,008

Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows at 10% per annum for the period from October 9, 2013 to December 31, 2013 (Successor), the period from January 1, 2013 to October 8, 2013 (Predecessor) and the year ended December 31, 2012 (Predecessor) (stated in thousands):

	Successor			Predecessor
	October 9, 2013 - December 31, 2013			January 1, 2013 - October 8, 2013			January 1, 2012 - December 31, 2012
Standardized Measure, Beginning of Period	$	123,698		$	125,008		$	125,214
Oil and gas sales, net of production costs		(213	)		613			(206	)
Net change in sales and transfer prices and in production (lifting) costs related to future production		-			(14,424	)		-
Extensions, discoveries and improved recovery, net of costs		-			-			-
Change in estimated future development costs		-			-			-
Previously estimate development costs incurred		-			-			-
Revisions of previous quantity estimates		(97,857	)		-			-
Accretion of discount		-			12,501			-
Net change in income taxes		-			-			-
Purchases and sales of minerals in place		92,180			-			-
Timing and other		-			-			-
Standardized Measure, End of Period	$	117,808		$	123,698		$	125,008

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