ITEM 1. DESCRIPTION OF OUR BUSINESS
Radiant Oil and Gas, Inc. (“Radiant") 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. Jurasin Oil & Gas, Inc. (“JOG”) is a Louisiana corporation chartered in 1994. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
In August 2010, JOG completed a reverse acquisition transaction through an exchange agreement (“Reorganization”), with us whereby we acquired 100% of JOG’s issued and outstanding capital stock in exchange for 5,000,002 shares of our common stock. The agreement provides for the issuance of up to an additional 1,000,000 shares of our common stock upon the satisfaction of certain performance conditions. As of December 31, 2010 performance conditions have been met that resulted in the issuance of 500,000 of these shares. As a result of the reverse acquisition, JOG became our 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.
Consequently, the assets and liabilities and the historical operations of JOG are reflected in the consolidated financial statements for periods prior to the Reorganization. Our assets and liabilities will be recorded at the historical cost basis. After the completion of the Reorganization our consolidated financial statements now include the assets and liabilities of both Radiant and JOG, JOG’s historical operations up through the closing date of the Reorganization and the combined operations of Radiant and JOG from the closing date of the Reorganization.
Effective September 9, 2010 Radiant effected a one for two reverse stock split. The accompanying financial statements have been retroactively restated to reflect the stock split.
Radiant, also does business through our wholly owned subsidiaries, JOG, Rampant Lion Energy, LLC (“RLE”) and Jurasin Oil and Gas Operating Company (“JOGop”) and our 51% interest in Amber Energy, LLC (“AE”).
Our ability to continue as a going concern is dependent on our ability to raise additional capital and to refinance our Credit Facilities. There can be no assurance that we will be successful in raising sufficient capital to continue to operate. If we do not raise capital sufficient to fund our business plan, we will curtail operations.
At the end of 2010, we had contracts for gross acres permitted, leased, optioned, or farmed-in totaling 8,595 acres. An offshore block east of Corpus Christi, Texas contains 5,760 acres in approximately 140 feet of water while all other projects are located in South Louisiana either directly on land or in water depths not exceeding 10 feet.
Definitions
BCF = Billion cubic feet of natural gas;
BO/D = Barrels of oil per day
MBC = Thousand barrels of condensate
MBO = Thousand barrels oil;
MMBO = Million barrels of oil;
MMCF = Million cubic feet of natural gas
MMCF/D = Million cubic feet of natural gas per day
Mcfe = Thousand cubic feet of natural gas equivalent
TCF = Trillion cubic feet of natural gas;
Amber Energy LLC “AE”
Radiant owns 100% of JOG which owns a 51% membership interest in AE, a limited liability company. Macquarie Bank Ltd. (“MBL”) through its affiliate Macquarie Americas Corp (“MAC”) owns the remaining 49% membership interest in AE. The members share gains and losses in the same proportion as their membership interest. AE has certain interests in 2 different project areas that are contiguous: the Ensminger Replacement Well Project and the Amber Project. Radiant, through JOG, has operational control of AE subject only to the terms of the Credit Facility. AE was formed as a project specific vehicle for the development of the Amber 3-D seismic project in St Mary Parish Louisiana. As an incentive to MBL for lending capital, its subsidiary, Macquarie America Corporation (“MAC”), became a 25% equity owner in AE. The October 4, 2007 amended credit agreement also required that if AE still owed a specific amount of money under the Credit Facility on the second anniversary of the credit agreement, MAC’s interest would automatically increase to 49%. That increase became effective with no other action on October 5, 2009.
Amber Project. AE currently has a Seismic Permit Agreement, dated April 18, 2008, which was granted by Apache Corporation to complete a 3-D survey. The Seismic Permit Agreement was extended beyond its original expiration date at no cost and now expires on September 1, 2011. AE also owns interests in seismic permits on additional acreage in the project area. AE has an Exploration Agreement, dated October 6, 2008, with Energy XXI Onshore, LLC, which provides that AE and Energy XXI Onshore, LLC will each have a 50% working interest and share the costs of the seismic project in those proportions if this project is developed as well as in any proposed wells in which AE chooses to participate. AE’s interest in wells may be less if Apache chooses to participate in the drilling of wells on the Apache acreage subject to and under the terms of the Seismic Permit Agreement. The Apache agreement provides Apache the option to participate as a working interest partner for approximately 12.5% of 100% of the working interest. In the event Apache participates, AE and Energy XXI’s working interest would each be reduced to approximately 43.75% versus the current 50% working interest. AE will manage and operate the land and lease functions as well as the actual shooting of the seismic. AE will also lead the interpretation of the resultant seismic data and generation of prospects within the project. Energy XXI Onshore, LLC will operate the drilling and production of all wells in which it participates.
While at one time AE held additional permits and permits with options to lease in this area, these permits expired before the seismic could be shot. The proposed 3-D seismic survey would consist of 50 square miles or 32,000 acres. Of this, AE has current permits or leases covering 990 acres. The Company’s plan is to renew the additional permits, commence the seismic shoot and acquire additional leaseholds; provided that at least $5,500,000 can be raised to fund this project. AE will be responsible for its 50% interest in this amount. The Company expects to reacquire the permits and additional leasehold in 2011 and to begin the seismic shoot in late 2011 or early 2012. The Company anticipates its share of the cost to re-acquire the permits and additional leasehold to be between 10% and 15% its total $2,750,000 capital requirement to complete the seismic survey.
Several regional 3-D seismic programs were shot several years ago that acquired data in and around but not over the entire project area. The plan is to augment the existing 3-D coverage by shooting the gaps between the existing programs to get full fold coverage over the objective area that has not been 3-D’ed. Seismic data can delineate the location of reserves but, on its own, cannot prove with reasonable certainty the actual reserves contained in a location. This project area will require land rig locations to fully develop.
In connection with the Seismic Permit Agreement with Apache Corporation, we entered into an Exploration Agreement with Apache Corporation. Apache’s acreage is subject to a pending lawsuit regarding the retention by Apache of non-producing deep rights of some of the various underlying leases. The Company does not believe that this litigation will have a material impact on the Company or its operations. The pending lawsuit was filed against Apache by certain of the landowners for alleged environmental damages and lack of development of the deeper horizons (below current production) prior to AE obtaining the seismic permit and sub-lease. AE is not a party to the suit and we believe that the obtaining of a permit and sub-lease does not subject AE to becoming a party to the lawsuit. Management believes that Apache, by virtue of the agreement with AE, has diffused the issue of lack of development of deep rights since the purpose of the program is to develop such rights. To management’s knowledge, the suit is dormant and the decision to proceed is an acceptable business risk.
Ensminger Replacement Well Project: The Ensminger Replacement Well Project covers 634 acres, in which AE holds a 12.5% working interest before pay out and a 15% working interest after pay out (net of sublease described below). Energy XXI Onshore, LLC (“Energy XXI”), a 50% working interest owner, is the operator for this project. AE entered into an Exploration and Ratification and Joinder Agreement, dated effective February 1, 2010, with J&S 2008 Program, LLC and others (collectively “J&S”) for the drilling of the replacement well. Under the terms of the agreement, AE is not responsible for funding the drilling and completion of the initial well in connection with this project in exchange for the sub-leasing to J&S of a 37.5% interest in the project before payout and 35% interest in the project after payout. The Ensminger #2 well was drilled to a Total Vertical depth of 15,101’. The operator was unable to log the lowest portion of the well and the participants are using 3-D seismic to determine in which direction a contemplated side-tracking of the well should be pursued. For safety reasons, the well has been temporarily abandoned during this evaluation period. The Company believes that the side-tracking may be considered a part of the original well drilling and, as such, the Company would not be responsible for any associated costs. AE will be responsible for its proportionate share of the drilling and completion costs of any additional wells on this project. The Company does not anticipate an additional well until 2012.
In the first quarter of 2011, the company participated in an operation in the original Ensminger #1 well in which the well was cleaned out to a depth below the 69 sand. This operation provided data that sets up the well as a potential sidetrack into the 68 sand, thereby providing an option for sidetrack operations on a well other than the Ensminger #2 well. On the way out of the hole the lower part of the 67 sand was perforated and showed an initial bottom hole pressure of over 8000 pounds but was deemed non-commercial. The company and partners elected not to set this well up for production and the Company is further evaluating the well for proposed future operations as a sidetrack into the 68 sand or to add additional perforations into the 67 sand.
The 3D seismic data was reprocessed by Seismic Exchange, Inc. for AVO attributes. The company has used this new data set to reinterpret the structural geology of the project the results of which are included in the footnotes which provided for reserve additions for the well and reservoir.
Energy XXI has indicated that they would relinquish their interest in the project to the participants and the company is contemplating absorbing the EXXI relinquished interest for a possible overall interest of over 50 % working interest with operations, subject to other partner elections. The company is mindful of any lease expirations and has successfully negotiated with the landowners and leaseholders in the past to facilitate primary and or extended operations on the leasehold. Due to this history with the landowners originating in 2002 management believes that it can extend lease terms if necessary although this is not certain. Management is currently moving forward with contingency plans on the leasehold.
The Ensminger Replacement Well Project is located onshore in sugar cane fields in St. Mary Parish, Louisiana. The drilling of the Ensminger #2 replacement well to the Ensminger #1 was operated by Energy XXI. Additional operations would now, upon final approval of participants, be operated by the Company. The Ensminger # 1 well was a project originated and 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 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.
In connection with the assignment of interest from ExxonMobil Corp, and Century Exploration New Orleans, Inc., AE assumed the obligation to plug the Ensminger #1 well, which includes providing a bond in the amount of $730,000, which we obtained by collateralizing our assets under the letter of credit pursuant to the AE Credit Facility. Energy XXI Offshore has already assumed its 50% share of the bond. J&S will assume its share of this obligation upon final completion of the replacement well as a producing well. In the event the project is not successful, the well(s) will be plugged in accordance with state regulations and the bond will be released. AE’s current share of the bond’s collateralization is $365,000. After assumption of all participants’ shares, AE will be responsible for $109,500 of the bond. The Company has accrued for its share of the obligation to plug the well as part of its Asset Retirement Obligation.
Rampant Lion ”RLE”
Radiant owns 100% of RLE via its 100% ownership of JOG. RLE owns working and overriding royalty interests in a lease, comprising approximately 5,760 acres located in the federal waters offshore Texas. The Aquamarine Project is approximately 28 miles from shore and is located in 140’ of water. Management had prior discussion and contract negotiation with EOG Resources, Inc. (“EOG”) regarding a platform owned by EOG and which is currently active as a pipeline hub. Management also appraised the platform’s utility during that time and did an onsite inspection, with EOG’s approval. Due to this history, management believes that, if prudent and economic at the time, an agreement can be made to utilize the platform for the drilling and producing of our prospective wells.
The platform would only be put back into service once the first well is ready to be drilled which we expect will be in 2012 or later The acreage position in which RLE holds its interest in the Aquamarine Project is subdivided into an exclusive area (Aquamarine Project - Marg A- Exclusive) and a non-exclusive area (Marg A-5 Non-Excusive). In the entirety of the leasehold, Offshore Paragon Petroleum Inc. (“Paragon”) enjoys a back-in after project payout (being the payout of all costs attributable to the drilling, completion, equipping and operating of the first two wells drilled on the block) of 10% of 8/8ths working interest which interest shall be subject to all royalties and other burdens in existence as of February 2006. Paragon shall have the same right to participate or not in any future wells drilled and, if participating, will pay its proportionate share of drilling and other costs incurred. Failure to participate shall be subject to any penalties as provided for in the applicable Joint operating Agreement. Please see “Risks Related To Our Business” for a discussion of the recent moratorium imposed by the federal government regarding the drilling of wells in federal waters.
Aquamarine Project - Marg A Exclusive Area.
Marg A Exclusive includes 2,520 acres located in the federal waters offshore Texas, more specifically Mustang Island Block MU 758. Pursuant to the participation agreements with Challenger Minerals, Inc. and Medco Energi US, LLC, the Company holds an 11.25% working interest upon the well’s first production, a 28.125% working interest after the well pays out (assuming the Company exercises its right to back-in for an additional 16.885%), and a 21.325% working interest after the project pays out and assuming that Paragon Petroleum, Inc. elects to back-in for a 10% of 8/8ths working interest. In the event Paragon Petroleum does not elect to exercise its option, the Company’s interest will remain at 28.125%.A well was re-completed in May 2010 and production resumed shortly thereafter. Medco Energi US, LLC is the operator for this project.
There is currently one well producing from the field. It is supported from a caisson which is tied into the MU 759 “B” production platform, located on a contiguous block. Chevron Corporation (“Chevron”) discovered normally-pressured multiple pays in the Rob L, Rob M and Marg A sands in 1977. Chevron set the ‘A’ platform and successfully drilled and completed 6 wells. The block has cumulative production of 96 BCF and 67 MBO. The last date of production from this platform was in 1994. RLE generated and caused the Medco #1 well to be drilled in October 2006. This well tested the under-produced Marg A sands in a structurally higher position than the Chevron wells. The Medco well was successful in finding 103’ of net pay in 7 sands. The well was successfully tested in the Marg A at 2.5 MMCF/D & Marg A-2 sands at 1.75 MMCF/D and was producing from the Marg A - B sand at 1.75 MMCF/D. Our strategy is to prove up additional reserves by developing the sands tested above and the other pay sands seen in the initial well. The Company’s capital requirement for developing these sands is expected to be less than $15,000 through 2011. We believe that the trap is a downthrown 3 and 4-way closure and that the sands are consistent across the structure and block.
Aquamarine Project - Marg A-5 Non-Exclusive.
Marg A-5 is located on Mustang Island Block MU 758 in the federal waters offshore Texas. We currently hold a 100% working interest on 3,240 acres that make up the Aquamarine Project - Marg A-5. The acreage is HBP (held by production). As 100% working interest owner, we anticipate being the operator for this project. There is currently no activity on this project. In order to drill and complete a well on this project, the Company anticipates it will need to raise an additional $15,000,000 from third parties through debt, issuance of equity, or sale of partial interest in the project. The Company does not anticipate spending any capital on this project through 2011.
RLE has identified a normally-pressured Marg A-5 prospect on the northeast portion of our block. The Marg A-5 sand is the lowermost of the Marg A sands locally. There is approximately 2,500’ of gross sand section in the Marg A. Although our primary target is the Marg A-5, we intend to test the majority of this section in a trapping position.
In the adjacent block to the east, MU 759, EOG discovered commercial gas in January 1994. We understand that EOG drilled 6 productive well and set two structures, and that they found pay in 8 sands within the Marg A section. The wells have cumulatively produced 45.5 BCF and 165 MBO. These sands are normally-pressured. The trap is up-thrown with 3 way dip closure. Seismically, there is some amplitude anomalies with phase changes within the Marg A section that are direct ties to the pay sands, including the Marg A-5.
We have interpreted 3D seismic and have integrated it with the sub-surface control. Our prospect is up-thrown with 3 way dip closure and has an amplitude anomaly with phase changes at the Marg A-5 level. Approximately 7,000’ to the northwest, Chevron drilled its #1 well in November 1985. This well encountered 65’ of Marg A-5 sand at 9,710’. The sand is in a non-trapping position and had no amplitude or phase change characteristics. At our location, we will be >200’ high to this well at the Marg A-5 sand level. The prospect has 335 acres of closure.
Ruby-Diamond-Coral Project
There are currently 4 leases that comprise this prospect. We have a 65% working interest in the Ruby-Diamond-Coral Project before pay out and a 56.25% working interest after pay out. We intend to act as the operator of this project to drill and complete a well. Ruby-Diamond-Coral consists of 1,481 gross acres in shallow Louisiana state waters offshore St. Mary Parish. Some additional leasing may be required before drilling is initiated.
Pursuant to an Option Agreement dated April 15, 2008, with Energy XXI, Energy XXI was to acquire 100% of the leases and we were provided the option to participate for a 25% working interest. The Option Agreement was subsequently assigned to Buccaneer Resources, LLC “Buccaneer”. As of the date hereof, none of the leases had been assigned to Buccaneer Resources, LLC pursuant to the Option Agreement, although they will be upon request by Buccaneer.
In addition, pursuant to an Exploration Agreement among JOG, Sweet Bay Exploration, LLC “Sweet Bay” and Energy XXI, JOG and Sweet Bay were provided the right to receive a permanent overriding interest of 2.5% and a 2% overriding interest which could be converted into a 25% working interest at payout. Subsequently, Energy XXI withdrew from the project but the Exploration Agreement has never been amended to reflect the terms between the remaining parties. We anticipate amending the Exploration Agreement in the second quarter of 2011 to reflect all current terms.
The Ruby-Diamond-Coral Prospect 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 Text. W. sands which have produced 103 BCF and 2.8 MMBC in the field proper. Three Text W sands, ranging in depths from 12,300′to 12,800′ are the specific prospect targets. The initial proposed well will be a re-entry and a sidetrack from the inactive COCKRELL #1 SL 14354 borehole. A directional well will be drilled to 13,702′MD (13,000′ TVD). The estimated net cost to drill and complete the proposed sidetrack is $3,450,000. We expect to fund this project with the issuance of equity, or to sell a portion or all of our interest which could include having our interest carried and significantly reduce or eliminate our capital requirement.
The secondary objective in the Ruby-Diamond Coral Prospect 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. The Company does not expect to drill to the Cib Op in 2011 unless we are able to sell a portion of our interest and significantly reduce or eliminate our capital requirement.
In the following tables under Productive Wells, Drilling Activity and Acreage, “Gross” refers to the total project amount and “Net” refers to our proportionate share of that item based on our working interest.
Priority of projects
The Company intends to proceed with the projects as capital is raised with priority given to projects most ready to execute. Management’s order of priority of projects is as follows:
1.
Ensminger Replacement Well Project -- Continue operations on the well for which we expect to execute as stated above.
2.
Ruby, Diamond, Coral Project -Drill the initial proposed well which is a re-entry and sidetrack out of the Cockrell #1 well as discussed above.
3.
AE Project. Continue with re-activation of our lease position for which title work has been completed. Execute as described above.
4.
RLE --Aquamarine-Marg A 5 Exclusive Area and Aquamarine-Marg A 5 Non-Exclusive Area . Due to the economics with current gas pricing, we do not intend to pursue these projects on an immediate basis. We shall monitor pricing and economics to determine when or if to execute on the project.
The priority of projects may fluctuate as dictated by issues such as variance of oil and gas pricing, ability to timely execute on acreage acquisition, change in government regulation, amount of capital raised to execute on our projects, in addition to the factors cited in the section titled “Risk Factors”.
ITEM 1A.
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.
During the twelve months ended December 31, 2010 and December 31, 2009, Radiant generated net revenues of $169,649 and $106,502, respectively. For the twelve months ended December 31, 2010, Radiant operating expenses were $2,898,691 resulting in a loss from operations of $2,729,042. For the twelve months ended December 31, 2009, Radiant operating expenses were $843,282, resulting in a loss from operations of $736,780. It should be expected that we will continue to experience operating losses at least through 2011. There can be no assurance that we will ever achieve net income from operations or otherwise become profitable.
We have negative cash flow from operations.
We have historically experienced losses and negative cash flows from operations and these conditions raise substantial doubt about our ability to continue as a going concern and management is attempting to raise additional capital to address our liquidity. We believe that our negative cash flow from operations will continue at least through 2011. There can be no assurance that we will ever be able to raise sufficient capital to generate positive cash flow from operations.
We will need to raise significant capital during 2011.
At December 31, 2010, we had current assets of $440,903, current liabilities of $6,214,933 and $5,774,030 of negative working capital. As of this date, the Company has nominal current assets and a significant working capital deficit. The Company intends to raise up to $12,000,000 during 2011 to fund capital expenditures, working capital needs and reduce debt in 2011. In September 2011, the Company will be required to pay off or refinance the Credit Facility in the amount of approximately $3,379,000 (on a stand-alone basis, RLE and AE owed approximately $5,513,000). There can be no assurance that the Company will be able to refinance the AE Credit Facility and/or the RLE Credit Facility. MBL has agreed to convert $1,000,000 of the Credit Facility into up shares of Company’s common stock pursuant to the Debt Conversion. The failure to refinance the Credit Facility on acceptable terms will cause the Company to curtail operations. Implementation of the Company business strategy will require approximately $6,065,000 of initial capital expenditures and $2,000,000 of working capital in 2011 to further develop the business plan. There can be no assurance that that the best-efforts financings will result in required fundings on favorable terms, if at all. The failure to raise needed funds would have a material adverse effect on our business, financial condition, operating results and prospects, could cause us to curtail operations. See “Risk factor - We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.”
We have a Going Concern
As of December 31, 2010, our auditor determined that our financial conditions raised substantial doubt as to our ability to continue as a going concern. Management plans to raise equity financing and to restructure our Credit Facility. Our ability to continue as a going concern is dependent on our ability to raise additional capital and refinance our Credit Facility, of which there can be no assurance that we will be successful. If we do not raise capital sufficient to fund our business plan, we may not survive.
The terms of AE’s and RLE’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 AE and RLE both have secured credit facilities with MBL. All of the RLE and AE assets secure the Credit Facility. As of the date hereof, the outstanding principal and interest on the Credit Facility was approximately $3,379,000 (on a stand-alone basis, RLE and AE owed approximately $5,513,000). The Credit Facility matures in March 2011. Radiant is prohibited from taking any material action without the consent of MBL including selling or disposing of any assets of AE and RLE. To secure the payment of all obligations owed pursuant to the Credit Facility, AE and RLE, respectfully, granted the bank a security interest and lien on all of their respective assets. The occurrence of an event of default under any of our obligations would constitute a cross-default and would subject us to foreclosure to the extent necessary to repay any amounts due. If the bank were to foreclose on either AE’s or RLE’s assets, such event would have a material adverse effect on our financial condition.
Failure to retire or refinance either the AE Credit Facility or the RLE Credit Facility will adversely affect our financial condition.
We do not have sufficient funds to repay the AE Credit Facility and the RLE Credit Facility when our debt obligations to them become due. Accordingly, we will be required to obtain funds to repay the Credit Facility either through refinancing or the issuance of additional equity or debt securities. As we have no commitment in place to effect such actions, there is no assurance that we can refinance such indebtedness. The failure to refinance either the AE Credit Facility or the RLE Credit Facility would adversely affect the Company and could cause us to curtail operations.
We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.
We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements will depend on numerous factors, and we cannot predict accurately the timing and amount of our capital requirements. We intend to primarily finance our capital expenditures through best efforts equity and debt offerings. There is no assurance that we will be successful in these capital raising activities. Adverse change in market conditions could make obtaining this financing economically unattractive or impossible.
The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, ceased to provide funding to borrowers.
A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our credit facilities which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or not purse growth opportunities.
Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. As a result, we may lack the capital necessary to capitalize on business opportunities described herein and be successful in our business operations. There is no assurance that we will be successful in raising the capital necessary to implement our business plan.
To service our indebtedness, we will require a significant amount of cash. Our ability to raise significant capital depends on many factors beyond our control.
Our ability to make payments on and to refinance our indebtedness (including the existing Credit Facility) and to fund planned capital expenditures and development and exploration efforts will depend on our ability to raise cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure you that future borrowings or other facilities will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.
We may be required to:
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obtain additional financing;
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sell some of our assets or operations;
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reduce or delay capital expenditures, development efforts and acquisitions; or
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revise or delay our strategic plans.
If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure you that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.
Potential claim for shares of common stock by a third party finder.
In April 2010, the Company entered into a reorganization agreement with Jurasin that terminated as conditions precedent to closing, were not satisfied. A third party finder was to receive 780,000 shares (on a post split basis) pursuant to this agreement for services relating to the reorganization, not related financing efforts. As such agreement was terminated due to closing conditions not being satisfied such party is not entitled to receive any shares of Company common stock. While this party has stated to one of our directors that he is entitled to an unspecified number of shares, the Company intends to vigorously defend any claim made against the Company and any of its directors by this third party. As no formal demand against the Company has been made, it is not possible to quantify such claim.
Risks Related to Our Business
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:
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domestic and foreign supplies of oil and natural gas;
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price and quantity of foreign imports of oil and natural gas;
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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;
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level of consumer product demand;
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level of global oil and natural gas exploration and productivity;
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domestic and foreign governmental regulations;
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level of global oil and natural gas inventories;
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political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
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weather conditions;
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technological advances affecting oil and natural gas consumption;
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overall U.S. and global economic conditions; and
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price and availability of alternative fuels.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us, in future periods, having to make substantial downward adjustments to any estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.
Our future business will involve many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
We engage in exploration and development drilling activities. Any such activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.
Our business involves a variety of inherent operating risks, including:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of gas, oil and formation water;
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natural disasters, such as hurricanes and other adverse weather conditions;
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pipe, cement, subsea well or pipeline failures;
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casing collapses;
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mechanical difficulties, such as lost or stuck oil field drilling and service tools;
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abnormally pressured formations; and
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environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:
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injury or loss of life;
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severe damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigations and penalties;
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suspension of our operations; and
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repairs to resume operations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our properties will materially affect the quantities and present value of those reserves.
Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of any proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
Unless we replace crude oil and natural gas reserves any future reserves and production will decline.
Our future crude oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace any reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.
Relatively short production periods or reserve life for Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.
High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the United States. Typically, 50 percent of the reserves of properties in the Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. A significant amount of our prospects are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.
The Company may need to obtain bonds or other surety in order to maintain compliance with those regulations promulgated by the BOEMRE (MMS).
For offshore operations, lessees must comply with the BOEMRE (MMS) regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Shelf and removal of facilities. To cover the various obligations of lessees on the U.S. Outer Continental Shelf of the Gulf of Mexico, the BOEMRE (MMS) generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. We are currently reviewing whether we are exempt from the supplemental bonding requirements of the BOEMRE (MMS). The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.
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:
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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
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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:
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severe weather;
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delays or decreases in production, the availability of equipment, facilities or services;
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delays or decreases in the availability of capacity to transport, gather or process production; and/or
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changes in the regulatory environment.
Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.
Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we. We actively compete with other companies when acquiring new leases or oil and gas properties. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves.
We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:
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the volume, pricing and duration of our natural gas and oil hedging contracts
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supply of and demand for natural gas and oil;
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actual prices we receive for natural gas and oil;
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our actual operating costs in producing natural gas and oil;
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the amount and timing of our capital expenditures and decommissioning costs;
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the amount and timing of actual production; and
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changes in governmental regulations or taxation.
The timing of any production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Our offshore operations will involve special risks that could affect operations adversely.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.
Market conditions or transportation impediments may hinder access to oil and gas markets or delay production.
Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.
We are not the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.
As we carry out our planned drilling program, we will not serve as operator of all planned wells. It is expected that AE will be the operator of its seismic shooting, it is expected that Energy XXI will be the operator of the AE and Ensminger projects. It is expected that Medco will be the operator of the Aquamarine Exclusive area and that a third party will operate the Baldwin project. It is management’s expectation that the Company will operate the Aquamarine - Non-Exclusive project as well as the Ruby-Diamond-Corel project. 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:
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the timing and amount of capital expenditures;
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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;
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the operator’s expertise and financial resources;
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approval of other participants in drilling wells;
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selection of technology; and
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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. 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:
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require the acquisition of a permit before drilling commences;
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restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
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impose substantial liabilities for pollution resulting from operations.
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Failure to comply with these laws and regulations may result in:
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the imposition of administrative, civil and/or criminal penalties;
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incurring investigatory or remedial obligations; and
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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.
We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.
Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, or if current or prior operations were conducted consistent with accepted standards of practice. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.
On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.
The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.
We currently do not hedge but believe that we will hedge in the near future. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.
If we acquire properties, we may be unable to successfully integrate the operations of the properties we acquire.
Although we have no present intentions to acquire any properties, we expect that we will evaluate property acquisitions in the course of our ordinary business operations. If we acquire any properties, the integration of the operations of the properties we acquire with our existing business will be a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:
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operating a larger organization;
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coordinating geographically disparate organizations, systems and facilities;
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integrating corporate, technological and administrative functions;
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diverting management’s attention from other business concerns;
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an increase in our indebtedness; and
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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.
If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our acquisitions.
We do not currently have commodity price risk; however, if we are able to produce oil and gas in the near future we may experience commodity price risk. Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.
The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.
The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential. Inspections may not be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.
We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” 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.
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. We currently have all the necessary permits for our proposed projects save and except the permits to drill individual wells. We do not anticipate any difficulty acquiring them at a cost of less than $10,000 per well before beginning any drilling operation
If we are unable to acquire or renew our lease on oil and gas properties we could be unable to drill additional wells.
The Company’s lease on the Ensminger well expires in April 2011. The Company expects to either begin an operation that will extend the lease or will be able to negotiate a new lease although there can be no assurance we will be successful. If we are unable to extend or renew the lease, the impact on the Company’s proved undeveloped reserves as of December 31, 2010 would be a reduction of 1.2 BCFe and $4.1 million of projected discounted cash flows.
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. 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 agreements with Mr. Jurasin.
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.
We recently issued an aggregate of 3,543,205 shares for services rendered, which issuances may adversely affect the market value of our stock.
In July and August 2010, we issued 543,205 shares of common stock to an investor relations consultant, and 3,000,000 shares of common stock (of which 2,000,000 are subject to forfeiture) to an investment banker, both issuances for services to be rendered. These issuances may be perceived as an overhang on the market and could depress any market that may develop for the Company common stock as well as the offering price of our equity securities in subsequent financings.
There is no assurance of continued public trading market and being a low priced security may affect the market value of stock.
To date, there has been only a limited public market for our common stock. Our common stock is currently quoted on the OTCBB. As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations as to the market value of our stock. Our stock is subject to the low-priced security or so called “penny stock” rules of the SEC that impose additional sales practice requirements on broker/dealers who sell such securities. Some of such requirements are discussed below.
A broker/dealer selling “penny stocks” must, at least two business (2) days prior to effecting a customer’s first transaction in a “penny stock,” provide the customer with a document containing information mandated by the SEC regarding the risks of investing in our stock, and the broker/dealer must receive a signed and dated written acknowledgement of the customer’s receipt of that document prior to effecting a customer’s first transaction in a “penny stock.”
Subject to limited exceptions, a broker/dealer must obtain information from a customer concerning the customer’s financial situation, investment experience and investment objectives and, based on the information and any other information known by the broker/dealer, the broker/dealer must reasonably determine that transactions in “penny stocks” are suitable for the customer, that the customer has sufficient knowledge and experience in financial matters, and that the customer reasonably may be expected to be capable of evaluating the risks of transactions in “penny stocks.” A broker/dealer must, at least two business (2) days prior to effecting a customer’s first purchase of a “penny stock” send a statement of this determination, together with other disclosures required by the SEC, to the customer, and the broker/dealer must receive a signed and dated copy of the statement prior to effecting the customer’s first purchase of a “penny stock”.
A broker/dealer must also, orally or in writing, disclose prior to effecting a customer’s transaction in a “penny stock” (and thereafter confirm in writing):
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the bid and offer price quotes in and for the “penny stock,” and the number of shares to which the quoted prices apply;
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the brokerage firm’s compensation for the trade; and
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the compensation received by the brokerage firm’s sales person for the trade.
In addition, subject to limited exceptions, a brokerage firm must send to its customers trading in “penny stocks” a monthly account statement that gives an estimate of the value of each “penny stock” in the customer’s account. Accordingly, the Commission’s rules may limit the number of potential purchasers of the shares of our common stock.
Resale restrictions on transferring “penny stocks” are sometimes imposed by some states, which may make transaction in our stock more difficult and may reduce the value of the investment. Various state securities laws pose restrictions on transferring “penny stocks” and as a result, investors in our common stock may have the ability to sell their shares of our common stock impaired.
There can be no assurance we will have market makers in our stock. If the number of market makers in our stock should decline, the liquidity of our common stock could be impaired, not only in the number of shares of common stock which could be bought and sold, but also through possible delays in the timing of transactions, and lower prices for the common stock than might otherwise prevail. Furthermore, the lack of market makers could result in persons being unable to buy or sell shares of the common stock on any secondary market.
We have never paid dividends on our common stock.
We have never paid dividends on our common stock and do not presently intend to pay any dividends in the foreseeable future. We anticipate that any funds available for payment of dividends will be re-invested into the Company to further its business strategy.
We may issue preferred stock.
Our Articles of Incorporation authorizes the issuance of up to 5,000,000 shares of blank check preferred stock with designations, rights and preferences determined from time to time by the Board of Directors. Accordingly, our Board of Directors is empowered, without stockholder approval, to issue preferred stock with dividend, liquidation, conversion, voting, or other rights which could adversely affect the voting power or other rights of the holders of the common stock. In the event of issuance, the preferred stock could be utilized, under certain circumstances, as a method of discouraging, delaying or preventing a change in control of the Company. Although we have no present intention to issue any shares of its authorized preferred stock, there can be no assurance that the Company will not do so in the future.
Any trading market that may develop may be restricted by virtue of state securities “Blue Sky” laws which prohibit trading absent compliance with individual state laws. These restrictions may make it difficult or impossible for our security holders to sell shares of our common stock in those states.
There is no public market for our common stock, and there can be no assurance that any public market will develop in the foreseeable future. Transfer of our common stock may also be restricted under the securities regulations and laws promulgated by various states and foreign jurisdictions, commonly referred to as “Blue Sky” laws. Absent compliance with such individual state laws, our common stock may not be traded in such jurisdictions. Because the securities registered hereunder have not been registered for resale under the Blue Sky laws of any state, the holders of such shares and persons who desire to purchase them in any trading market that might develop in the future, should be aware that there may be significant state Blue Sky law restrictions upon the ability of investors to sell the securities and of purchasers to purchase the securities. These restrictions prohibit the secondary trading of our common stock.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None
ITEM 2.
ITEM 2. PROPERTIES
Productive Wells
The following table sets forth our working interests in productive wells:
Our only productive well is the Medco MU 758 B-1 well.
Drilling Activity
The following table sets forth our drilling activity.
The only well we drilled in 2010 was the Ensminger #2. The well is temporarily abandoned subject to further evaluation.
Acreage
The following table sets forth our working interests in developed and undeveloped acreage:
Our estimate of acreage includes those that we directly own and our pro rata share of acreage associated with AE which is accounted for on a proportional consolidation basis. Our interest in AE was 51% as of December 31, 2009.
The following table summarizes potential expiration of our onshore and offshore undeveloped:
All of the Company’s onshore leases expire in 2011. If the Company does not begin drilling operations on the Ensminger lease by April 20, 2011 then the lease (364 gross acres, 23 net acres) will expire. The Company is reviewing its alternatives to bring operations or to re-lease the acreage. The Company’s Amber lease of 990 gross and 252 net acres expires on September 1, 2011. The Company anticipates beginning operations to hold the lease. Otherwise the estimated lease renewal cost is $300,000 gross and $76,500 net.
Capital Expenditures, Including Oil and Gas Costs Incurred
Property acquisition costs:
Oil and Gas Production and Prices
The following table sets forth our average daily production and average sales prices from our net ownership:
Production increased as a result of a successful workover on the MU 758 B1 well.
Production Unit Costs
The following table sets forth our production unit costs. Production costs include lease operating expense and production taxes.
Lease operating expenses decreased as the operator of the MU 758 B1 well performed unsuccessful workover operations in 2009 along with the expense of relieving fluid buildup on the MU 758 B-1 well.
Reserves
The disclosure requirements for registrants engaged in oil and gas producing activities are prescribed by Rule 4-10 of Regulation S-X and Industry Guide 2 of Regulation S-K. Under these guidelines proved oil and gas reserves are defined as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Reasonable certainty means a high degree of confidence that the quantities will be recovered.
Proved Undeveloped Oil and Gas Reserves
Undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
The Company’s total estimated proved undeveloped reserves of 6,815 MMCFE as of December 31, 2010, increased by 3,911 as a result of upward revisions on our Ensminger project and the addition of reserves on our Coral Project. The Company’s proved undeveloped reserves are contained in these two projects and Radiant did not spend any capital to convert proved undeveloped reserves to proved developed reserves in 2010. The company sub-leased a portion of its interest in its PUD reserves in exchange for being carried on the initial drilling operations of the Ensminger well so there was no capital requirement in 2010. The initial operations performed in 2010 were not successful and the Company expects to spend approximately $242,000 on Ensminger and $3.5 million on Coral in 2011 to convert proved undeveloped reserves to proved developed reserves.
The Company currently has one proved developed well (Medco MU 758 B1). The following table summarizes the Company’s reserves at December 31, 2010:
The following table sets forth the company’s reserves:
(1) PV-10 reflects the present value of our estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the average price from the first day of every month in 2010) without giving effect to non-property related expenses such as general and administrative expenses, debt service, DD&A expense and discounted at 10 percent per year before income taxes. Average prices in effect for 2010 were $79.43 per barrel of oil and $4.38 per MMBTU of natural gas, excluding differentials.
Our estimate of proved reserves includes those that we directly own and our pro rata share of proved reserves associated with AE, which is accounted for on a proportional consolidation basis. Our interest in AE was 51% as of December 31, 2010.
Preparation of Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. As additional geosciences, engineering and economic data are obtained, proved reserve estimates are more likely to increase or decrease than to remain the same. These estimates are thoroughly reviewed and revised upward or downward as warranted.
The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers
Radiant’s Vice President, Tim McCauley is the person primarily responsible for overseeing the third party engineers we have engaged to prepare our proved reserve estimates. Mr. McCauley has served as Vice President - Engineering and Exploratory Drilling since April 2009, and of Radiant since August 2010. From 2008 to 2009, Mr. McCauley was the engineering manager for AGR Turn Key Drilling. From 2005 through 2008, Mr. McCauley was a drilling engineer and a drilling manager for Applied Drilling Technology. Mr. McCauley received his bachelor’s degree in petroleum engineering in 1996 from Texas A&M University. Mr. McCauley is a member of the Society of Petroleum Engineers, International Association of Drilling Contractors and Houston Sport and Social.. Our proved developed reserve estimate and the proved undeveloped reserves relating to the Coral project disclosed in this report were prepared by Mire & Associates, Inc. The person responsible for preparing the report was Kurt Mire. Mr. Mire is a senior engineering professional with over twenty five years of reservoir and production engineering experience with majors, independents consulting firms and as an independent consultant. He has a broad range of experience in the Gulf of Mexico, onshore Gulf Coast, Mid-continent, West Texas, East Texas, Venezuela, Brazil, India and Iraq. He has extensive experience in reserves evaluation and has a Bachelor of Science in Petroleum Engineering for the University of Southwestern Louisiana. Our proved undeveloped reserve estimate disclosed in this report was prepared by Ralph E. Davis Associates, Inc. The person responsible for preparing the report was Allen L. Kelley, Vice President. Mr. Kelley has over twenty five years experience in reservoir studies. He has evaluated energy properties throughout the major basins in North America and has done extensive work in unconventional tight gas sand reservoirs. He has participated on the U.S. Potential Gas Committee since 1990 and currently sits on the editorial committee. Mr. Kelley is a graduate of Texas Tech University with a degree in Geology.
Marketing and Customers
We intend to market substantially all of our oil and natural gas production from the properties we operate. The majority of our operated oil gas production will likely be sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.
Nearly 100 percent of our total oil and natural gas revenues during the years ended December 31, 2010 and 2009 came from production on the Aquamarine project. Medco Energi US (“Medco”) is the operator of this project and RLE has chosen to allow the operator to market its share of production. Therefore, nearly 100% of our oil and gas sales were to Medco. We have the right to market our own production and believe that there are other customers who would purchase all or substantially all of our production in the event that Medco Energi US LLC curtailed its purchases. The Company has not entered into discussions with any other potential customers.
We transport most of our oil and gas through third-party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is normally readily available. Our ability to market our oil and gas may at times be limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties could be adversely affected.
Competition
The oil and gas industry is intensely competitive. This is particularly true in the competition for acquisitions of prospective oil and natural gas properties and oil and gas reserves. We believe that the location of our leasehold acreage, our exploration, drilling, and production expertise, and the experience and knowledge of our management and industry partners enable us to compete effectively in our core operating areas. Notwithstanding our talents and assets, we still face stiff competition from a substantial number of major and independent oil and gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity. We also compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for the drilling and completion of wells. We are seeing signs of loosening rig availability, although it is quite specific by region.
Regulatory Matters
Regulation of Oil and Gas Production, Sales and Transportation
The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.
We intend to operate various gathering systems. The United States Department of Transportation and certain governmental agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities by prescribing standards. However, based on current standards concerning transportation and storage activities and any proposed or contemplated standards, we believe that the impact of such standards is not material to our operations, capital expenditures or financial position.
All of our sales of our natural gas are currently deregulated, although governmental agencies may elect in the future to regulate certain sales. The Company believes that is it in compliance with all relevant government regulations.
Environmental Regulation
Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste materials, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.
The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations:
·
Clean Air Act, and its amendments, which governs air emissions;
·
Clean Water Act, which governs discharges of pollutants into waters of the United States;
·
Comprehensive Environmental Response, Compensation and Liability Act, which imposes strict liability where releases of hazardous substances have occurred or are threatened to occur (commonly known as “Superfund”);
·
Resource Conservation and Recovery Act, which governs the management of solid waste;
·
Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;
·
Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;
·
Safe Drinking Water Act, which governs underground injection and disposal activities; and
·
U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.
We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. To date, there are no known issues that have had a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.
The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. For example, costs may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.
We believe our operations are in substantial compliance with applicable environmental laws and regulations. We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. The insurance coverage maintained by us provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.
Employees
We have 6 employees and 3 consultants as of April 15, 2011.
General
Our principal place of business is at 9700 Richmond Avenue, Suite 124, Houston, Texas 77042. The Company leases its office space and the current lease expires on April 30, 2011.
ITEM 3.
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 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.
ITEM 4. RESERVED
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our common stock is quoted on the OTCBB under the symbol “ROGI.” The market for our common stock on the OTCBB is limited, sporadic and highly volatile. The following table sets forth the approximate high and low bid quotations per share of our common stock on the OTCBB for the periods indicated. The closing price of our common stock on April 13, 2011 was $2.49.. The quotations reflect inter-dealer prices, without retail markups, markdowns, or commissions and may not represent actual transactions. Additionally, certain of these prices are prior to the August 2010 Reorganization and therefore do not reflect the acquisition of JOG. Investors should not rely on these historical price quotes as they are not reflective of our current business operations. The closing price for our common stock as reported by the OTCBB on August 5, 2010 was $1.20 per share. All quotations in this Memorandum give effect to our 1-for-5 reverse stock split effected on April 16, 2010 and our 1-for-2 reverse stock split effected on August 30, 2010.
Period
High
Low
Fiscal Year Ended December 31, 2009
Quarter ended March 31
$2.00
$1.00
Quarter ended June 30
Quarter ended September 30
$5.10
$5.10
$1.00
$1.20
Quarter ended December 31
$1.20
$1.20
Fiscal Year Ended December 31, 2010
Quarter ended March 31
$1.20
$1.20
Quarter ended June 30
$1.20
$1.20
Quarter ended September 30
$1.20
$ .06
Quarter ended December 31
$4.00
$ .06
Fiscal Year Ended December 31, 2011
Quarter ended March 31
$9.49
$1.60
Quarter through April 13
$2.49
$2.49
Holders of Record
We had 815 stockholders of record of our common stock as of April 6 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.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Not Required
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Organizational History
Prior to the Reorganization, Radiant was an inactive public company seeking merger and business operations opportunities. The Company was originally incorporated as a Colorado corporation in June 1973. In April 2010, the Company reorganized from a Colorado corporation to a Nevada corporation, effected a 5 for 1 reverse split and changed its name from G/O Business Solutions, Inc. to Radiant Oil & Gas, Inc.
In July 2010, the Company entered into an exchange agreement with JOG, which closed in August 2010. For legal purposes, Radiant is the surviving entity; however for accounting purposes, JOG is the survivor. JOG was originally incorporated as a Louisiana corporation in October 1990. A further 2 for 1 reverse split was completed September 9, 2010.
Principles of Consolidation
We consolidate all investments in which we have exclusive control. The accompanying consolidated financial statements include the accounts of JOG, RLE, and JOGOp. In accordance with established practice in the oil and gas industry, our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of AE in which we have an interest. We own a 51% interest in AE as of June 30, 2010 and as of September 10, 2010.
Going Concern
As of December 31, 2010, the Company had a working capital deficit of $5,774,030 and an accumulated deficit of $5,974,616. As a result, our auditors determined that our financial conditions raised substantial doubt as to our ability to continue as a going concern. Management plans to raise equity financing and to further restructure or pay off our Credit Facility. Management’s current plan is to raise additional equity capital to fund working capital requirements and to improve our balance sheet in order to improve our plan to refinance the Credit Facility. Our equity funding is being conducted on a best efforts basis, and we have no firm commitments for equity capital financing nor do we have any commitments regarding our refinancing. Our ability to continue as a going concern is dependent on our ability to raise additional capital, to which we have entered into an investment banking agreement with John Thomas Financial, and refinance our Credit Facility. There can be no assurance that we will be successful. If we do not raise capital sufficient to fund our business plan, we may not survive.
Results of Operations
General
Radiant seeks to develop, produce and acquire oil and natural gas properties along the Gulf Coasts of Texas and Louisiana and on the Outer Continental Shelf of the United States. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) or that are areas where there are fields where large volumes of hydrocarbons have been previously produced but are no longer strategic to major or large exploration-oriented independent oil and gas companies.
One of our primary strategies is to gather a leasehold position in fields that have previously produced and find additional development opportunities or to acquire new seismic to identify opportunities. Our management team has extensive, geological, geophysical, technical, and engineering expertise in successfully developing and operating properties in both our current and planned areas of operation. We seek to create value through the development of properties in areas that have that have significant undeveloped reserves and have close proximity to existing infrastructure allowing us to get new production to market quickly.
Over the last few years, the Company has spent the majority of its time and financial resources developing projects. This involved geological and geophysical work along with negotiating contracts and acquiring lease acreage. The program is a continuation of the work begun in 2007. Radiant’s predecessor, JOG, assembled and procured financing from MBL to buy acreage and execute the Amber, Ensminger and Aquamarine projects. The Aquamarine Project had a well drilled on it in which is currently producing and has multiple behind pipe recompletions that will be done as the pay zones deplete. The Ensminger project is one that Jurasin originally developed and was brought into the MBL facility along with the Amber project. Radiant included substantially all of the Jurasin Projects into the Reorganization and thus also included the Ruby/Diamond/Coral project. This represented substantially all of Jurasin’s assets. Since the Company has been working to develop these projects and most have not yet reached production we have incurred operating losses in 2010 and 2009 of $2,729,042 and $736,780 respectively. The operating losses that were incurred in 2010 were primarily the result of stock issued for services, costs of the reorganization and interest on the MBL notes. The operation losses in 2009 are mainly a result of interest payments to MBL for commitment to the MBL facility. We expect to continue to incur operating losses until we are able to raise equity to finish developing the projects and/or to repay the MBL facility.
In 2010 and 2009 the MU 758 B1 well was responsible for virtually all of the Company’s production. This well is located on the Outer Continental Shelf of the United States in the Mustang Island Area, Block 758 and is operated by Medco. In 2010, the Company performed a successful recompletion accounting for the increase in production we experienced.
As the only current production of the Company comes from the MU 758 B1 well, we are dependent upon raising capital through equity or the sale of a portion our interest while keeping a carried interest to be able to develop our properties. Once the Company raises the capital it will be able to determine which projects may be pursued and what results may be anticipated.
The following table summarizes selective production and financial information:
Twelve months ended December 31, 2010 compared to December 31, 2009
The Company had a loss from operations of $2,29,042 and net loss of $2,975,422 for the year ended December 31, 2010 compared to a loss from operations of $736,780 and net loss of $1,274,798 in the prior year. The primary reasons we experience net loss are that our general and administrative expenses are greater than our revenue and we are incurring interest expense. In 2007 we established a credit line with MBL to fund the general and administrative, land, geological and geophysical expenses to develop our projects with the expectation that we would continue to be funded once the projects were ready to drill wells or shoot seismic data. In 2008, we borrowed funds and began incurring interest expense as we developed the projects. In late 2008, MBL stopped funding on the credit line just as our projects were ready to begin drilling wells and complete our seismic project was ready to shoot. As a result we have been incurring interest expense and general and administrative expenses without corresponding revenue until we can raise adequate capital to drill our projects
The Company’s production both in 2010 and 2009 was primarily from the MU 758 B1well. In 2010, the Company performed a successful recompletion on this well resulting in increased production. In 2009 this well experienced a fluid build up reducing production and was also curtailed for five months in 2009 because of pipeline mechanical problems. The Company experienced an increase in production in 2010 as the operator of the well performed a successful recompletion while the fluid build up and the mechanical problems have been resolved. The 71% increase in production was slightly offset by a 8% decrease in realized prices resulting in a net increase of revenues of $63,147 (59%).
The Company’s lease operating expenses decreased by $213,894 (77%). In 2009 the operator of the MU 758 B1 performed some unsuccessful workover operations and the well experienced fluid build-up causing the Company to incur extra operating expenses. The Company’s general and administrative expenses increased by $2,276,571 (441%). General and administrative expenses in 2010 included non cash expenses relating to issuing Company stock and stock options to employees as an incentive to retain their services. Employees stock and stock option expense in 2010 totaled $993,232 and $103,693 respectively. The Company did not incur these expenses in 2009. The Company issued stock for services to a public relations firm, a geophysicist and Brian Rodriquez (a director of the Company) for a total expense of $606,103. The Company also incurred increase legal and auditing fees in connection with the Reorganization and subsequent public reporting requirements.
The Company’s had increased interest expense in 2010 of $61,791(12%) primarily from an increase in the rate on the Rampant Lion Credit Facility.
The Company recorded a gain on forgiveness of interest in 2010 of $266,084 as we entered into an amendment with Macquarie Bank to modify our Credit Facility. See Liquidity and Capital Resources.
Twelve months ended December 31, 2009 compared to December 31, 2008
The Company had an operating loss of $736,780 and net loss of $1,274,798 for the year ended December 31, 2009 compared to an operation loss of $371,353 and net loss of $936,257 in the prior year. The primary reasons we experience net loss are that our general and administrative expenses are greater than our revenue and we are incurring interest expense. In 2007 we established a credit line with MBL to fund the general and administrative, land, geological and geophysical expenses to develop our projects with the expectation that we would continue to be funded once the projects were ready to drill wells. In 2008, we borrowed funds and began incurring interest expense as we developed the projects. In late 2008, MBL stopped funding on the credit line just as our projects were ready to begin drilling wells. As a result we have been incurring interest expense and general and administrative expenses without corresponding revenue until we can raise adequate capital to drill our projects
The Company’s production is in 2009 was primarily from the MU 758 B1well. This well experienced a fluid build up reducing production and was also curtailed for five months in 2009 because of pipeline mechanical problems. Production on this well was shut in for three months in 2008 as a consequence of Hurricane Ike offsetting some of reduction in 2009. The Company expects an increase in production in 2010 as the operator of the well performed a successful recompletion while the fluid build up and the mechanical problems have been resolved.
Both the difference in the operating loss and net loss was primarily from a reduction in production and in realized product prices Revenues decreased both from the lower production and lower realized natural gas prices. The Company’s production decreased approximately 32% while the realized prices diminished nearly 70% leading to a total reduction of revenues of approximately 80%. The Company expects prices and production to be more stable in 2010.
The Company’s lease operating expenses increased approximately 32% primarily from the expense of additional repairs after Hurricane Ike.
In order to lower expenses the Company reduced staff in 2009 compared to 2008 resulting in lower general and administrative costs.
The Company’s interest expense increased approximately 4% in 2009 compared to 2008. The increase was primarily from the Company beginning to accrue interest at the default rate during 2009 partially offset by the decrease in the Company’s ownership of AE from 75% to 51%.
Liquidity and Capital Resources
Historically our primary source of funding was from capital contributions, bank borrowings and cash from operations. The Company has been successful in putting together projects and then selling a portion of its interest in that project, while keeping a carried interest, so that its capital requirement is less than its proportionate share of ownership and income. As of December 31, 2010, the Company had a cash balance of $32,453. The Company’s capital requirements in 2011 are approximately $12.6 million. We need approximately $6.4 million to fund capital expenditures as described below, approximately $4.2 million to pay off or refinance the Credit Facility and approximately $2.0 million to fund working capital needs for the next 12 months.
The following table summarizes the expected net capital expenditures in 2011:
We do not currently have the necessary capital to fund our current operations and pay our debts and other liabilities (including amounts owed under the Credit Facility). The Company must therefore raise capital on an immediate basis. There can be no assurance, however, that financing will be available to the Company on favorable terms when required, if at all. The failure to raise needed funds could have a material adverse effect on our business, financial condition, operating results and prospects, and could cause us to curtail operations.
Net cash flow used in operations was $1,107,802 in 2010 compared to $1,305,096 in 2009. The decrease in cash used in operations of $197,294 was primarily from increased production and reduced operating expense on the MU 758 B1 well. In 2009 the other asset reduction of $861,301 was from the collection of an insurance settlement. We used the funds primarily to reduce our payables by $899,489. Cash used in both years is primarily from a significant general and administrative burden while developing projects without a corresponding revenue source.
Net cash flow provided by investing activities was $343,133 in 2010 compared to net cash flow used by investing activities of $179,982 in 2009. The increase of $523,115 was primarily from an increase of $216,335 in sales of securities, $144,175 increase in asset sales and a reduction of $87,643 in property acquisitions as compared to 2009.
Net cash flow provided by financing activities was $598,268 in 2010 compared to $126,795 in 2009. This was primarily from $555,765 of net cash proceeds received in the issuance of common stock in 2010 while no stock issued in 2009. The Company borrowed $744,679 and repaid $702,176 in 2010.
Senior credit facility of RLE (“RLE Credit Facility”) and Senior Credit Facility of AE (“AE Credit Facility”) and (collectively “The Credit Facility”)
In September 2006, RLE entered into the RLE Credit Facility with Macquarie Bank Limited (MBL) originally for up to $25 million. The note was collateralized by substantially all of the assets of RLE. In addition, we pledged our ownership interest in RLE and executed a parent company guarantee to pay up to $500,000 of the outstanding indebtedness as additional security. During the year ended December 31, 2006, we incurred legal costs associated with the note of $228,751. These costs were capitalized as deferred finance charges and are amortized straight-line over three years, the life of the facility.
In February 2010, we entered into a supplemental agreement that cross-collateralized the RLE Credit facility with the assets of AE and extended the maturity date of the note to March 14, 2011.
In October 2007, AE entered into the AE Credit Facility with MBL originally for up to $10 million. The note was collateralized by substantially all assets of AE. The agreement provides 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 $1,500,000. We contributed certain lease interests to AE. AE’s company agreement provides for board representation for MBL and joint consent is required for certain transactions. Because of the shared control of AE and in accordance with established practice in the oil and gas industry, we proportionately consolidate AE. Our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of AE.
MBL has opted not to advance any further funds on the $10M facility. The principal balance due MBL exceeded $2M on October 9, 2009 and MAC’s ownership automatically increased from 25% to 49%.
We measured the fair value of the debt proceeds and the equity interest conferred on the date of inception of the facility and allocated the proceeds of the note based on the relative fair values of the debt and equity. We used the proceeds of the first tranche of the debt as the fair value of the debt. Because there were no proved reserves on the lease interests owned by AE and no objectively determinable fair value, we used the accumulated historical costs of the lease interests to approximate the fair value of the equity interest. The fair value of the investment was allocated between the note and equity interest as follows:
Equity
$
38,899
Debt
448,392
Total
$
487,291
The discount arising from this transaction was recorded at the inception of the note and is amortized straight-line over the life of the credit facility, 36 months. In addition, during the year ended December 31, 2008, we incurred legal costs associated with the note which were capitalized as deferred finance charges of $51,390 and which are amortized straight-line over the life of the facility.
In April 2008, the note was modified to accommodate our contribution of the Ensminger project to AE. Modifications included increasing the threshold for the step up of MBL’s equity interest to 49% from $1,500,000 to $2,000,000 and reclassifying tranches available within the facility. Because of the structure of the note, the modification was evaluated by comparing the borrowing capacity prior to the modification to the borrowing capacity after the modification. The borrowing capacity of the facility was unchanged. Thus, the only change to the accounting for the note is that additional deferred financing charges of $38,668 were recorded and are amortized over the remaining life of the credit facility, 18 months.
In February 2010, we entered into a supplementary agreement with MBL under which, they effected a partial release of mortgage in certain assets 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.
Beginning at the closing of the Reorganization through April 7, 2010 we entered into a series of amendments under which:
·
The maturity date of our Credit Facilities was extended to September 9, 2011;
·
All prior defaults or events of default prior to the modification of the Credit Facilities were waived;
·
the RLE Credit Facility was amended to eliminate any financial ratios or production covenants that would put us into default on the notes.
·
Interest on the AE Credit Facility outstanding loans had been accrued at a fixed rate based on the prime rate at the time the Company borrowed the funds and upon default, at the default rate. In the loan modification, prior interest due was stipulated to be $361,221 ($184,223 net to our proportionate share) as of July 28, 2010 resulting in a gain on forgiveness of interest in the amount of $521,733 ($266,804 net to our proportionate share).
·
We agreed to make monthly interest payments at prime rate plus 8% on the RLE credit facility and made principal reduction payments on the Credit Facilities of $100,000 on each of August 5, 2010, August 20, 2010 and September 20, 2010. We also made a payment of $250,000 on November 15, 2010. We shall also pay amounts equal to any proceeds from the sale of collateral, any insurance proceeds received and 1/6th of the gross proceeds of any subsequent capital raised.
·
We cross-collateralized the RLE and AE Credit Facilities and AE and RLE each executed an unconditional guarantee of payment of the obligations under both Credit Facilities; Radiant executed a limited guarantee of payment of up to $500,000 for the obligations under both Credit Facilities;
·
MBL has agreed to convert $1,000,000 of the Credit Facilities into shares of Radiant common stock at a conversion price equal to the per share price of the most material equity raise from a non-affiliated person. provided that upon each such conversion there is (i) no event of default in the Credit Facility and (ii) the Company has repaid $900,000, of aggregate principal and interest payments on the Credit Facility after April 7, 2010.Since we proportionally consolidate AE, the $1,000,000 conversion of debt to equity would only result in a $510,000 reduction to notes payable on our consolidate financial statements and;
·
MBL agreed to re-convey to JOG all interests in real property and membership interests conveyed to its affiliate Macquarie Americas Corp (“MAC”) in connection with the AE Credit Facility, provided that all obligations under the AE Credit Facility, RLE Credit Facility, and all letters of credit shall have been paid in cash prior to maturity.
In addition to the outstanding note payable, $186,150 is obligated as collateral for a letter of credit supporting a bond related to the plug, abandon, and restoration obligations on the Ensminger Project.
In April 2011, the Credit Facility was amended to extend the maturity date to the earlier of September 9, 2011. The monthly amortization payments have been suspended until the maturity date. The Company has agreed make a payment of not less than $900,000 upon the consumption of the Convertible Preferred Equity Raise. The Company will also continue to pay an amount equal to 1/6th of the proceeds from any capital raise other than the Convertible Preferred Equity Raise, any proceeds from the sale of collateral, and any insurance proceeds received. The Agreement also modified the original debt conversion feature. MBL will convert a maximum aggregate of $1,000,000 if payments of at least $900,000 have been made and no event of default exists. The conversion price will be at a price equal to the per share price of Radiant’s most recent material equity raise from a non-Affiliated Party. The only material event of default is to make the required payments.
Margin Loan and line of credit
We have a line of credit available from our bank for up to $25,000 that carries 7% annual percentage rate and had a margin loan facility from our broker-dealer that carried a variable rate as discussed in Note 4. In July 2010 we paid off and closed the margin account. As of December 31, 2010, we are obligated to pay $24,308 to our bank for the outstanding amount on the line of credit. On December 31, 2009 the outstanding amounts were $125,495 and $1,300 on the margin loan and line of credit, respectively.
18% Debentures
In August 2010, the Company issued $600,000 in principal amount of debentures due on the earlier of (i) July 31, 2011 and (ii) the closing of a $2,000,000 financing. As additional consideration for the purchase of the debentures, the Company also issued to the investors warrants to purchase up to 300,000 shares of common stock at a purchase price of $1.00 per share. The warrants expire upon the earlier of (i) two years after a registration statement registering the resale of the shares underlying the warrants is declared effective by the SEC and (ii) July 31, 2014. The Company granted the investors piggyback registration rights for the shares of common stock underlying the warrants. In November 2010, holders of a principal amount of $500,000 of these debentures exchanged such debentures for 500,000 shares of common stock and the remaining principal amount of $100,000 was paid in full; all accrued interest was also paid.
Majority Shareholder Notes
At the Closing of the Reorganization, the Company also issued a promissory note in favor of the Majority Shareholder in the original principal amount of $884,000, which accrues interest at the rate of 4% per annum and matures upon the earlier of (i) May 31, 2013 or (ii) the date on which the Company closes any equity financing in which the Company receives gross proceeds of at least $10,000,000. Also in connection with the Reorganization, an additional note for $165,000 which accrues interest at the rate of 4% shall be due and payable on demand to the Majority Shareholder at any time subsequent to the repayment in full of all outstanding indebtedness of the Credit Facility. The note and payable were dividends to the Majority Shareholder.
Capital Issuance
In July 2010, the Company agreed to issue 543,205 shares of Company common stock to Lighthouse for financial communication services which shares were issued in August 2010.
In August 2010, concurrent with the Closing of the Reorganization, the Company issued 50,000 shares of Company common stock to Brian Rodriguez pursuant to his director’s agreement.
In August 2010, the Company issued 3,000,000 shares of Company common stock to JTF in consideration for entering into an investment banking agreement. JTF will be the placement agent for a series of private offerings for up to $14,500,000 on a best efforts basis. The fee paid is reflected as a reduction of additional paid in capital as a deferred offering cost, which will offset the gross proceeds received from equity offerings. The investment banking agreement also provides for the placement of debt instruments. As debt offerings are closed, the pro rata portion of the pre-paid offering costs associated with the debt will be recorded to a deferred finance charge. As amended the agreement states that in the event JTF places equity or equity equivalent offerings, it will receive a cash placement agent fee of 10% of the gross proceeds of any offerings and cash expense reimbursement of 3% of the gross proceeds of any offerings, except that the fees and expense reimbursements are 8% and $75,000 respectively, for the first $2,000,000 of proceeds. At the closing of each equity offering, the firm will receive warrants to purchase one share of common stock for each ten shares sold with an exercise price of 105% of the offering price of the stock. The investment banking firm will forfeit 2,000,000 of the 3,000,000 shares received at the signing of the original agreement if, within 12 months after a registration statement has been filed and declared effective, $10,000,000 has not been raised pursuant to the agreement; and Radiant will pay a consulting fee of $8,000 in cash per month for one year after the first closing of at least the Minimum amount under the private offering. In the event that JTF places debt financing, they will receive a cash placement fee as follows: 5% of the first $10 million, 4% of the next $10 million, 3% of the next $10 million, 2% of the next $10 million, and 1% of any amounts raised over $40 million. If Radiant enters into additional financing with MBL, JTF will receive 2% of the cash proceeds.
Radiant issued to accredited investors (i) on November 12, 2010, 1,065,000 shares of our common stock for proceeds of $1,065,000 (including a principal amount of $500,000 from the 18% debentures that was converted into 500,000 shares of our common stock), less an 8% sales commission of $85,200 and related expenses of approximately $31,000 and (ii) on November 15, 2010, 150,000 shares of our common stock for gross proceeds of $150,000 less an 8% sales commission of $12,000. In addition, the Company is required to file a registration statement with the Securities and Exchange Commission (“SEC”) within 30 days of the earlier of (i) raising a total of $12 million and (ii) March 31, 2011 and to use its best efforts to have the registration statement declared effective within 120 days from the filing of the registration statement. The penalty for noncompliance, per each 30 day period of delay, is 2% of the newly issued shares up to a cap of 6%. As additional compensation to the sales commission and expenses for placing the offering of a total of 1,215,000 common shares, John Thomas Financial received warrants to purchase 121,500 shares of our common stock for $1.05. The Company used a portion of the proceeds to repay $250,000 on the Credit Facility, and $130,000 to repay the accrued interest on all the debentures and the remaining principal amount of the un-converted 18% debentures.
In February 2011 the Company entered into a settlement agreement with Mr. Allen Hobbs, our former controller, in full settlement of his employment agreement. As part of this settlement agreement Mr. Hobbs received 12,967 shares of our common stock not previously earned.
Off-Balance Sheet Arrangements
None.
Critical Accounting Policies
Principles of Consolidation
We consolidate all investments in which we have exclusive control. In accordance with established practice in the oil and gas industry, our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of a limited liability company, AE in which we have an interest. We owned a 75% interest in AE through October 9, 2009 and 51% after that date.
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our estimates include oil and natural gas proved reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
Oil and Natural Gas Properties
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the SEC. Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization. We evaluate unevaluated properties for inclusion in the amortization base at least annually.
Capitalized costs included in the amortization base are depleted using the units of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
We include our pro rata share of assets and proved reserves associated with an investment that is accounted for on a proportional consolidation basis with assets and proved reserves that we directly own in the appropriate cost center. We calculate the depletion and net book value of the assets based on the cost center’s aggregated values. Accordingly, the ratio of production to reserves, depletion and impairment associated with a proportionally consolidated investment does not represent a pro rata share of the depletion, proved reserves, and impairment of the proportionally consolidated venture.
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Asset Retirement Obligation
We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.
Revenue Recognition
We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.
Recent Accounting Pronouncements
In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the un-weighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009.
In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and natural gas producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted ASU 2010-03 effective December 31, 2009.
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements).
The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on our operating results, financial position or cash flows.
In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. We adopted the provisions of ASU 2010-09 for the period ended March 31, 2010.
In December 2010, the FASB issued ASU No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (ASU 2010-28). This codification update modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts and requires reporting units with such carrying amounts to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. ASU 2010-28 is effective for fiscal years and interim periods beginning after December 15, 2010 and early adoption is not permitted. The Company will adopt the provisions of this update in its Quarterly Report on Form 10-Q for the three months ended March 31, 2011. The Company is currently evaluating the impact that this adoption will have on its operating results, financial position, cash flows or disclosures but does not expect a material impact if any, as a result of the adoption.
In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current ombination(s) occurred as of the beginning of the comparable prior annual period only. This update also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company will adopt the provisions of this update for any business combinations that occur after January 1, 2011.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK
Not Required
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item appears beginning on page following the signature page of this Report
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is collected and communicated to management to allow timely decisions regarding required disclosures. The Chief Executive Officer has concluded, based on his evaluation as of December 31, 2010 that, as a result of the following material weakness in internal control over financial reporting disclosure controls and procedures were ineffective in providing reasonable assurance that material information is made known to him by others within the Company:
We do not maintain sufficient staff to have a proper segregation of duties in certain areas of our financial reporting process. The areas where we have a lack of segregation of duties include cash receipts and disbursements, approval of journal vouchers, approval of purchases and approval of accounts payable invoices for payment. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the financial statements will not be prevented or detected on a timely basis.
Changes in internal control over financial reporting
There have not been any changes in our internal controls over financial reporting that occurred during 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B
ITEM 9B OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, OFFICERS AND CORPORATE GOVERNANCE
Radiant’s directors and executive officers are:
Name
Age
Position
John M. Jurasin
Director, Chief Executive Officer, Chief Financial Officer and Chairman of the Board
Robert M. Gray
Director
Timothy N. McCauley
Vice President - Engineering and Exploratory Drilling
George R. Jarkesy, Jr.
Director
Brian Rodriquez
Director and Treasurer
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. Gray has over 30 years of experience in the oil and gas business and has served as Land Manager for JOG since December 2007, and Director and Vice-President of Land of Radiant from August 2010 through April 2010 and continues to serve as Director. Prior to JOG, Mr. Gray served as Land Manager for Americo Energy Resources, LLC since March 2007. From 1998 until 2006, Mr. Gray was a consulting oil and gas Land Manager. Prior to that, Mr. Gray was a landman or consulting landman for a number of companies including Hunt Oil Company, Petro-Guard Production Company, LLC and Bank One Texas, N.A. Mr. Gray received his degree from the University of Texas. Mr. Gray is a member of the American Association of Professional Landmen, Houston Association of Professional Landmen, West Houston Association of Professional Landmen and Pioneer Oil Producers Society. In addition, Mr. Gray served as a West Houston Chapter Executive Board Member for the Coastal Conservation Association. He also served as the Assistant Secretary Treasurer for the Fort Bend County Municipal Utility District (Elected Public Official) from 1993 - 1998. Mr. Gray is currently a member of the board of the Texas Alpha Endowment Fund, Inc. As former Land Manager for JOG, Mr. Gray has gained a broad and unique understanding of our planned business, operations, and interests. Mr. Gray’s specific experience, qualifications, attributes and skills described above led the Board to conclude that Mr. Gray should serve as a member of the Board of Directors.
Mr. McCauley has served as Vice President - Engineering and Exploratory Drilling since April 2009, and of Radiant since August 2010. From 2008 to 2009, Mr. McCauley was the engineering manager for AGR Turn Key Drilling. From 2005 through 2008, Mr. McCauley was a drilling engineer and a drilling manager for Applied Drilling Technology. Mr. McCauley received his bachelor’s degree in petroleum engineering in 1996 from Texas A&M University. Mr. McCauley is a member of the Society of Petroleum Engineers, International Association of Drilling Contractors and Houston Sport and Social.
Mr. Jarkesy has served as a director of the Company since August 2010. Mr. Jarkesy also served as chairman of the board and chief executive officer from August 15 2006 through June 15 2007. Mr. Jarkesy has been engaged in the private equity and investment business for over five years, and currently serves as the managing member of John Thomas Capital Management Group, LLC, which has been the general partner for John Thomas Bridge & Opportunity Fund, L.P. since June 2007. Mr. Jarkesy previously served as the chief operating officer and president of SH Celera Capital Corporation, an internally managed fund from March 2007 until March 2008. Mr. Jarkesy has founded and built companies engaged in financial consulting, real estate investments, real estate
management, employee leasing, light steel manufacturing, livestock management, oil field services and biotechnology during the last ten years. Mr. Jarkesy has served as a director of America West Resources, Inc. since 2008. Mr. Jarkesy provides the Board with exceptional leadership and management knowledge, having gained extensive public company management experience during the course of his career. Mr. Jarkesy’s specific experience, qualifications, attributes and skills described above led the Board to conclude that Mr. Jarkesy should serve as a member of the Board of Directors.
Mr. Rodriguez has served as a director since 2006, an executive officer of Radiant from 2006 through August 2010, and as president of Marathon Advisors LLC, a professional services firm providing accounting and business development services to micro-cap and small-cap companies for over five years. Mr. Rodriguez has served as interim chief financial officer of America West Resources, Inc., a publicly-held domestic coal mining company, during 2008 and during the period October 2009 to the present. Since December 2007, Mr. Rodriguez has served on the board of directors of America West Resources. From March 2006 through May 2007, Mr. Rodriguez served as chief financial officer of SH Celera Capital Corporation, an internally managed fund. He served as an accounting and finance consultant for Jefferson Wells from October 2004 to the present. From March 2002 to October 2005, Mr. Rodriguez served as controller and then director of finance for JP Mobile, Inc., a privately held wireless software company based in Dallas. Mr. Rodriguez has been a Certified Public Accountant in the State of Texas since 1995. . Mr. Rodriguez’s extensive financial background and exceptional leadership experience provide the Board with financial accounting and management expertise and perspectives. Mr. Rodriguez’s experience as a CFO of publically traded companies allows him to offer important insights into the role of finance in our business strategy. Mr. Rodriguez’s specific experience, qualifications, attributes and skills described above led the Board to conclude that Mr. Rodriguez should serve as a member of the Board of Directors.
Board Composition; Independence of Directors & Board Committees; Code of Ethics
The Company’s board of directors consists of four members, and Mr. Jurasin has a right to nominate and appoint an additional director, provided that a majority of the existing board members approve. There are no family relationships between any of the Company’s officers and directors.
The Company does not have any “independent directors” as that term is defined under independence standards used by any national securities exchange or an inter-dealer quotation system. The board of directors has not established any committees and, accordingly, the board of directors serves as the audit, compensation, and nomination committee.
Our Company has adopted a Code of Ethics governing the conduct of our executive officers.
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.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
Name and Principal Position
Year
Salary
($)
Bonus
($)
Stock
Awards
($)
Option
Awards
($)
Other
Compensation
($)
Total
($)
John M. Jurasin(1)
$207,206(2)
$450,677(3)
$1,064,784(4)
$1,722,667
$234,000
$234,000
$461,875
$461,875
Brian Rodriquez(5)
$50,000(6)
$ 50,000
$22,500(7)
$ 22,500
$114,750(8)
$114,750
Robert M. Gray(9)
$101,359(10)
$5,000
$82,500(11)
$19,294(12)
$208,153
$151,225
$151,225
$142,586
$142,586
Allen W. Hobbs (13)
$88,023
$2,083(14)
$6,248(15)
$ 96,354
$104,400
$104,400
$68,200
$ 68,200
Timothy N. McCauley(16)
$82,237(17)
$5,000
$235,473(18)
$41,281(19)
$363,991
Mark Witt(20)
Jay King(210
$163,333
$163,333
$89,015
$ 89,015
(1) John M. Jurasin served as JOG’s chief executive officer and director in 2008 through August 2010 and Radiant’s chief executive officer and director beginning August 2010.
(2) Includes $25,000 of wages on which the Company deferred payment until 2011.
(3) Mr. Jurasin was awarded 450,677 shares of common stock based on achievement of certain vesting requirements in the Exchange Agreement. An additional 450,677 shares of common stock are expected to be earned in 2011 based on the achieving of additional vesting requirements in the Exchange Agreement.
(4) Mr. Jurasin received notes totaling $1,049,000 as dividends at the closing of the Reorganization. The notes accrued $15,784 of interest in 2010.
(5) Mr. Rodriguez served as Radiant’s chief executive officer in 2008 through August 2010 and as secretary/treasurer and director beginning August 2010.
(6) Mr. Rodriquez received 50,000 shares of our common stock as consideration for serving as a director in 2010.
(7) In March 2009, Mr. Rodriguez received 22,500 shares of our common stock as consideration for serving as a director and executive officer.
(8) In February 2008, Brian Rodriguez received 22,500 shares of our common stock as consideration for serving as a director and executive officer.
(9) Robert M. Gray served as JOG’s land manager in 2008 through August 2010 and became vice president of land and a director of Radiant in August 2010.
(10) Includes $15,625 of wages on which the Company deferred payment until 2011.
(11) Mr. Gray was awarded 75,000 shares of common stock upon completion of the Reorganization and 7,500 shares of common stock achievement of certain vesting requirements in the Exchange Agreement. An additional 7,500 shares of common stock are expected to be earned in 2011 based on the achieving of additional vesting requirements in the Exchange Agreement.
(12) On August 5, 2010, Mr. Gray was granted options to buy 279,000 shares of Radiant common stock at $1.00 per share. The options vest equally over on each of the next three anniversaries of the grant date.
(13) Allen W. Hobbs served as JOG’s controller in 2008 through August 2010 and Radiant’s controller from August 2010 until his employment was terminated in November 2010.
(14) Mr. Hobbs was awarded 20,834 shares of common stock upon completion of the Reorganization and 2,083 shares of common stock achievement of certain vesting requirements in the Exchange Agreement.
(15) On August 5, 2010, Mr. Hobbs was granted options to buy 93,000 shares of Radiant common stock at $1.00 per share. His options were cancelled in his termination agreement.
(16) Timothy N. McCauley served as JOG’s vice president of operations from February 2010 until August 2010 and as Radiant’s vice president of operations since August 2010.
(17) Includes $18,125 of wages on which the Company deferred payment until 2011.
(18) Mr. McCauley was awarded 214,066 shares of common stock upon completion of the Reorganization and 21,407 shares of common stock achievement of certain vesting requirements in the Exchange Agreement. An additional 21,406 shares of common stock are expected to be earned in 2011 based on the achieving of additional vesting requirements in the Exchange Agreement.
(19) On August 5, 2010, Mr. McCauley was granted options to buy 597,243 shares of Radiant common stock at $1.00 per share. The options vest equally over on each of the next three anniversaries of the grant date.
(20) Mark Witt served as JOG’s chief financial officer in 2008 and 2009. In April 2010, we terminated a contract with our former CFO.
(21) Jay King served as JOG’s chief geologist in 2008 and 2009.
The value attributable to any stock or option awards described in the table above represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. See Note 8 - Common Stock and Common Stock Options of the Company’s Consolidated Financial Statements for the Year ended December 31, 2010.
Outstanding Equity Awards at Fiscal Year-End Table
Name
Number of securities underlying unexercised options
(#)
exercisable
Number of securities underlying unexercised options
(#)
un-exercisable (1)
Option exercise price
($)
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(2)
($)
John M. Jurasin
Robert M. Gray
279,000
$1.00
8/5/2020
279,000
$279,000
Timothy N. McCauley
597,243
$1.00
8/5/2020
597,243
$579,000
(1)
Options were granted on August 5, 2010 and vest equally on each of the first three anniversaries of the grant date.
(2)
Market value is based on the last material issuance price of our common stock.
Employment Agreements
The Company has entered into employment agreements with John M. Jurasin and Timothy N. McCauley
Pursuant to Mr. Jurasin’s employment agreement, he serves as the Company’s Chief Executive Officer and President and his annual salary is $200,000, which will be increased to $250,000 upon the Company receiving $10,000,000 in equity or debt financing and $300,000 upon the Company becoming cash flow positive.
Pursuant to Mr. McCauley’s employment agreement, he serves as the Company’s Vice President - Engineering and Exploration Drilling, his annual salary is $145,000, and he was issued options to purchase 298,622 shares of the Company’s common stock at an exercise price of $1.00 per share, which shall vest equally over the next three years.
Director Compensation
Our directors were not compensated for their services during 2010, other than as reflected in the “Summary Compensation Table” above.
ITEM 12.
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 December 8, 2010 (i) by each person who is known by us to beneficially own more than 5% of our common stock, (ii) by each of our named executive officers and directors, and (iii) by all of our executive officers and directors as a group. The number of shares beneficially owned by each director or executive officer is determined under rules of the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose. Under the SEC rules, beneficial ownership includes any shares as to which the individual has the sole or shared voting power or investment power. In addition, beneficial ownership includes any shares that the individual has the right to acquire within 60 days. Unless otherwise indicated, each person listed below has sole investment and voting power (or shares such powers with his or her spouse). In certain instances, the number of shares listed includes (in addition to shares owned directly), shares held by the spouse or children of the person, or by a trust or estate of which the person is a trustee or an executor or in which the person may have a beneficial interest. As of April 6,2010, there were 13,288,813 shares of common stock outstanding.
Name and Address of Owner
Number of
Shares Owned
Percentage
John Thomas Bridge & Opportunity Fund, L.P. (1)
2,236,393
17%
John Thomas Financial, Inc. (2)
3,000,000
23%
Named Executive Officers and Directors:
John M. Jurasin (3)
4,957,445
37%
Brian Rodriguez(4)
131,322
1%
George R. Jarkesy, Jr. (5)
2,277,939
17%
Robert M. Gray (6)
82,500
*
Timothy N. McCauley(7)
235,472
2%
Allen W. Hobbs
35,884
*
Jay King
--
--
Mark Witt
--
--
All Executive Officers and Directors as a Group (6 persons)
7,720,562
57%
* Less than one percent
(1)
The address for John Thomas Bridge & Opportunity Fund, L.P. (“Fund”) is 3 Riverway, Suite 1800, Houston, Texas 77056. The Fund is a limited partnership, and the John Thomas Capital Management Group, LLC is the general partner of the Fund (“GP”). George Jarkesy is the managing member of the GP. Mr. Jarkesy and the GP may be deemed to have beneficial ownership of the securities reported herein. Includes presently exercisable warrants to purchase 62,500 shares of common stock at an exercise price of $1.00 per share.
(2)
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. Of the amount shown in this table, 2,000,000 are subject to forfeiture. See Capital Issuance under Item 7.
(3)
The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042. Does not include 450,677 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements.
(4)
Does not include 50,000 shares issuable to Mr. Rodriguez in June 2011 pursuant to his director’s agreement.
(5)
Consists of (i) 42,546 shares owned of record by Mr. Jarkesy, (ii) 2,090,403 shares owned by the Fund, and (iii) presently exercisable warrants to purchase 62,500 shares of common stock at an exercise price of $1.00 per share owned by John Thomas Bridge & Opportunity Fund II, L.P. of which Mr. Jarkesy is the managing member of the general partner and Mr. Jarkesy and the general partner may be deemed to have beneficial ownership of the securities owned by this fund.
(6)
Does not include (i) 7,500 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements, and (ii) an option to purchase 139,500 shares of our common stock at an exercise price of $1.00 per shares and which vest equally over the next three years.
(7)
The address is 9700 Richmond Ave., Suite 124, Houston, Texas 77042. Does not include (i) 21,406 shares to be issued pursuant to the Reorganization upon satisfaction of certain vesting requirements, and (ii) an option to purchase 298,622 shares of our common stock at an exercise price of $1.00 per share and which vest equally over the next three years.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Transactions with Related Persons
In December 2007, John Thomas Bridge and Opportunity Fund L.P. (an entity that Mr. Jarkesy is the managing member of its general partner) acquired an aggregate of 2,090,403 shares of Company common stock from Sand Hills General Partners, a Texas General Partnership and SHGP’s owner, Sand Hills Partners, LLC, a Delaware limited liability company in a private transaction. The acquisition of the shares by John Thomas Bridge & Opportunity Fund, L.P. resulted in a change of control of the Company. As of December 31, 2008, we had outstanding loans from George Jarkesy totaling $5,000, plus $1,745 in accrued interest, and $11,902 in expenses had been paid by Mr. Jarkesy on behalf of the Company, representing an advance. Mr. Jarkesy is the fund manager of the John Thomas Bridge & Opportunity Fund, the majority shareholder of the Company, and during the years ended 2008 and 2009, we borrowed an aggregate of $55,000 from John Thomas Bridge and Opportunity Fund, LP. The notes accrued interest at 8% per annum and matured on December 31, 2009. In April 2010, John Thomas Bridge and Opportunity Fund and Mr. Jarkesy converted all of their outstanding notes (approximately $108,504) and contributed $8,000 for consideration of 250,000 shares of our common stock. In connection with the Reorganization, John Thomas Bridge and Opportunity Fund, LP personally indemnified JOG and John Jurasin for any misrepresentations by Radiant up to $500,000. In connection with the indemnification agreement, the Company agreed to pay John Thomas Bridge and Opportunity Fund, LP $250,000 upon the closing a minimum of $10,000,000 in debt or equity financing. The John Thomas Bridge & Opportunity Fund II, L.P. (an entity that Mr. Jarkesy is the managing member of its general partner) purchased (i) $125,000 of debentures in August 2010, issued as part of the $600,000 of bridge financing that matures on the earlier of July 31, 2011 and the closing of $2,000,000 financing (to be partially prepaid with 30% of the gross proceeds from subsequent financings equaling and exceeding $500,000), and (ii) four-year warrants to purchase 62,500 shares of common stock (with piggy back registration rights for the underlying shares of common stock at a purchase price of $1.00 per share). In November 2010, the debentures were converted into 125,000 shares of common stock. Mr. Jarkesy acquired 42,546 shares during 2007 for nominal consideration. In 2010 we borrowed $7,000 with an interest rate of 8% and an additional $50,000 for which the terms have not yet been negotiated. Mr. Jarkesy was the chairman of the board and chief executive officer of the Company from August 15, 2006 through June 15, 2007 and was appointed as a director on August 5, 2010.
In connection with the Reorganization, the Company issued the John M Jurasin 4,957,445 shares of our common stock (plus an additional 450,677 shares of common stock subject to the satisfaction of vesting requirements) for his shares of the issued and outstanding common stock of JOG (originally issued for nominal consideration). In addition, the Company issued the Mr. Jurasin a note in the principal amount of $884,000, which accrues interest at 4% per annum and is payable in three years. The note shall be prepaid upon the Company raising at least $10,000,000. Also in connection with the Reorganization, we issued an additional $165,000, note to Mr. Jurasin which accrues interest at 4% per annum and is payable upon demand any time after the Credit Facility has been repaid.. The notes were treated as a dividend to the Majority Shareholder. Prior to the Reorganization, JOG transferred the following interests for nominal consideration to entities owned and controlled by the Majority Shareholder (collectively, the “Transferred Interests”): (i) Ensminger- overriding royalty interest equal to approximately 2.0% in and to certain leases contained within the geographic confines of the Ensminger #1 Planulina D Reservoir A Unit located in St. Mary Parish, Louisiana -as of the date hereof, there is no production attributable to this interest; (ii) Aquamarine- overriding royalty interest of 0.85% in and to oil & gas lease, serial number OCS-G 23135, dated effective October 1, 2001, by and between the United States of America, as lessor, to Paragon Petroleum, Inc. and DDD Energy, Inc. as lessees, covering all of Block 758, Mustang Island Area, OCS Leasing Map, Texas Map No. 3, describing 5,760 acres, more or less - this interest is currently producing after having been shut-in from October 2008 through December 2008 and from March 2009 through July 2009; (iii) Coral/Ruby/Diamond- an approximately 1.35% before payout and 0.75% after payout overriding royalty interest covering certain lands located in Louisiana State Waters in St. Mary Parish, Louisiana- there is no production attributable to this interest; (iv) any and all overriding royalties to which JOG may be entitled under that certain area of mutual interest agreement, Baldwin Prospects, St. Mary Parish, Louisiana, dated January 22, 2010, by and between JOG and J&S Oil & Gas, LLC, and covering certain lands located in St. Mary Parish, Louisiana- there is no production attributable to this interest; and (v) all working interest, overriding royalty interest, or any other interest in the following wells operated by Zenergy, Inc. in the Charenton Field, St. Mary Parish, Louisiana: 3 TEC #1-41, 3 TEC #2, 3 TEC #4, 3 TEC #5, 3 TEC #5 SWD, 3 TEC #8, 3 TEC #7, 3 TEC #9, 3 TEC #11 and 3 TEC #11-A - these interests do not exceed more than a 1.5% working interest and a net revenue interest (yielding in 2009 gross working interests of $23,308 and net revenue interest of $1,266). For the quarter ended March 31, 2010, JOG did not earn any net profits from the Transferred Interests. During the year ended December 31, 2009, JOG earned approximately $26,000 net profits from the Transferred Interests. During the year ended December 31, 2008, JOG earned approximately $69,000 net profits from the Transferred Interests. At December 31, 2010 the Company also owed Mr. Jurasin $25,000 in deferred salary and $29,742 from shareholder advances.
In connection with the Reorganization, we issued Mr. Gray 75,000 shares of our common stock (plus an additional 15,000 shares of common stock subject to the satisfaction of vesting requirements), Mr. McCauley 214,066 shares of our shares of common stock (plus an additional 42,813 shares of common stock subject to the satisfaction of vesting requirements. At December 31, 2010 Mr. Gray and Mr. McCauley were owed $15,625and $18,044 respectively, in salary deferred by the Company. At December 31, 2010 Mr. Gray was also owed $50,606 for services performed for Radiant prior to becoming an employee.
In connection with the Reorganization, the Company entered into a director’s agreement with Mr. Rodriguez, in which the Company agreed to pay Mr. Rodriguez $3,000 per month beginning in June 2010, and issue to Mr. Rodriguez 100,000 shares of Company common stock, of which 50,000 shares were issued upon the closing of the Reorganization and the remaining 50,000 shares will be issued in June 2011. Mr. Rodriguez personally indemnified JOG and John Jurasin for any misrepresentations by Radiant in the Reorganization up to $50,000. In connection with the indemnification agreement, the Company agreed to pay Mr. Rodriguez $25,000 prior to the payment of any cash bonus to any employee, officer or director. Mr. Rodriguez acquired an aggregate of 81,327 shares of common stock during 2008, 2009 and 2010 for nominal consideration. Mr Rodriquez was formerly the chief executive officer of the Company, and continues to serve as a director.
John Thomas Financial will provide investment banking services to the Company, and pursuant to an investment banking agreement, the Company will pay John Thomas Financial in connection with equity financings cash sales commissions of up to 10% of the gross proceeds, non-accountable expense allowances of up to 3% of the gross proceeds and five-year warrants to purchase one share of common stock for each ten shares of common stock (including common stock equivalents) sold in the Offering at a purchase price of 105% of the offering price; and in connection with debt financings (excluding the first $600,000 has been raised to date), a cash fee equal to 5% of the first $10,000,000 of debt financing, 4% of the next $10,000,000 of debt financing, 3% of the next $10,000,000 of debt financing, 2% of the next $10,000,000 of debt financing, and 1% in excess of $40,000,000 of debt financing. In August 2010, the Company issued to John Thomas Financial 3,000,000 shares of common stock as additional consideration for entering into the investment banking agreement, and John Thomas Financial is entitled to receive $75,000 of expense reimbursement once $2,000,000 is raised in an offering. In November 2010, JTF served as a placement agent in connection with the sale of 1,215,000 shares of Company common stock for $1,215,000, received sales commission of $97,200 and expense reimbursement of $25,000, and a five-year warrant to purchase 121,500 shares of Company common stock at an exercise price of $1.05 per share, which warrant contains registration rights regarding the resale of the underlying common stock. We have been advised by John Thomas Bridge & Opportunity Fund L.P. that John Thomas Bridge & Opportunity Fund L.P. and John Thomas Financial are not affiliates of one another. We have further been advised by John Thomas Bridge & Opportunity Fund as follows, with respect to the relationship between John Thomas Financial and John Thomas Bridge & Opportunity Fund:
(a) Neither John Thomas Financial nor any of its affiliates has any direct or indirect ownership or management interest in John Thomas Bridge & Opportunity Fund L.P. or John Thomas Bridge & Opportunity Fund II, L.P.;
(b) Neither John Thomas Bridge & Opportunity Fund L.P. nor any of its affiliates has any direct or indirect ownership or management interest in John Thomas Financial;
(c) From time to time John Thomas Financial has served as placement agent for John Thomas Bridge & Opportunity Fund L.P. in connection with offers and sales of John Thomas Bridge & Opportunity Fund L.P. securities;
(d) Pursuant to a placement agent agreement, dated as of July 19, 2007, between John Thomas Financial and John Thomas Bridge & Opportunity Fund L.P., John Thomas Bridge & Opportunity Fund L.P. has been granted a trademark license to use the name “John Thomas” and variants thereof in connection with, among other things, the operation of John Thomas Bridge & Opportunity Fund L.P.; and
(e) John Thomas Financial from time to time receives compensation with respect to companies it introduces to John Thomas Bridge & Opportunity Fund L.P. and which obtain loans from John Thomas Bridge & Opportunity Fund L.P. John Thomas Financial did not introduce John Thomas Bridge & Opportunity Fund L.P to the Company, and received no compensation in connection with the Reorganization.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Professional services were rendered by MaloneBailey, LLP for the fiscal years ended December 31, 2010 and 2009. The aggregate fees for each of those years were as follows:
Audit fees for the fiscal years ended December 31, 2010, and 2009 represent the aggregate fees billed for professional services rendered for the audit of our annual financial statements and review of financial statements included in our quarterly reports on Form 10-Q or services that are normally provided in connection with statutory and regulatory filings or engagements for those fiscal years.
Audit Committee Pre-Approval Policies and Procedures
The Board of Directors serves as the Audit Committee of the Company. The Board of Directors on an annual basis reviews audit and non-audit services performed by the independent auditor. All audit and non-audit services are pre-approved by the Board of Directors, which considers, among other things, the possible effect of the performance of such services on the auditors’ independence. The Board of Directors has considered the role MaloneBailey in providing services to us for the fiscal year ended December 31, 2009 and has concluded that such services are compatible with MaloneBailey’s independence as the Company’s auditors.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Each exhibit identified below is filed as part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with “” constitute a management contract or compensatory plan or arrangement.
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
Articles of Incorporation of Radiant Oil & Gas, Inc. Previously filed on Form 8-K dated August 16, 2010.
3.2
Amended and Restated Bylaws of Radiant Oil & Gas, Inc. Previously filed on Form 8-K dated August 16, 2010.
4.1
Form of specimen certificate representing shares of Radiant Oil & Gas, Inc. common stock. Previously filed on Form 8-K dated August 16, 2010.
4.2
Form of debenture issued in $600,000 bridge financing. Previously filed on Form 8-K dated August 16, 2010.
4.3
Form of warrant issued in $600,000 bridge financing. Previously filed on Form 8-K dated August 16, 2010.
4.4*
10% Convertible Promissory Note issued February 1, 2011 to Fermo Jaeckel.
10.1
Radiant Oil & Gas, Inc. 2010 Stock Option Plan. Previously filed on Form 8-K dated August 16, 2010.
10.2
Amended and Restated Secured Credit Agreement, dated April 30, 2008, by and between Amber Energy, LLC, and Macquarie Bank Limited. Previously filed on Form 8-K dated August 16, 2010.
10.3
First Amendment to Amended and Restated Secured Credit Agreement, dated August 5, 2010, by and between Amber Energy, LLC and Macquarie Bank Limited. Previously filed on Form 8-K dated August 16, 2010.
10.4
Amended and Restated Senior First Lien Secured Credit Agreement, dated September 14, 2006, by and between Rampant Lion Energy, LLC and Macquarie Bank Limited. Previously filed on Form 8-K dated August 16, 2010.
10.5
Second Amendment to Amended and Restated Senior First Lien Secured Credit Agreement, dated August 5, 2010, by and between Rampant Lion Energy, LLC and Macquarie Bank Limited. Previously filed on Form 8-K dated August 16, 2010.
10.6
Limited guaranty of Radiant for benefit of Macquarie Bank Limited. Previously filed on Form 8-K dated August 16, 2010.
10.7
Omnibus Amber Amendment. Previously filed on Form 8-K dated August 16, 2010.
10.8
Omnibus Rampant Lion Amendment. Previously filed on Form 8-K dated August 16, 2010.
10.9
Directors Agreement, dated August 5, 2010, by and between Radiant Oil & Gas, Inc. and Brian Rodriguez. Previously filed on Form 8-K dated August 16, 2010.
10.10
John Jurasin note dated August 5, 2010. Previously filed on Form 8-K dated August 16, 2010.
10.11
Form of Stock Option Agreement for Incentive Stock Options granted under the 2010 Stock Option Plan to various employees. Previously filed on Form 8-K dated August 16, 2010.
10.12
Employment Agreement, dated as of August 5, 2010, by and between Radiant Oil & Gas and Robert M. Gray. Previously filed on Form 8-K dated August 16, 2010. Previously filed on Form 8-K dated August 16, 2010.
10.13
Employment Agreement, dated as of August 5, 2010, by and between Radiant Oil & Gas and Timothy N. McCauley. Previously filed on Form 8-K dated August 16, 2010.
10.14
Employment Agreement, dated as of August 5, 2010, by and between Radiant Oil & Gas and John M. Jurasin. Previously filed as Exhibit 10.15 on Form 8-K dated August 16, 2010.
10.15
Indemnification Agreement of John Thomas Bridge & Opportunity Fund, LP. Previously filed as Exhibit 10.17 on Form 8-K dated August 16, 2010.
10.16
Indemnification Agreement of Brian Rodriguez. Previously filed as Exhibit 10.18 on Form 8-K dated August 16, 2010.
10.17
John Jurasin Note dated October 12, 2010. Previously filed as Exhibit 10.19 on Form 8-K dated November 8, 2010.
10.18
Third Amendment to Credit Agreement dated October, 19, 2010 by and between Rampant Lion Energy, LLC and Macquarie Bank Limited. Previously filed as Exhibit 10.20 on Form 8-K dated November 8, 2010.
10.19
Consulting Agreement dated July 29, 2010 by and between Radiant Oil & Gas, Inc. and Lighthouse Capital, Ltd. Previously filed as Exhibit 10.21 on Form 8-K dated November 8, 2010.
10.20
First Amendment to Consulting Agreement dated August 12, 2010 by and between Radiant Oil & Gas, Inc. and Lighthouse Capital, Ltd. Previously filed as Exhibit 10.22 on Form 8-K dated November 8, 2010.
10.21
Investment Banking Agreement by and between Radiant Oil & Gas, Inc. and John Thomas Financial, Inc. Previously filed as Exhibit 10.23 on Form 8-K dated November 8, 2010.
10.22
First Amendment to Investment Banking Agreement by and between Radiant Oil & Gas, Inc. and John Thomas Financial. Previously filed as Exhibit 10.24 on Form 8-K dated November 8, 2010.
10.23
First Amendment to Amended and Restated Senior First Lien Secured Credit Agreement, dated August 5, 2010, by and between Rampant Lion Energy, LLC and Macquarie Bank Limited. Previously filed as Exhibit 10.25 on Form 8-K dated January 5, 2011.
10.24
Joint Operating Agreement dated May 24, 2006 by and between Medco Energi US LLC and Rampant Lion Energy, LLC with amendments dated October 31, 2006 and March 29, 2007. Previously filed as Exhibit 10.26 on Form 8-K dated January 5, 2011.
10.25
Mustang Island Block 758 Participation Agreement by and between Rampant Lion Energy LLC and Medco Energy US LLC dated May 24, 2006. Previously filed as Exhibit 10.27 on Form 8-K dated January 5, 2011.
10.26*
Fourth Amendment to Credit Agreement dated April 7, 2011 by and between Rampant Lion Energy, LLC and Macquarie Bank Limited.
10.27*
Second Amendment to Amended and Restated Secured Credit Agreement, dated April 7, 2011 by and between Amber Energy, LLC and Macquarie Bank Limited.
22.1*
List of Subsidiaries of Radiant Oil & Gas, Inc. Previously filed on Form 8-K dated August 16, 2010.
23.1*
Consent of Ralph E. Davis Associates, Inc.
23.2*
Consent of Mire & Associates, Inc.
31.1*
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*
Reserve report prepared dated April 1, 2011 by Ralph E. Davis Associates, Inc.
99.2*
Reserve report prepared by dated February 24, 2011 Mire & Associates, Inc.
99.3*
Reserve report prepared by dated February 22, 2011 Mire & Associates, Inc.
*
Filed herewith.

Management contract or compensatory plan arrangement.
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: April 15, 2011
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, Chief Financial Officer, Principal Accounting Officer and Chairman of the Board
April 15, 2011
John M. Jurasin
/s/ Robert M. Gray
Director
April 15, 2011
Robert M. Gray
/s/ Brian E. Rodriquez
Director
April ,15 2011
Brian E. Rodriguez
/s/ George R. Jarkesy
Director
April 15, 2011
George R. Jarkesy
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, December 31, 2010 and December 31, 2009
Consolidated Statements of Operation, Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss), Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows, Years Ended December 31, 2010, 2009 and 2008
Notes to Financial Statements
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. as of December 31, 2010 and 2009 and the related consolidated statements of operations and comprehensive losses, changes in stockholder’s deficit, and cash flows for the years then ended. 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. at December 31, 2010 and 2009 and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2, the Company has recurring losses from operations and has a working capital deficit. These factors raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ MaloneBailey LLP
www.malone-bailey.com
Houston, Texas
April 15, 2010
F- 2
F- 3
F- 4
F- 1
RADIANT OIL & GAS, INC.
F- 1
RADIANT OIL & GAS, INC.
Note 1 - Description of Business and Summary of Significant Accounting Policies
Description of business and basis of presentation
Radiant Oil and Gas, Inc. (“Radiant") 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. Jurasin is a Louisiana Corporation chartered in 1994. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
In August 2010, Jurasin Oil and Gas, Inc (“JOG”) completed a reverse acquisition transaction through an exchange agreement with us whereby we acquired 100% of JOG’s issued and outstanding capital stock in exchange for 5,000,002 shares of our common stock. The agreement provides for the issuance of up to an additional 1,000,000 shares of our common stock upon the satisfaction of certain performance conditions. Under the agreement for the performance of each of the following conditions (up to a maximum of four), the former JOG shareholders will receive 250,000 additional shares of common stock. As of December 31, 2010, two of the performance conditions have been met resulting in the issuance of 500,000 of these common shares. The performance conditions that were met were the nomination of the southern acreage for lease and the re-acquiring of the seismic permit on 1,000 net acres for Amber. The remaining performance conditions of permit on a well on the Coral; the re-acquiring State seismic permit covering open acreage in Bayou Teche, Grand Lake and Attakapas Wildlife Management Areas; re-acquire seismic permit on additional 1,000 acres on Amber lease; extend Apache Seismic Permit and Sub-Lease from September 2010; and execute seismic services contract for shooting of 3-D survey.
As a result of the reverse acquisition, JOG became our wholly-owned subsidiary and 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.
Consequently, the assets and liabilities and the historical operations of JOG are reflected in the consolidated financial statements for periods prior to the Reorganization Agreement. Our assets and liabilities will be recorded at the historical cost basis. After the completion of the exchange agreement (“Reorganization”), our consolidated financial statements now include the assets and liabilities of both Radiant and JOG, JOG’s historical operations up through the closing date of the Reorganization and the combined operations of Radiant and JOG from the closing date of the Reorganization.
Effective September 9, 2010 Radiant effected a one for two reverse stock split. The accompanying financial statements have been retroactively restated to reflect the stock split.
Principles of Consolidation
We consolidate all investments in which we have exclusive control. The accompanying consolidated financial statements include the accounts of Radiant Oil and Gas, Inc., our wholly owned subsidiaries, JOG, Rampant Lion Energy, LLC (“RLE”), and Jurasin Oil and Gas Operating Company (“JOGOp”).
In accordance with established practice in the oil and gas industry, our financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of a limited liability company, Amber Energy, LLC in which we have an interest. We owned a 75% interest in Amber through October 9, 2009 and 51% after that date. Our net interest is referred to as “AE.”
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these
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estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our estimates include oil and natural gas proved reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
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.
Concentrations
Our operations are concentrated in Louisiana and Texas. We are heavily dependent on the sale of natural gas, which accounted for 99% and 73% for each of the years ended December 31, 2010 and 2009, respectively. If the oil and natural gas exploration and production industry in general and the natural gas industry in particular were adversely affected, we would experience adverse effects.
In 2010, and 2009 we sold approximately 98% and 75% of our production, respectively, to Medco Energi US, LLC, the operator of our one currently producing property.
We are the non-operator on our proved properties. As such, we have a concentration risk associated with the business success of our operators. If our operators are not successful in operating our properties, we could experience material adverse effects.
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. At December 31, 2010 and 2009 we had $0 held in banks in excess of federally insured limits. We believe that credit risk associated with cash is remote.
We have approximately 99% of our debt placed with one entity, as described more fully in Note 5 - Notes Payable.
Investments
We classify our marketable securities as trading, available-for-sale, or held-to-maturity. The appropriate classification of its marketable securities is determined at the time of purchase and reevaluated at each balance sheet date. As of December 31, 2010 and 2009, respectively, we owned no investments that were considered to be held-to-maturity or trading. Available for sale securities are marked to market based on the fair values of the securities, with unrealized gains or losses, net of tax, reported as a component of accumulated other comprehensive income (loss). We owned securities with a fair value of $0 and $246,203 at December 31, 2010 and 2009, respectively, which were classified as available for sale. Fair value is determined using quoted prices in active markets for the identical asset; total fair value is the market price per share multiplied by the number of shares owned without consideration of transaction costs (level 1 input). When available-for-sale securities are sold, unrealized gain or loss included in accumulated other comprehensive income is reclassified into earnings and included in the realized gain or loss on sale of the security.
Accounts receivable and allowance for doubtful accounts
Accounts receivable are reflected at net realizable value. We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust the allowance as necessary using the specific identification method. There is no significant allowance for doubtful accounts at December 31, 2010 or 2009.
Deferred Finance Charges
Deferred finance charges consist of legal fees incurred in connection with the issuance of our notes payable were capitalized and
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are separately shown in the consolidated balance sheets. The charges are being amortized on a straight-line basis over three years, the term of the 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 - 5 years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.
Impairment of Long-Lived Assets
We periodically review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize 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. We recorded no impairment during the years ended December 31, 2010 and 2009.
Oil and Natural Gas Properties
We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the 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 cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization. We evaluate unevaluated properties for inclusion in the amortization base at least annually.
Capitalized costs included in the amortization base are depleted using the units of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
We include our pro rata share of assets and proved reserves associated with an investment that is accounted for on a proportional consolidation basis with assets and proved reserves that we directly own in the appropriate cost center. We calculate the depletion and net book value of the assets based on the cost center’s aggregated values. Accordingly, the ratio of production to reserves, depletion and impairment associated with a proportionally consolidated investment does not represent a pro rata share of the depletion, proved reserves, and impairment of the proportionally consolidated venture.
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
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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.
Asset Retirement Obligation
We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.
Revenue Recognition
We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.
Income Taxes
We account 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. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2006 remain open to examination by U.S. federal and state tax jurisdictions.
Fair Value
Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
The three-level hierarchy is as follows:
·
Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
·
Level 2 inputs consist of quoted prices for similar instruments.
·
Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
As of December 31, 2010 and December 31, 2009, we had investments of $0 and $246,203, respectively, measured at fair value using level 1 inputs. At December 31, 2010 we had derivatives of $231,526 valued using level 3 inputs. The carrying amounts reported in the balance sheet for cash and accounts payable and accrued expenses approximate their fair market value based on
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the short-term maturity of these instruments.
Recent Accounting Pronouncements
In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the un-weighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009.
In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted ASU 2010-03 effective December 31, 2009.
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements).
The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on our operating results, financial position or cash flows.
In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. We adopted the provisions of ASU 2010-09 for the period ended March 31, 2010.
In December 2010, the FASB issued ASU No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (ASU 2010-28). This codification update modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts and requires reporting units with such carrying amounts to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. ASU 2010-28 is effective for fiscal years and interim periods beginning after December 15, 2010 and early adoption is not permitted. The Company will adopt the provisions of this update in its Quarterly Report on Form 10-Q for the three months ended March 31, 2011. The Company is currently evaluating the impact that this adoption will have on its operating results, financial position, cash flows or disclosures but does not expect a material impact if any, as a result of the adoption.
In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current ombination(s) occurred as of the beginning of the comparable prior annual period only. This update also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the
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reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company will adopt the provisions of this update for any business combinations that occur after January 1, 2011.
Note 2 - Going Concern
As reflected in the accompanying financial statements, we had a working capital deficit of $5,774,030 and an accumulated deficit of $ 5,974,616 as of December 31, 2010, which raise substantial doubt about our ability to continue as a going concern. Management plans to raise funds through the issuance of debt, the sale of common stock, merger with another company or the sale of partial interests in our projects to other industry participants.
Our ability to continue as a going concern is dependent on our ability to raise capital through the issuance of debt, the sale of common stock, the consummation of a merger or the sale of partial interests in our projects to other industry participants. If we do not raise capital sufficient to fund our business plan, Radiant may not survive. The financial statements do not include any adjustments that might be necessary if we were unable to continue as a going concern.
Note 3 - Investments
Our investments consist of holdings in mutual funds. The mutual funds are invested primarily in equity securities. The cost, unrealized gains and losses, and fair value of our available-for-sale securities at December 31, 2010 and 2009 were as follows:
Cost
$
-
$
217,439
Unrealized gains (losses)
-
28,764
Fair Value
$
-
$
246,203
Balances related to our results of operations for the years ended December 31, 2010 and 200 follow:
Proceeds from sales of investments
$
241,341
$
25,006
Gross and net realized (losses)
$
21,542
$
(21,926)
Margin Account
We borrowed $44,016 and repaid $169,510 on margin from our broker-dealer during 2010. We borrowed $125,495 from our broker-dealer.in 2009. We were indebted to the broker-dealer in the amount of $0 and $125,495 as of December 31, 2010 and 2009, respectively. The margin loan was secured by the securities and cash held within the account and interest was charged at market rates.
Interest expense paid to the broker-dealer totaled $5,460 and $666 in 2010and 2009, respectively.
Average interest rates for 2010 and 2009 were 6.25 percent and 8 percent, respectively.
Note 4 - Oil and Gas Properties
Oil and natural gas properties as of December 31, 2010 and 2009, consisted of the following:
Project descriptions
Aquamarine
We own interests in a lease located in the federal waters offshore Texas, which is referred to as the Aquamarine Project. There is currently one producing gas well in this lease area. There are proved producing and proved developed not producing reserves associated with this lease area.
Amber
Our Amber project consists of multiple leases, permits and permits with options to lease onshore Louisiana, USA. There are no proved reserves associated with the Amber prospect.
Ensminger
Our Ensminger Project is located onshore in Louisiana, USA. Currently, there are no producing wells in this area. Our reserves associated with this area are proved undeveloped.
In February 2010, we sublet a portion of our interest in Ensminger, thus reducing our before payout working interest and net revenue interest to 6.375% and 4.62188%, respectively. We received net cash proceeds of $149,175. In addition, the sub-letting parties assumed responsibility for their pro rata share of the asset retirement obligation on the property, such share being $48,611 at the time of the transfer. At this time, Energy XXI (Bermuda) Limited became the operator of the wells in this project. The proceeds and the assumption of the asset retirement obligation were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
In March 2010, we completed the transfer of a 0.5% overriding royalty interest to an unaffiliated third party and received total proceeds of $250,000. The funds had been paid to Amber in December 2009 and are reflected as of that date as a deposit of $127,500, our pro rata share of the liability.
In April 2010, the Ensminger #2 was drilled and has been temporarily abandoned pending the results of a sidetrack that the Company expects to drill in the Exxon Ensminger #1.
Coral/Ruby/Diamond
We own a contractual interest in certain oil and gas leases located in the state waters of Louisiana. Under an agreement with the leasehold owners and another party, we will receive 30% of any promote that is acquired when the deal is sold. A 35% interest has been sold to a third party the agreement for which provides for a 25% working interest after payout.
Related Party Transfer
Effective March 2010, we assigned certain legacy overriding royalty interests 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, our CEO. We retained our working interests in these projects. Additionally, we assigned our working interest in a project, Charenton, to the related party entity. We did not receive any proceeds for the conveyances and except for the Ensminger Project, the interests assigned had a historical cost basis of $0. The Ensminger Project had allocable costs of $23,446. The conveyance was accounted for as a transaction between entities under common control and the ORRI was recorded as a distribution to shareholder and transferred out of property at historical cost.
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Our interests in projects for which there were proved reserves, as of December 31, 2010, were as follows:
Project name
Before payout working interest
Net revenue interest
Aquamarine
11.25%
9.5125%
Ensminger
6.375%
4.62188%
Coral
65.5%
48.7744%
Adjustment of interest in investee
The company agreement governing our subsidiary, Amber and Amber’s secured credit facility provided that if the outstanding amount on the facility as of October 9, 2009 exceeded $2,000,000 24% of the membership of Amber would be transferred to an affiliate of our lender. The provisions of the note are more fully discussed in Note 5 - Notes Payable. On October 9, 2009, the outstanding balance exceeded $2,000,000. Thus, our proportional interest in Amber reduced from 75% to 51%. Accordingly, our pro rata share of our ownership in Amber’s oil and gas properties and reserves were reduced by 24%. This resulted in a reduction of our cost basis in the Amber and Ensminger projects of approximately $650,000.
Costs incurred for oil and gas properties
Significant investments in oil and gas properties during the year ended December 31, 2010 include:
•
Acquisition costs of $33,976
•
Exploration, which consisted of geological costs of $121,657: and
•
Development costs pertaining to our Aquamarine project of $9,292.
Significant investments in oil and gas properties during the year ended December 31, 2009 include:
•
Acquisition costs of $148,791
•
Exploration which consisted of geological costs of $52,846
•
Development costs pertaining to our Ensminger and Aquamarine projects of $39,219;
Cost recovery
During the year ended December 31, 2010, we transferred our overriding royalty interest in the Ensminger project to a third party and reduced our cost recovery by $250,000. We also sold a portion of our working interest in Ensminger which reduced our cost recovery by $149,175 from the net proceeds and an additional $48,611 from the buyer assuming their portion of the asset retirement obligation. Cost recovery was also reduced by $23,446 for the cost basis in the overriding royalty interest in Ensminger that was assigned to a related party entity owned by John M. Jurasin. The proceeds received in these transactions were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
Impairment
We account for our 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 cost center.
The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
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Beginning December 31, 2009, full cost companies use the un-weighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date. Prior to December 31, 2009, companies used the price in effect at the end of each accounting period and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the end of the accounting quarter.
We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess 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.
At December 31, 2010 and 2009, the ceiling test value of our reserves was calculated based on the first day average of the 12-months ended December 31, 2010 and 2009 of the West Texas Intermediate (WTI) posted price of $79.43 and $61.18 per barrel respectively, and the first day average of the 12-months ended December 31, 2010 and 2009 of the Henry Hub price of $4.38 and $3.87 per MMbtu respectively. Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
At December 31, 2010 and 2009, our net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.
Note 5 - Notes Payable
Notes payable as of December 31, 2010 and December 31, 2009 consisted of the following:
December 31,
December 31,
Senior credit facility (RLE)
$ 818,309
$ 1,223,309
Senior credit facility, (AE)
2,032,188
2,032,188
Margin loan
-
125,495
Line of credit
24,308
1,300
Unamortized Discounts
(104,855)
(6,608)
Totals
$ 2,769,950
$ 3,375,684
Senior credit facility of RLE (“RLE Credit Facility”) and Senior Credit Facility of AE (“AE Credit Facility”) and (collectively “The Credit Facilities”)
MBL has opted not to advance any further funds on the Credit Facilities. The principal balance due MBL exceeded $2M on October 9, 2009 and MAC’s ownership automatically increased from 25% to 49%.
In September 2006, RLE entered into the RLE Credit Facility with Macquarie Bank Limited (MBL) originally for up to $25 million. The note was collateralized by substantially all of the assets of RLE. In addition, we pledged our ownership interest in RLE and executed a parent company guarantee to pay up to $500,000 of the outstanding indebtedness as additional security. During the year ended December 31, 2006, we incurred legal costs associated with the note of $228,751. These costs were capitalized as deferred finance charges and are amortized straight-line over three years, the life of the facility.
In October 2007, AE entered into the AE Credit Facility with MBL originally for up to $10 million. The note was collateralized by substantially all assets of AE. The agreement provides 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 $1,500,000. We contributed certain lease interests to AE. AE’s company agreement provides for board representation for MBL and joint consent is required for certain transactions. Because of the shared control of AE and in accordance with established practice in the oil and gas industry, we proportionately consolidate AE. Our financial statements include our pro-rata 51% share of assets, liabilities, income and lease operating and general and administrative costs and expenses of AE.
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We measured the fair value of the debt proceeds and the equity interest conferred on the date of inception of the facility and allocated the proceeds of the note based on the relative fair values of the debt and equity. We used the proceeds of the first tranche of the debt as the fair value of the debt. Because there were no proved reserves on the lease interests owned by AE and no objectively determinable fair value, we used the accumulated historical costs of the lease interests to approximate the fair value of the equity interest. The relative fair value of the investment was allocated between the note and equity interest as follows:
Equity
$
38,899
Debt
448,392
Total
$
487,291
The discount arising from this transaction was recorded at the inception of the note and is amortized straight-line over the life of the credit facility, 36 months. In addition, during the year ended December 31, 2008, we incurred legal costs associated with the note which were capitalized as deferred finance charges of $51,390 and which are amortized straight-line over the life of the facility.
In April 2008, the note was modified to accommodate our contribution of the Ensminger project to AE. Modifications included increasing the threshold for the step up of MBL’s equity interest to 49% from $1,500,000 to $2,000,000 and reclassifying tranches available within the facility. Because of the structure of the note, the modification was evaluated by comparing the borrowing capacity prior to the modification to the borrowing capacity after the modification. The borrowing capacity of the facility was unchanged. Thus, the only change to the accounting for the note is that additional deferred financing charges of $38,668 were recorded and are amortized over the remaining life of the credit facility, 18 months.
In February 2010, we entered into a supplementary agreement with MBL under which, they effected a partial release of mortgage in certain assets 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.
Beginning at the closing of the Reorganization through April 7, 2011 we entered into a series of amendments under which:
·
The maturity date of our Credit Facilities was extended to September 9, 2011.
·
All prior defaults or events of default prior to the modification of the Credit Facilities were waived;
·
The RLE Credit Facility was amended to eliminate any financial ratios or production covenants that would put us into default on the notes
·
Interest on the AE Credit Facility outstanding loans had been accrued at a fixed rate based on the prime rate at the time the Company borrowed the funds and upon default, at the default rate. In the loan modification, prior interest due was stipulated to be $361,221 ($184,223 net to our proportionate share) as of July 28, 2010 resulting in a gain on forgiveness of interest in the amount of $521,733 ($266,804 net to our proportionate share).
·
We agreed to make monthly interest payments at prime rate plus 8% on the RLE credit facility and made principal reduction payments on the Credit Facilities of $100,000 on each of August 5, 2010, August 20, 2010 and September 20, 2010. We made a payment of $250,000 on November 15, 2010. We shall also pay amounts equal to , any proceeds from the sale of collateral, any insurance proceeds received.and1/6th of the gross proceeds of any subsequent equity raised
·
We cross-collateralized the RLE and AE Credit Facilities and AE and RLE each executed an unconditional guarantee of payment of the obligations under both Credit Facilities; Radiant executed a limited guarantee of payment of up to $500,000 for the obligations under both Credit Facilities;
·
MBL has agreed to convert $1,000,000 of the Credit Facilities into shares of Radiant common stock at a conversion price equal to the per share price of the most recent material equity raise from a non-affiliated person , provided that upon such conversion there (i) no event of default in the Credit Faciliies and (ii) $the Company has repaid $900,000, of aggregate principal and interest payments on the Credit Facility after April 7, 2011. Since we proportionally consolidate AE, the $1,000,000 conversion of debt to equity would only result in a $510,000 reduction to notes payable on our consolidate financial statements and;
·
MBL agreed to re-convey to JOG all interests in real property and membership interests conveyed to its affiliate Macquarie Americas Corp (“MAC”) in connection with the AE Credit Facility, provided that all obligations under the
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AE Credit Facility, RLE Credit Facility, and all letters of credit shall have been paid in cash prior to maturity of September 9, 2011.
In addition to the outstanding note payable, $186,150 is obligated as collateral for a letter of credit supporting a bond related to the plug, abandon, and restoration obligations on the Ensminger Project.
We have determined that the conversion option discussed above is a derivative, as more fully discussed in Note 5. The fair value of the option as of the date of the loan modification, $233,339, has been bifurcated from the note and will be measured at fair value at each reporting date. The value of the option has been recorded as a discount from the notes payable and will be amortized straight-line over the remaining term of the notes, seven months.
Margin Loan and line of credit
We have a line of credit available from our bank for up to $25,000 that carries 7% annual percentage rate and through July 2010 had a margin loan facility from our broker-dealer that carried a variable rate as discussed in Note3. As of December 31, 2010, we are obligated to pay $24,308 to our bank for the outstanding amount on the line of credit. The margin loan was closed and had $0 outstanding balance at December 31, 2010. On December 31, 2009 the outstanding amounts were $125,495 and $1,300 on the margin loan and line of credit, respectively.
18% Debentures
Prior to the closing of the Reorganization, Radiant sold debentures with a face amount of $475,000 and issued warrants to purchase 237,500 shares of Radiant common stock to three investors. The debentures have an 18% per annum stated interest rate, an effective interest rate of 71%, and mature on July 31, 2011. The warrants have an exercise price of $1.00 per share and a term of up to 4 years. The proceeds of the debentures were allocated between the debentures and the warrants based on their relative fair market values. The fair market value of the warrants was determined using the Black-Scholes option pricing model with the following assumptions:
Risk-free interest rate
1.22%
Dividend yield
0%
Volatility factor
232%
Expected life (years)
4 years
We allocated the proceeds, which were collected prior to the close of the Reorganization Agreement and which totaled $475,000, between the warrants and the debentures based on the relative fair values as follows:
Relative fair value of warrants
$ 156,223
Relative fair value of debenture
$ 318,777
Gross proceeds
$ 475,000
The relative fair value of the warrants is reflected as a discount from the debt. The discount will be amortized using the effective interest method over the life of the debenture, one year.
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Prior to the closing of the Reorganization Agreement, Radiant sold a debenture with a face amount of $125,000 and issued warrants to purchase 62,500 shares of Radiant common stock to a related party of Radiant. The debenture has an 18% per annum stated interest rate, an effective interest rate of 71%, and matures on July 31, 2011. The warrants have an exercise price of $1.00 per share and a term of up to 4 years. The proceeds of the debentures were allocated between the debentures and the warrants based on their relative fair market values. The fair market value of the warrants was determined using the black-holes option pricing model with the following assumptions:
Risk-free interest rate
1.22%
Dividend yield
0%
Volatility factor
232%
Expected life (years)
4 years
We allocated the proceeds between the warrants and the debentures based on the relative fair values as follows:
Relative fair value of warrants
$ 41,113
Relative fair value of debenture
$ 83,887
Gross proceeds
$ 125,000
The relative fair value of the warrants is reflected was recorded as a discount from the debt. In November 2010, $500,000 of the debentures was converted into 500,000 shares of common stock. Additionally, we paid off the remaining $100,000 of the debentures from the proceeds of sales of common stock. The Company recorded interest expense of
Derivative liabilities
In connection with the convertible note and related warrants, we evaluated the exercise feature of the warrants and the conversion feature of the convertible debt under FASB ASC 815, Derivatives and Hedging, and determined that these instruments have characteristics of a liability and therefore a derivative liability under the above guidance. The warrant and convertible debt agreements contain a reset (“ratchet”) provision that creates a variable exercise price. As a result, this embedded feature is bifurcated and recorded as a derivative liability. This liability is marked-to-market at the end of each reporting period and the resulting gain or loss is recorded as a component of earnings. At December 31, 2010, the aggregate fair value of these derivative liabilities is $231,526.
Fair value measurements
FASB ASC 820, Fair Value Measurements and Disclosures defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. FASB ASC 820 also establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. FASB ASC 820 describes three levels of inputs that may be used to measure fair value:
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. Our derivative liabilities are classified as Level 3.
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.
The following table provides a summary of the fair value of our derivative liabilities as of December 31, 2010 (there was no
F- 13
derivative liabilities as of December 31, 2009):
These derivative liabilities did not exist at December 31, 2009. The fair value of the derivative liabilities at inception was $119,465 and $233,339 related to the warrants and convertible debentures, respectively. The change in value of the derivative liability associated relates to a mark-to-market adjustment, which is reflected in the statement of operations.
Note 6 - Deferred Gain
In 2007, Jurasin created Amber and entered into a credit facility with MBL (See Note 5). In connection with the credit facility, MAC received a 25% ownership interest in Amber. In addition, when the outstanding loan exceeded a set amount, MAC received an additional 24% ownership. In April 2008, Jurasin contributed assets with a historical cost of $189,670 to Amber. MAC’s pro rata share of the assets, $47,417, is reflected as a basis adjustment in the underlying asset and was recorded as a deferred item in oil and gas properties. Similarly, during 2009, MAC received the additional 24% ownership in Amber, which resulted in an additional basis difference of $57,994. This amount, along with the remaining balance of the $47,417 amount recorded in 2008, was netted against the deferred gain (see below).
On October 9, 2009, our ownership interest in Amber reduced from 75% to 51% in accordance with certain terms of the company agreement as discussed in Note 5. At the time of the change in ownership percentage, Amber’s equity was a deficit because the aggregate liabilities exceeded the aggregate assets. The reduction in ownership percentage triggered a basis difference between Jurasin’s investment and the underlying net liability. As a result, we recorded a deferred gain, net of the unamortized basis difference noted above, and is amortizing the net balance into income over the life of the oil and gas assets. The difference in basis as of October 9, 2009 was $443,954, which equates to 24% of the accumulated losses in Amber through that date. The net deferred gain of $338,543 will be recovered over 17 years, the useful life of Amber’s underlying oil and gas assets as indicated in our reserve report, as a reduction of depletion. We recovered $20,376 and $5,008 during the years ended December 31, 2010 and December 31, 2009, respectively, resulting in a carrying value of $313,159.
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Note 7 - Asset Retirement Obligation
The following is a reconciliation of our asset retirement obligation liability as of December 31, 2010 and 2009:
Liability for asset retirement obligation, beginning of period
$
138,323
$
173,605
Additions
-
-
Liabilities transferred in conjunction with adjustment of interest in subsidiary
-
(38,162)
Assumption of liability in conjunction with partial sale
(48,610)
Revisions in estimated cash flows
-
(11,709)
Accretion
7,799
14,589
Liability for asset retirement obligation, end of period
$
97,512
$
138,323
Note 8 - Common Stock and Common Stock Options
Common Stock
Immediately prior to the Reorganization we had 4,166,667 shares of $.01 par value common stock outstanding to John M. Jurasin (“Majority Shareholder”), our chairman of the board and chief executive officer.
In May 2010, JOG issued 20 shares of its common stock to employees and a contractor contingent upon the closing of a reverse acquisition transaction. In the Reorganization Agreement these shares were converted in 833,335 of our $.01 par value common shares. The shares were valued at $1.00 per share, the value of a private placement offering for Radiant common stock (“PPO”) and are recorded as share based compensation. The par value is shown in common stock and the balance is paid in capital.
Common shares retained by the original registrant were 2,492,639.
Connected to the closing of the Reorganization, Radiant issued common stock to consultants as follows:
·
50,000 shares of common stock to a former officer of Radiant on August 5, 2010 as consideration associated with his entering into an agreement to serve as one of our directors. The shares were valued at $50,000, or $1.00 per share, the value of the PPM and the $50,000 has been included as an expense for stock based compensation. 50,000 additional shares will vest one year from the Reorganization Agreement closing date.
·
543,205 shares of Radiant common stock to an investment relation/public relations firm on August 12, 2010 for services. The shares are fully vested and non-forfeitable at the time of issuance. The shares were valued at $543,205, or $1.00 per share, the value of the PPM and expensed as stock based compensation.
·
3,000,000 shares of Radiant common stock to John Thomas Financial (“JTF”), as consideration for an investment banking agreement on August 23, 2010. As amended the agreement states that in the event JTF places equity or equity equivalent offerings, it will receive a cash placement agent fee of 10% of the gross proceeds of any offerings and cash expense reimbursement of 3% of the gross proceeds of any offerings, except that the fees and expense reimbursements are 8% and $75,000 respectively, for the first $2,000,000 (exclusive of the $600,000 raised in August 2010) of proceeds. At the closing of each equity offering, the firm will receive warrants to purchase one share of common stock for each ten shares sold with an exercise price of 105% of the offering price of the stock. The investment banking firm will forfeit 2,000,000 of the 3,000,000 shares received at the signing of the original agreement if, within 12 months after a registration statement has been filed and declared effective, $10,000,000 has not been raised pursuant to the agreement; We also contracted with JTF for consulting services at $8,000 in cash per month for one year after the first closing of at least the Minimum amount under the PPM. The first closing was on November 12, 2010. The 1,000,000 vested shares were valued at $1,000,000 or $1.00 per share, the value of the PPO and are shown in capital as an offering cost. Two million of these shares are forfeitable and have a service condition. One million shares were reflected in the statement of changes in shareholders’ deficit.
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JTF will be the placement agent for a series of private offerings for up to $14,500,000 on a best efforts basis. The fee paid is reflected as a reduction of additional paid in capital as a deferred offering cost, which will offset the gross proceeds received from equity offerings. The investment banking agreement also provides for the placement of debt instruments. As debt offerings are closed, the pro rata portion of the pre-paid offering costs associated with the debt will be recorded, to deferred finance charge.
The agreement requires Radiant to file a registration statement with the Securities and Exchange Commission within 30 days of the earlier of (i) raising a total of $12 million and (ii) March 31, 2011, and to use its best efforts to have the registration statement declared effective within 120 days from the filing of the registration statement. The Company does not anticipate meeting this filing requirement and will be required to issue an additional 72,900 shares and has accrued registrations rights expense of $72,900 based on a fair value of $1 per share.
In the event that JTF places debt financing, they will receive a cash placement fee as follows: 5% of the first $10 million, 4% of the next $10 million, 3% of the next $10 million, 2% of the next $10 million, and 1% of any amounts raised over $40 million. If Radiant enters into additional financing with MBL, JTF will receive 2% of the cash proceeds. As of December 31, 2010, $1,215,000 has been raised.
Radiant issued to accredited investors (i) on November 12, 2010, 1,065,000 shares of our common stock for proceeds of $565,000 and to extinguish $500,000 of the 18% debentures into 500,000 shares of our common stock, less an 8% sales commission of $85,200 and related expenses of approximately $31,000 and (ii) on November 15, 2010, 150,000 shares of our common stock for gross proceeds of $150,000 less an 8% sales commission of $12,000. In addition, the Company granted demand registration rights with respect to the resale of the 1,215,000 shares of common stock issued. As part of the compensation for placement of the offering John Thomas Financial received warrants to purchase 121,500 shares of our common stock for $1.05. The Company used a portion of the proceeds to repay $250,000 on the Credit Facility and $100,000 plus accrued interest for the remaining 18% debentures.
The agreement provides for the issuance of up to an additional 1,000,000 shares of our common stock upon the satisfaction of certain performance conditions. Under the agreement for the performance of each of the following conditions (up to a maximum of four), the former JOG shareholders will receive 250,000 additional shares of common stock. As of December 31, 2010, two of the performance conditions have been met resulting in the issuance of 500,000 of these common shares. The performance conditions that were met were the nomination of the southern acreage for lease and the re-acquiring of the seismic permit on 1,000 net acres for Amber. The remaining performance conditions of permit on a well on the Coral; the re-acquiring State seismic permit covering open acreage in Bayou Teche, Grand Lake and Attakapas Wildlife Management Areas; re-acquire seismic permit on additional 1,000 acres on Amber lease; extend Apache Seismic Permit and Sub-Lease from September 2010; and execute seismic services contract for shooting of 3-D survey.Of these, 450,677 were issued to the John M Jurasin, our chief executive officer.. The shares were valued at $500,000 or $1.00 per share, the value of the PPO and recorded as share based expense. There are still 500,000 shares remaining which can be vested if certain additional performance conditions are met.
In February 2011 the Company entered into a settlement agreement with Mr. Allen Hobbs, our former controller, in full settlement of his employment agreement. As part of this settlement agreement Mr. Hobbs received 12,967 shares of our common stock not previously earned.
Common Stock Options
Immediately subsequent to the reorganization, Radiant granted options to purchase 694,122 shares of Radiant common stock with an exercise price of $1.00 per share and a term of 10 years to JOG employees and an option to purchase 93,000 shares of common stock with an exercise price of $1.00 per share and a term of 10 years to a JOG consultant. The options vest 1/3 on the first anniversary of the grant, 1/3 on the second anniversary of the grant, and 1/3 on the third anniversary of the grant. The fair value of the options issued to employees, $690,876, was based on the quoted market price of Radiant's stock on the date of grant and estimated using the Black-Sholes option pricing model. It will be recorded as compensation expense over the vesting period in accordance with financial accounting standards. The Company recorded $95,954 of compensation expense in 2010 related to these options. The fair value of the option issued to the consultant, $92,873, was based on the value of the PPO and estimated using the Black-Sholes option pricing model and will be recorded as consulting expenses over the vesting period in accordance with financial accounting standards. The Company recorded $12,899 of consulting expense in 2010 related to these options. The unamortized stock based compensation and consulting expense on these options is $673,423 at December 31, 2010. The weighted average exercise price is $1 for all outstanding options. The weighted average remaining contractual term for all
F- 16
options outstanding is 9.6 years. There is no intrinsic value on stock options at December 31, 2010. There were no stock options outstanding at December 31, 2009 and no other stock options were granted other the 694,122 to employees and the 93,000 options granted to consultants. The following assumptions were used in the Black-Sholes option pricing model:
Risk-free interest rate
1.93%
Dividend yield
0%
Volatility factor
229%
Expected life (years)*
6 years
The expected term of the options was computed using the “plain vanilla” method as prescribed by Securities and Exchange Commission Staff Accounting Bulletin 107 because we do not have sufficient data regarding employee exercise behavior to estimate the expected term. 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.
Warrants
Prior to the closing of the Reorganization, Radiant sold debentures with a face amount of $475,000 and issued warrants to purchase 237,500 shares of Radiant common stock to three investors and sold a debenture with a face amount of $125,000 and issued warrants to purchase 62,500 shares of Radiant common stock to a related party of Radiant. The warrants have an exercise price of $1.00 per share and a term of up to 4 years. The proceeds of the debentures were allocated between the debentures and the warrants based on their relative fair market values (see note 5). The warrants vested immediately. The total relative fair value of these warrants was $197,336 and was recorded as a debt discount and amortized using the effective interest method. As of December 31, 2010, the $197,336 was fully amortized. The following assumptions were used in the Black-Sholes option pricing model:
Risk-free interest rate
1.22%
Dividend yield
0%
Volatility factor
232%
Expected life (years)
4 years
At the closing of 1,215,000 share equity offering in November 2010, JTF received 121,500 warrants to purchase exercise price of 1.05. 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. At December 31, 2010, the warrant had a fair value of $119,465 and this fair value was included in the derivative liability balance. There was no difference in fair value from the grant date to December 31, 2010. The following assumptions were used in the Black-Sholes option pricing model at December 31, 2010:
Risk-free interest rate
1.35%
Dividend yield
0%
Volatility factor
213%
Expected life (years)
4 years
The weighted average exercise price is $1.01 for all outstanding warrants. The weighted average remaining contractual term for all warrants outstanding is 2.55 years. There is no intrinsic value on warrants at December 31, 2010. There were no warrants outstanding at December 31, 2009 and the total outstanding warrants were 427,575 warrants at December 31, 2010.
Note 9 - Related Party Transactions
Related parties include John Jurasin, our chairman and chief executive officer, George Jarkesy, as director and manager of the John Thomas Bridge and Opportunity Fund, Robert M. Gray, director and vice president, Tim McCauley, vice president, David R. Strawn, shareholder, David M. Klausmeyer, shareholder, Macquarie Americas Corp “MAC”, an affiliate of MBL and the owner of 49% equity interest in AE and John Thomas Financial, Inc.
F- 17
Transactions involving related parties are as follows:
Macquarie Bank Limited
AE is partially owned by an affiliate of our lender, Macquarie Bank Limited, and Radiant uses the proportionate consolidation method to consolidate AE. Radiant pays for goods and services on behalf of AE and passes those charges on to AE through intercompany billings. Periodically, AE will reimburse Radiant for these expenses, or potentially pays for goods and services on behalf of Radiant. These transactions are recorded as a due to / from AE in Radiant’s records and as a due to / from Radiant in AE’s records. Due to the fact that Radiant only consolidates its proportionate share of balance sheet and income statement amounts, the portion of the due from AE related to the other interest owner does not eliminate and is carried as a due from AE until the balance is settled through a cash payment. Due from related party was $ 382,343 and $139,193 as of December 31, 2010 and December 31, 2009, respectively.
John Jurasin
Effective March 2010, we assigned certain legacy overriding royalty interests 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. We retained our working interests in these projects. Additionally, we assigned our working interest in a project, Charenton, to the related party entity. We did not receive any proceeds for the conveyances and, except for the Ensminger Project, the interests assigned had a historical cost basis of $0. The Ensminger Project had allocable costs of $23,446. The conveyance was accounted for as a transaction between entities under common control and the ORRI was recorded as a distribution to shareholder and transferred out of property at it historical cost.
John M Jurasin advanced us $29,725 and $0 as of December 31, 2010 and December 31, 2009, respectively. The funds were advanced to pay operating expenses and there are no formal repayment terms. At December 31, 2010 the Company owed Mr. Jurasin $25,000 for unpaid salary. Two notes were issued to Mr. Jurasin in lieu of payment of dividends from Radiant, which in turn represented funds advanced by Radiant to its subsidiaries JOG, AE and RLE to fund operations. A note for $884,000 accrues interest at a rate of 4% per annum and matures upon the earlier of (i) May 31, 2013 or (ii) the date on which the Company closes any equity financing in which the Company receives gross proceeds of at least $10,000,000. The other note is for $165,000 and accrues interest at a rate of 4% and is due and payable upon demand at any time subsequent to the repayment in full of all outstanding indebtedness under the Credit Facility. (see Note 5) Total accrued interest on the two notes in 2010 was $15,784.
George Jarkesy and John Thomas Bridge & Opportunity Fund
John Thomas Bridge & Opportunity Fund (“JTBOF”) is a significant stockholder, and its managing partner, George Jarkesy, is a director for the company. The Company owes JTBOF for a note issued in April 2010, in the principal amount of $7,000, bearing interest at 8%. Total accrued interest on the note is $380. The Company also owes JTBOK for a $50,000 advance in December 2010, on which there are no formal repayment terms. In addition JTBOF subscribed to $125,000 of the debentures described in which was converted into 125,000 shares of Radiant common stock. (See note 5).
In April 2010, Mr. Jarkesy advanced the Company $25,000 for working capital purposes. The terms of the repayment have not yet been determined.
John Thomas Financial, Inc
John Thomas Financial, Inc is a significant stockholder. The Company issued 3,000,000 shares of common stock for investment banking services. In the event JTF places equity or equity equivalent offerings, it will receive a cash placement agent fee of 10% of the gross proceeds of any offerings, and cash expense reimbursement of 3% of the gross proceeds of any offerings, except that the fees and expense reimbursements are 8% and $75,000 respectively, for the first $2,000,000 (exclusive of the $600,000 raised in August 2010) of proceeds. JTF will also receive warrants to purchase one share of common stock for each ten shares sold with an exercise price of 105% of the offering price of the stock. Radiant will pay a consulting fee of $8,000 in cash per month for one year after the first closing of at least the Minimum amount under the private offering. See note 6 - Common Stock.
David R. Strawn and David M. Klausmeyer
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Mr. Strawn and Mr. Klausmeyer, shareholders of the Company each loaned the Company $12,193 between March 2002 and June 2005. The notes accrue interest at 8% per annum. The Company recorded interest expense in 2010 of $3,597 and the total accrued interest is $23,505.
Robert M. Gray and Timothy N. McCauley
Mr. Gray, director of the Company and employee until April 2010 and Mr. McCauley vice president of the Company were owed $15,625 and $18,125 in salary at December 31, 2010. In addition at December 31, 3010, Mr. Gray was owed $50,606 for consulting services rendered prior to becoming an employee of Radiant.
Note 10 - Income Taxes
As of December 31, 2010, we had approximately $2,065,000 of U.S. federal and state net operating loss carry-forward available to offset future taxable income, which begins expiring in 2022, if not utilized.
Our 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.
Components of deferred tax assets as of December 31, 2010 and 2009 are as follows:
The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we 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:
The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at December 31, 2010 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, our income tax years 2006 through 2010 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. In certain jurisdictions we operate 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 our effective income tax rate.
Note 11 - Commitments and Contingencies
Contingencies
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From time to time, we 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, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our 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, we may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.
Commitments
In conjunction with our acquisition of the Ensminger Project in 2008, we assumed the obligation to plug the Ensminger #1 well, which includes providing a bond in the amount of $186,150, which we obtained by collateralizing our assets under the letter of credit available pursuant to the Amber Credit Facility. As a result of the sale in February 2010 of a portion of our working interest, third parties are responsible for $130,305 of this liability.
We lease office space in Houston, Texas. Our office lease is due to expire in April 2011 with options for renewal for up to 3 years at specified rates. Lease expense for the years ended December 31, 2010 and 2009 was $85,888 and $85,868, respectively. The following table displays our lease commitments for the next five years:
2012-2015
Commitments
$25,035
-
Note 12 - Additional Financial Statement Information
Property and Equipment
Property and equipment consisted of the following:
Depreciation expense was $5,211 and $18,722 for the years ended December 31, 2010 and 2009, respectively.
Deposit
In December 2009, Amber received an advance payment of $127,500 towards a purchase of a partial working interest in Ensminger. In February 2010, Jurasin conveyed an overriding ownership interest it owned in Ensminger to the counterparty. There were no deposits as of December 31, 2010.
Accounts payable and accrued expenses
Accounts payable and accrued expenses consist of the following:
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Accounts payable
$
689,712
$
252,868
Registration rights liability
72,900
Accrued payroll obligations
29,852
3,907
Accrued taxes
25,150
23,733
Other payables
847,059
1,011,021
Accounts payable and accrued expenses
$
1,664,673
$
1,291,529
Other payables relate to our Aquamarine Project and consist of AFE overruns and a penalty for our non-consent to a workover procedure. In accordance with the joint operating agreement, the amounts billed will be recovered by offsetting the revenue from the property against the payable.
The following is a reconciliation of our liability for other payables as of December 31, 2010 and 2009:
Liability for other payables, beginning of period
$
1,011,021
$
880,497
Additions
2,693
201,376
Revenue offset
(166,655)
(70,852)
Liability for other payables, end of period
$
847,059
$
1,011,021
Note 13 - Subsequent Events
In February 2010, the company issued a convertible promissory note to Fermo Jaeckle in the principal amount of $475,000. As additional consideration Mr. Jaeckle was issued 475,000 shares of our common stock. The note bears interest at 10% per annum and matures on July 31, 2011. At the holder’s option, the note may be converted into the Company’s Series A Convertible Redeemable Preferred Stock at a conversion price of $30.00 per share.
In April 2010, Mr. Jarkesy advanced the Company $25,000 for working capital purposes. The terms of the repayment have not yet been determined.
Note 14 - Supplemental Oil and Gas Information (Unaudited)
The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities -Oil and Gas, (ASC 932).
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
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Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
In the following table, natural gas liquids are included in natural gas reserves. The oil and natural gas liquids price as of December 31, 2010 and 2009 are based on the 12-month unweighted average of the first of the month prices of the West Texas Intermediate posted price which equates to $79.43 per barrel and $61.18 respectively. Oil and natural gas liquids prices as of December 31, 2008 are based on the respective year-end West Texas Intermediate posted price of $44.60 per barrel. The gas price as of December 31, 2010 and 2009 is based on the 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $4.38 and $3.87 per MMbtu respectively. Gas prices as of December 31, 2008 are based on the year-end Henry Hub spot market price of $5.71 per MMbtu. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, in on-shore Louisiana and off-shore Texas.
The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers.
Proved Reserves
Noteworthy amounts included in the categories of proved reserve changes for the years 2010, 2009 and 2008, and in the above tables include:
·
Additions - Reflects the addition of the Coral Project.
·
Revisions of Previous Estimates - The Ensminger project was revised upward as a result of seismic re-processing indicating a larger reservoir while our Aquamarine project was revised downward as a zone depleted sooner than expected. Proved reserves must be estimated using the assumption that prices and costs remain constant for the duration of the reservoir life. Due to significantly lower average first-day of the month gas prices calculated for the 12 months ended December 31, 2009 compared to prices as of December 31, 2008, certain of our proved reserves were no longer economically producible.
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Sales of minerals in place - In February 2010, we sublet a portion of our interest in Ensminger, thus reducing our before payout working interest and net revenue interest to 6.375% and 4.62188%, respectively. This also includes a change in our proportional ownership of Amber, from 75% to 51% during the year ended December 31, 2009, See Note 4 - Oil and Gas Properties.
The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month un-weighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, and allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules). The Revised SEC rules did not affect the quantities of our proved reserves.
The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.
Capitalized Costs Related to Oil and Gas Activities
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization. All oil and gas properties are located in the United States of America.
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Costs Incurred in Oil and Gas Activities
All costs incurred associated with oil and gas activities were incurred in the United States of America. Costs incurred in property acquisition, exploration and development activities were as follows:
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities -Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.
We believe that the following factors should be taken into account when reviewing the following information:
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future costs and selling prices will probably differ from those required to be used in these calculations;
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due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
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a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
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future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, for the year ended December 31, 2008 the future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required. At December 31, 2009, as specified by the SEC, the prices for oil and natural gas used in this calculation were the un-weighted 12-month average of the first day of the month (12-month un-weighted average) cash price quotes, except for volumes subject to fixed price contracts.
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The Standardized Measure is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2009:
The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. Due to net operating loss carryforwards related to producing activities, income taxes have not been provided at December 31, 2010. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
Results of Operations for Producing Activities
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