Item 1. Business.
Business Development
Native American Energy Group, Inc. (“we,” “us,” “our”) was incorporated in the State of Nevada on January 18, 2005 under the name Halstead Energy Corporation (“Halstead”). On January 25, 2005, our name was changed to Native American Energy Group, Inc.
In October 2009, we completed a reverse merger transaction with Flight Management International, Inc. (“Flight Management”), a Delaware corporation. Simultaneous with the consummation of the merger, Flight Management changed its name to Native American Energy Group, Inc.
As of the date of this filing, our common stock is quoted on the Over-the-Counter Quotation Bureau (“OTCQB”) market under the symbol “NAGP.” Our wholly owned subsidiaries, NAEG Alaska Corporation (“NAEG Alaska”), a Delaware corporation incorporated in 2005 that was formerly known as Fowler Oil & Gas Corporation, and NAEG CBM Operations LLC (“NAEG Operations”), an Alaskan limited liability company formed in August 2006 that was formerly known as Fowler Oil & Gas Alaska, LLC, are our operating entities in Alaska. In November 2011, we reinstated NAEG Economic Development Corporation (“NEDC”), a not-for-profit company established for the purpose of supporting worthy causes and local programs, which in turn promote Native American economic self-sufficiency.
Operations
We are a development-stage energy resource development and management company, which is defined by the Financial Accounting Standards Board (FASB) as an entity that has not commenced planned principal operations and has no significant revenue. In August 2011, we commenced a pilot five well-workover program on four oil and gas lease holdings in the Williston Basin in Montana. During the months of August 2011 through December 2011, we completed the first phase of enhanced oil recovery (“EOR”) operations on four of our five wells. As a result of the initial EOR operations during the 3rd and 4th quarters of 2011, we collected and sold approximately 919 barrels of oil, in aggregate, from two wells during the 4th quarter ending December 31, 2011. Subsequently, we collected and sold approximately 314 barrels of oil, in aggregate during 2012. During the summer of 2013, subject to adequate financing, we intend to complete Phase 2 of the 5-Well Program and commence full-scale oil production shortly thereafter.
Currently, we have four principal projects:
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development of oil and gas interests in the Williston Basin in Montana (5-Well Program)
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development of coal-bed methane natural gas (“CBM”) in the Cook Inlet Basin in Alaska; and
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development of oil & gas properties on Native and non-Native American lands in Oklahoma using newer drilling and Enhanced Oil Recovery (EOR) technologies; and
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the implementation of vertical axis wind turbine power generation technology for the production of clean, cost-efficient green energy on all U.S. Native American Indian reservations.
We have been in the process of developing several energy projects for the past eight years. This has included the acquisition of oil properties in Montana, natural gas properties in Alaska and identifying both oil & gas properties in Oklahoma. Our management believes, however, that properties in these three states have potential based on the limited EOR operations that have been conducted there and that there are opportunities to acquire properties that formerly produced oil and gas that can be re-developed for commercial profitable operation using newer production techniques. We are also pursing oil properties in on both Native and non-Native American lands in Oklahoma whereby we can implement similar enhanced oil recovery techniques as we applied on the 5-Well EOR pilot program in Montana in addition to other technologies.
We have limited financial resources available, which has had an adverse impact on our activities and operations. Additional funding would allow the development of future wells, and pay for expenditures for exploration and development, general administrative costs, and possible entrance into strategic arrangements with a third parties. We plan to raise capital through the sale of equity or convertible debt securities and through loans from our stockholders and third parties. There can be no assurance that additional funds will be available to us on favorable terms, or at all. If adequate funds are not available, we may be required to curtail our operations significantly or obtain funds through entering into arrangements with collaborative partners or others that may require us to relinquish rights to certain of our assets that we would not otherwise relinquish.
Relations with Native American Tribes
We have dedicated a substantial portion of our business plan to the conscientious development and responsible management of our relationships with Native American tribes, which own vast reserves of a wide assortment of minerals, including oil, gas, coal and other valuable minerals. Much of this potential energy has gone undeveloped for a variety of reasons, including a lack of communication and distrust of potential development partners as well as tribal reasons to maintain lands in an undeveloped state.
Our management has committed the past decade to familiarizing themselves with the various Native American tribes, cultures, organizational structures, protocols and customs and believes that attractive arms-length mineral development arrangements can be reached with a large number of Native American tribes once a level of mutual trust and understanding is reached.
On August 15, 2005, we received the approval of our Nationwide Oil and Gas Bond from the Bureau of Indian Affairs at the United States Department of Interior in Washington D.C, which authorizes us to enter into or otherwise acquire an interest in oil and gas mining leases and oil and gas prospecting permits of various dates and periods of duration covering all lands or interests in lands held by the United States in trust for individual Native Americans or Native American tribes or bands also known as Federal Indian Reservations.
According to the Bureau of Indian Affairs at the United States Department of Interior, approximately 56.2 million acres are held in trust by the United States for various Indian tribes and individuals. There are approximately 326 Indian land areas in the U.S. administered as federal Indian reservations (i.e., reservations, pueblos, rancherias, missions, villages, communities, etc.).
In April 2007, we created a proprietary initiative called the Tribal Empowerment Program (the “Program”) whereby we promote tribal self-sufficiency by helping Native Americans to develop their own mineral resources and to use the revenue from such sources to implement renewable energy systems on their tribal lands. The Program has gained attention from tribes throughout the country and continues to win support from Native American activists, tribal leaders, U.S. politicians, spiritual leaders and business and energy professionals. In addition, in November 2011, we reinstated NAEG Economic Development Corporation (NEDC) for the purpose of supporting worthy causes and local programs, which in turn promote Native American economic self-sufficiency.
Williston Basin Operations, Montana
Since January 2005, we have been active in evaluating and acquiring oil and gas leases both on and around the Fort Peck Indian Reservation in the Williston Basin in Northeast Montana. We are currently focused on completing Phase 2 of our 5-Well Enhanced Oil Recovery Pilot Program on four oil and gas leases containing an aggregate of five wells on and around the Fort Peck Indian Reservation in the Williston Basin in Montana. The leases include historically producing oil and gas wells that were shut-in by previous oil and gas companies due to depressurization, paraffin, production falling below commercial levels at that time, termination of previous oil and gas leases by the tribal governments due to improper development and various economic reasons, and most commonly, declining oil prices. Phase 1 was completed in early 2012.
Our base of operations in the Williston Basin is located in the city of Wolf Point on the Fort Peck Indian Reservation. We have an equipment yard and maintenance facility with a workshop and three vehicle bays which is situated on approximately five acres. We own our own workover and well-servicing rig, which is used to re-work, service and drill shallow wells. Our standby field team includes fabricators, welders, machinists, heavy equipment operators, derrickmen, floor hands, roughnecks and rig operators, all of whom are independent contractors. The terms of the oil and gas leases typically range from three to five years and are automatically extended as long as any oil or gas is being sold off the lease or there is an agreement or understanding with the landowner to extend the lease due to permitting issues, or delayed development or production.
Due to stronger market prices for crude oil as compared to natural gas, our current focus has been on four oil and gas leases, containing an aggregate of five wells, on and around the Fort Peck Indian Reservation in the Williston Basin in Montana. In August 2011, we began the initial phase of work-overs and EOR operations on five wells in Montana which is hereinafter referred to collectively as the “Five-Well Program.” See Item 2 - Properties.
In our Five-Well Program, we leveraged advanced technology to enhance oil recovery on our leases. This technology, known as Single Entry Multi-Lateral Jetting System, or SEMJet®, has demonstrated its ability to enhance and exploit reservoirs and increase recovery of up to 50% more oil in place reserves from mature properties. Moreover, the SEMJet System gives us the ability to:
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inspect the condition of production tubing with in-situ inspection, log the cement bond and correlate the casing collars using its built-in logging system;
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create horizontal channels off any new or old wellbores that have 4.5” casing or greater, whether the wells are vertical, deviated or horizontal in design;
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enter mono-bore completions and jet lateral channels at a true 90º in casing as small as 3.5” using a secondary, unique coiled tubing system;
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unlock and stimulate trapped oil reserves beyond any near wellbore damage by displacing acid, specialty fluids or microbial products into the laterals;
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penetrate the reservoir and open up larger producing channels without using conventional perforating guns, which can damage the formation and are hazardous; and
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create a low pressure, high velocity circulating environment within the wellbore to ensure cuttings removal, geological samples and efficient well cleaning;
Jetting Down-Hole Schematic - Diagram Provided by SEMJET®
In September 2006, we consummated an Oil Sale and Purchase Agreement with Shell Trading U.S. Company (Shell), which provides for Shell to purchase all crude oil produced from our leases; and subjects us to no delivery commitments. Since 2006, we have sold oil from these five wells while performing minimal workover operations with our own workover service rig, surfactant treatments and flow testing. As a result of the initial EOR operations during the 3rd and 4th quarters of 2011, we collected and sold approximately 919 barrels of oil, cumulatively, from two wells during the 4th quarter ending December 31, 2011 and 175 barrels in the 1st quarter of 2012. During the summer of 2013, subject to adequate financing, we intend to complete Phase 2 of the 5-Well Program and commence full-scale oil production shortly thereafter.
The price of oil is a function of oil’s supply and demand, among other factors. Throughout 2008 and 2009, oil prices swung materially as demand contracted in light of the global recession.
According to the U.S. Energy Information Administration’s (“EIA”) Short-Term Energy Outlook, (the “Report”) dated May 7, 2013, the EIA projects that the West Texas Intermediate (“WTI”) spot prices are expected to average about $93 per barrel in 2013, which is $1.00 higher than the average WTI price of crude oil during 2012. The report can be accessed at the following link: http://www.eia.gov/forecasts/steo/pdf/steo_full.pdf
Cook Inlet Operations, Alaska
We explore areas where there are known coal resources because such areas have an increased likelihood of containing Coal Bed Methane (“CBM”). The Matanuska-Susitna (“Mat-Su”) Valley in Alaska is known for its significant coal reserves, which are larger than those in the prolific Powder River Basin of the United States. While the Mat-Su Borough Assembly has adopted some of the strictest regulations for coal bed methane drilling in the United States, our environmentally conscious approach to coal bed methane development led to approval of a Mat-Su Borough drilling permit in October 2, 2007 (“Permit”) and is the first and only CBM drilling permit issued by the Mat-Su Borough Planning Commission (“Mat-Su Borough”).
The issuance of the Mat-Su drilling permit was followed by the economic downturn and further decline in commodity prices in 2008 which changed the economics and fundability of the project. The permit expired on October 1, 2012. Today, we remain the only applicant that has ever received a CBM drilling permit in the Mat-Su Valley due to the Mat-Su Borough Assembly having adopted some of the strictest regulations for coal bed methane drilling in the United States. In addition, we have been approached by other local government agencies in the Mat-Su Valley that are pro-development of CBM and have the authority to issue drilling permits individually using the same permitting guidelines.
Natural gas production is in high demand by purchasers in the Mat-Su Valley such as the local gas and electric utilities including the Conoco Phillips LNG plant (“Conoco”) as they export liquefied natural gas to Japan directly from Alaska. Since 2008 and until recently, we have continued to maintain communication with the various prospective purchasers in the Cook Inlet area such as Conoco, Chugach Electric Association Inc. and the Matanuska Electric Association (“MEA”). In addition, MEA is working to build a 180 megawatt natural gas power generation plant as part of its mission of bringing reliable, affordable power to the residents of the Cook Inlet. Construction is proposed to begin 2013 and they expect to be ready for testing by October 2014. MEA expects to begin generating power by January 1, 2015.
As per our discussions with local officials, city governments, landowners, gas purchasers and the various permitting agencies in the region, we are confident that once adequate financing is identified, lease acquisitions and re-permitting can be achieved in an expeditious manner due to our relationships in the region as well as the growing demand and the dwindling supply of natural gas in the region.
According to the U.S. Energy Information Administration’s (“EIA”) Short-Term Energy Outlook, (the “Report”) dated May 7, 2013, EIA’s average 2013 Henry Hub natural gas spot price forecast is $3.80 per million British thermal units (MMBtu), an increase of $1.05 per MMBtu from the 2012 average spot price of $2.75. EIA expects that Henry Hub spot prices will average $4.00 per MMBtu in 2014. The report can be accessed at the following link: http://www.eia.gov/forecasts/steo/pdf/steo_full.pdf
Wind Energy Division - Overview
In February 2007, we entered into an exclusive technology and distribution rights agreement (the “Original Windaus Agreement”) for proprietary vertical axis wind turbines created by Windaus Energy, Inc. of Brantford, Ontario (“Windaus”). In March, 2010, we executed an amendment to the Original Windaus Agreement (the “Amendment” and, together with the Original Windaus Agreement, the “Windaus Agreement”), whereby we acquired exclusive manufacturing, marketing, sales, sublicensing and distribution rights to bring Windaus’ proprietary, highly advanced Vertical Axis Wind Turbine Energy Systems (the “Wind Turbine”) to the entire U.S. market, including all Native American Indian lands and reservations with boundaries established by treaty, statute, and/or executive or court order, and that are recognized by the U.S. Federal Government as territory in which U.S. federally recognized tribes American Indian tribes have jurisdiction (includes, without limitation, Rancherias, Pueblos, Indian Colonies, Alaska Native Villages and lands owned by Alaska Native Corporations.
Due to our current focus on the five well enhanced oil recovery program in Montana and other oil & gas development initiatives, in April 2012, we negotiated with Windaus to further amend the license agreement to reduce the licensed territory and relinquish NAGP’s manufacturing rights. On April 25, 2012, we amended the Windaus Agreement to reduce the licensed territory by approximately 95%, leaving NAGP only with distribution rights for all Indian Lands as specified in Exhibit A of the Technology License & Distribution Agreement which were filed as Exhibit 10.3 to Amendment No. 1 to our Form 10 Registration Statement filed November 16, 2010, all of which are incorporated herein by reference.
Contingent on funding, capital availability, certain strategic partnerships, we intend to engage in two segments of wind power generation:
1.
Wind Community Development: small to large-scale wind farms jointly owned by Native American Indian communities, small town local communities, farm owners and us. We plan to connect to the general utility electric grid to produce clean, environmentally sound wind power for use by the electric power industry.
2.
Single Unit Distribution: wind turbine systems to produce electrical power, both on and off the grid, for use by individual homeowners, small businesses, commercial industry, institutions, utility companies, schools, government buildings, apartment complexes, industrial sites, communication towers and military facilities.
Item 1A.
Item 1A. Risk Factors.
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
Item 1B.
Item 1B. Unresolved Staff Comments.
We are a smaller reporting company as defined by Rule 12b-2 of the Securities Exchange Act of 1934 and are not required to provide the information under this item.
Item 2.
Item 2. Properties.
Oil & Gas Properties, Wells, Operations and Acreage
Our properties consist primarily of interests in properties on which oil and gas wells are located, both non-producing and in progress, as well as undeveloped properties. Such property interests are often subject to landowner royalties, overriding royalties and other oil and gas leasehold interests and are listed below.
Five-Well Pilot Program
Below are background information and a field update on each well in the Five-Well Pilot Program. These five wells were specifically chosen due to the following important characteristics present in all wells: Permeability, Porosity and Pressure. Our management’s strategy regarding the Five-Well Program was to complete the initial workover (casing scraping, tubing testing), surfactant treatment and lateral jetting EOR process for the five wells as quickly as possible and complete the final phase of workovers necessary to bring the wells online and into production once we are adequately capitalized to do so. Due to our limited resources, our management completed as much of the plan as possible and intends to complete the Five-Well Program in its entirety by the end of the 3rd quarter of 2013 providing that we are able to raise sufficient funds in a private placement offering.
Cox 7-1 Well - located on 80 acres (SW NW of Sec.11-31N-44E) in Roosevelt County, Montana
Historically producing sweet crude from the shallow Mississippian Charles Formation, Cox 7-1 was first drilled in 1981 by Century Oil & Gas Corporation and completed at 35 barrels of oil per day, but was later shut-in primarily due to a build-up of naturally occurring paraffin which clogged perforations in the original well bore as well as a tubing anchor that was not able to be released or retrieved over the years by other operators. In addition, the well was only operating approximately 50% of the time mainly due to past operator’s inability to effectively correct mechanical problems with surface equipment. We began the workover and EOR process on this well in August 2011. During the well operations to retrieve the tubing anchor, it was discovered that, in fact, it was a packer instead of an anchor. We were successful in retrieving the packer and then proceeded with the EOR plan for the well. We completed the workover and EOR process in mid-September with satisfactory results. We installed updated surface equipment and in-ground flow lines. We plan to re-enter the well during the fall of 2013 and recomplete it by implementing a casing patch operation to bring the well online for production.
Sandvick 1-11 Well - located on 320 acres (SW NW of Sec.11-31N-44E) in Valley County, Montana
The well was originally drilled in 1983 by Clayton W. Williams, Jr. and was completed at 99 barrels of oil per day; however the average historical production of the well through the 1980s and 1990s declined to approximately 20 barrels per day, due largely to mud blockages down hole. During the initial phase of the workover, we succeeded in overcoming mud filtration issues which hindered past production. After jetting the laterals in the Ratcliffe formation, approximately 60 barrels of oil almost immediately flowed back into the pits on location, which indicated that we definitely stimulated the section of rock from which oil or gas is expected to be produced in commercial quantities (the “pay zone”). Swab testing showed a 30% oil cut (difference between oil and water) from total fluids. The well was brought online for testing in November at which time it exhibited strong oil production - during the initial 18 hours the well was online, it produced approximately 80 barrels of oil. However, a packer installed to close off a casing leak from a water zone above the oil zone lost integrity and allowed water to migrate into the wellbore which overpowered the pay zone. Consequently, we plan to re-enter the well during the fall of 2013 and recomplete the well by applying a cement squeeze into the casing to close off the water zone and then bring the well online for production.
Wright 5-35 Well - located on 160 acres (SW NW of Sec.35-24N-46E) in McCone County, Montana
This well was first drilled in 1960 by State Oil and Cities Service Oil Company. Original completion of the well resulted in 36 barrels of oil per day, a production level which persisted for most of its productive life through 1985 when it was shut down for two years. The well was brought back into production in 1987 and continued to produce oil until 1995 when it was again shut down. At that point in time, oil production had declined to approximately six barrels of oil per day due to a build-up of paraffin that plugged off perforations in the well bore. Following our acquisition of the lease in 2006, we serviced the well and applied a paraffin surfactant to clean the perforations, casing and tubing. Over the two-day testing period, the well produced over 400 barrels of 36 Degree API Gravity Oil. In November 2011, we completed the initial workover and EOR process of the Wright 5-35 well. Further, field crews successfully upgraded the electrical systems which power the surface equipment, replaced the pad under the pumpjack and winterized the well site. The production on the Wright 5-35 prior to originally being shut-in during 1995 was 9 barrels of oil per day. Well testing during the completion stage exhibited an oil cut ranging from 25% to 50%. On December 10, 2011, the well was brought online into minimal production and underwent adjustments to surface equipment to stabilize the well. During the following 2 weeks after being brought online, the well was generating approximately 24 barrels of 36 degree API Gravity Oil per day until it was shut-in during the last week of December 2011 pending purchase of additional equipment needed to effectively operate the well. Based on the well test which included swab testing, we estimate that daily oil production will approximate 60 barrels per day once we begin steady production from this well.
Beery 2-24 & 22-24 - located on 320 acres (N/2 of Sec.24-23N-49E) in McCone County, Montana
Both Beery 2-24 and Beery 22-24 are situated on NAGP’s 320 acre lease in north McCone County, and located in an oil and gas field originally discovered by Shell Oil in the early 1950s. Beery 22-24 was first drilled and completed in 1953 and is the only original well drilled by Shell that remains in the field today. This well was the second largest producer in the East Richey Field, producing 2300 barrels of oil per day (“BOPD”) during its active production life. Beery 2-24 was originally drilled and completed by Dick Shackelford and Edward Beery in 1980 and initially produced 24 BOPD. The Beery property produced approximately 350,000 barrels of the 2 million barrels of cumulative oil produced in the entire field.
In January 2012, we completed the lateral jetting operations of the Beery 2-24. We also purchased and installed four oil storage tanks at the tank battery location onsite providing 1600 barrels of total oil capacity. Since the jetting of the laterals combined with a proprietary chemical blend, the down-hole pressures have increased significantly and the well has naturally flowed in excess of 5 barrels of oil and a significant amount of gas every morning when the well was being bled off for daily operations. The swab tests indicate a consistent 50% oil cut from total fluids. We plan to mobilize the work-over rig to this site during the summer of 2013 and complete the workover process which includes installation of a specialized down-hole pump specifically designed for this well, replacing the current pumpjack with a larger pumpjack that will allow us to get a longer stroke when the well is in production and install electric equipment needed to operate the well which includes a 50 Horsepower motor. We plan to re-enter the well during the early summer of 2013 and recomplete it by implementing a casing patch operation and bring the well online for production. Based on the well tests from the EOR process, we are estimating the daily production from this well to be at least 100 barrels per day.
Beery 22-24 - Rework Plan
The Beery 22-24 is the fifth and final well in NAEG's five well Rework Program. Shell completed this well at 2600 barrels of oil per day in 1950's and it was one of the largest producers in the area. In 1986, the operator at the time installed a 385' liner at the bottom of the well in order to shut off water from one of three zones open. (B2, C2 and Mission Canyon) Until recently, this well would not have many options to improve oil production but with perforating technology achieving penetration distances of three feet or better and with the success of surfactants, we feel that after what was learned from the Beery 2-24 EOR program, this well has very similar potential as we are exploiting the same geological formations and pay-zones. Our plans include, perforating more holes in the B2 zone but more importantly, perforate the same part of the C2 zone that was completed in the Beery 2-24. The perforating will be followed up with a two hundred barrel surfactant and acid treatment. Ball sealers will be used to make sure all of the perforations are open. Based on the geology, production history of the well and our experience with the same formations in the Beery 2-24 which is in the same field, we are estimating the daily production from the Beery 22-24 well to be at 70 barrels per day. Subject to adequate financing, we plan to commence the workover and EOR operations on the Beery 22-24 well during the summer of 2013 after completion of the Beery 2-24 well.
Facilities
Corporate Office - We maintain our current principal office at 61-43 186th Street Fresh Meadows NY 11365.
Montana Maintenance Facility - We maintain an equipment yard and maintenance facility on the Fort Peck Indian Reservation in Montana. It is located on 5 acres and includes a tool workshop and three vehicle bays. It is located on Highway 2 in Wolf Point, Montana. There is no physical address for this location.
Item 3.
Item 3. Legal Proceedings.
The information required by Item 3 is included in “Notes to the Consolidated Financial Statements-Note 15 - Commitments and Obligation-Litigation.”
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information.
While there is no established public trading market for our common stock, our common stock is quoted on the OTCQB market under the symbol NAGP. The following table sets forth the high and low bid prices for our common stock reported by the OTC marketplace for the periods indicated below. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
On March 13, 2008, the Depository Trust & Clearing Corporation (“DTC”) had originally suspended trade and settlement services (known as a “Global Lock” or “Chill”) for our Company’s security along with 25 other companies, resulting in our common stock not being ineligible for delivery, transfer or withdrawal through the DTC system and not being electronically tradable. On June 21, 2012, after a four year appeal, the Depository Trust Company (DTC) restored full electronic clearance and settlement services for the Company’s “NAGP” security. A notice of reinstatement was filed as Exhibit 99.1 to an 8-K filed on June 25, 2012.
Holders
As of May 20, 2013, we had 756 registered shareholders of common stock.
Dividends
We have not paid any cash dividends to date and do not anticipate or contemplate paying any dividends in the foreseeable future. It is the present intention of our management to utilize all available funds for the growth of our business.
Equity Compensation Plan Information
Our 2011 Equity Incentive Plan (the “2011 Equity Incentive Plan”) was adopted by our Board of Directors effective June 6, 2011, and has been approved by the written consent of holders of shares of our common stock and Series A Preferred Stock.
Recent Sales of Unregistered Securities
In the fiscal year ended December 31, 2012, we made the following shares of unregistered securities, some of which have previously been disclosed on our Current Reports on Form 8-K and our Quarterly Reports on Form 10-Q:
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During the three months ended March 31, 2012, we issued and sold to four investors an aggregate of 592,000 shares of our common stock at a per share purchase price of $.25 for proceeds of $148,000.
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During the three months ended June 30, 2012, we issued and sold to 13 investors an aggregate of 675,800 shares of our common stock at a per share purchase price of $0.25 for proceeds of $168,950.
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During the three months ended September 30, 2012, we issued and sold to 15 investors an aggregate of 551,200 shares of our common stock at a per share purchase price of $0.25 for proceeds of $137,800.
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During the three months ended December 31, 2012, we issued and sold to 2 investors an aggregate of 850,000 shares of our common stock at a per share purchase price of $0.10 for proceeds of $85,000.
Item 6.
Item 6. Selected Financial Data.
We are a smaller reporting company as defined by Rule 12b-2 of the Securities Exchange Act of 1934 and are not required to provide the information under this item.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following information should be read in conjunction with the consolidated financial statements and notes thereto appearing elsewhere in this Annual Report on Form 10-K.
Overview
Native American Energy Group, Inc. is a development-stage energy resource development and management company, with four principal projects:
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development of oil and gas interests in the Williston Basin in Montana (5-Well EOR Program);
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development of coal-bed methane natural gas (“CBM”) in the Cook Inlet Basin in Alaska;
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development of oil & gas properties on Native and non-Native American lands in Oklahoma using newer drilling and Enhanced Oil Recovery (EOR) technologies; and
·
implementation of vertical axis wind turbine power generation technology for the production of clean, cost-efficient green energy on all U.S. Native American Indian reservations.
Since inception (2005), we have primarily been involved in the acquisition and management of Native American land and fee land acreage in Montana and Alaska and the exploration for, and development of, oil and natural gas properties which management believes have potential for improved production rates and resulting income by application of both conventional and non-conventional improvement and enhancement techniques, including horizontal drilling.
Our consolidated financial statements include the accounts, including our wholly owned subsidiaries, NAEG Alaska and NAEG Operations. All significant intercompany balances and transactions have been eliminated in consolidation.
To implement our current business plan, significant additional financing will be required and we will need to be successful in its efforts to identify, acquire and develop oil and gas reserves that are economically recoverable.
We are in the development stage as defined by Accounting Standards Codification subtopic 915-10 Development Stage Entities (“ASC 915-10”) with its efforts principally devoted to developing oil and gas reserves. To date, we have not generated sales revenues; have incurred expenses and sustained losses. Consequently, its operations are subject to all the risks inherent in the establishment of a new business enterprise. For the period from inception through December 31, 2012, the Company has accumulated losses of $31,331,949.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. In consultation with our Board of Directors, we have identified several accounting principles that we believe are key to the understanding of our financial statements. These important accounting policies require management’s most difficult, subjective judgments.
Property and Equipment
Property and equipment is recorded at cost. Depreciation of assets is provided by use of a straight line method over the estimated useful lives of the related assets. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred.
Undeveloped Oil and Gas Properties
Acquisition, exploration, and development of oil and gas activities are capitalized when costs are recoverable and directly result in an identifiable future benefit, following the full cost method of accounting. Improvements that increase capacity or extend the useful lives of assets are capitalized. Maintenance and turnaround costs are expensed as incurred.
Undeveloped oil and gas properties are assessed, at minimum annually or as economic events dictate, for potential impairment. Impairment is assessed by comparing the estimated net undiscounted future cash flows to the carrying value of the asset. If required, the impairment recorded is the amount by which the carrying value of the asset exceeds its fair value.
Capitalized costs are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves once determined by the independent petroleum engineers. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.
Costs of acquiring and evaluating unproved properties and major development projects are excluded from the depletion and depreciation calculation if and until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred.
Depletion and Amortization of Oil and Gas Properties
We follow the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of properties within a relatively large geopolitical cost center are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with our reserves. We capitalize internal costs directly identified with performing or managing acquisition, exploration, and development activities. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.
Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable cost center. We have assessed for impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool, less related deferred income taxes, should not exceed the following: (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves, plus (b) all costs being excluded from the amortization base, plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base, less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues should be based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test must take into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price should be consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. We did not have any hedging activities during the year ended December 31, 2012 and 2011. Application of the ceiling test is required for quarterly reporting purposes, and any write-downs cannot be reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.
During the years ended December 31, 2012 and 2011, our management performed an evaluation of its unproved properties for purposes of determining the implied fair value of the assets at the end of each respective year. The test indicated that the recorded remaining book value of its unproved properties exceeded its fair value for the years ended December 31, 2012 and 2011. As a result, upon completion of the assessment, management recorded a non-cash impairment charge of $-0-, net of tax, during the year ended December 31, 2012 and $690,552, net of tax, or $0.02 per share during the year ended December 31, 2011 to reduce the carrying value of the unproved properties to $-0-. Considerable management judgment is necessary to estimate the fair value. Accordingly, actual results could vary significantly from management’s estimates.
Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title passes from us to our petroleum or natural gas purchaser and collectability is reasonably assured. During the years ended December 31, 2012 and 2011, we received proceeds from the sale of oil from two wells on our sites in the amount of $41,831 and $111,606 respectively.
Income Taxes
We have adopted Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Temporary differences between taxable income reported for financial reporting purposes and income tax purposes are insignificant
Derivative Instruments and Fair Value of Financial Instruments
We have evaluated the application of Accounting Standards Codification 815-40, Derivatives and Hedging, Contracts in Entity’s Own Equity (“ASC 815-40”) to certain convertible debentures that contain exercise price adjustment features known as reset provisions, issued warrants with anti-dilutive provisions and an obligation it issue common shares under anti-dilutive provision in a settlement agreement . Based on the guidance in ASC 815-40, we have concluded these instruments and obligations are required to be accounted for as derivatives effective upon issuance.
We have recorded the fair value of the reset provisions of the convertible debentures and classified as derivative liabilities in our balance sheet at fair value with changes in the value of these derivatives reflected in the consolidated statements of operations as gain or loss on derivative liabilities. These derivative instruments are not designated as hedging instruments under ASC 815-10.
Net Loss per Share
We follow Accounting Standards Codification subtopic 260-10, Earnings Per Share (“ASC 260-10”), which specifies the computation, presentation and disclosure requirements of earnings per share information. Basic earnings per share have been calculated based upon the weighted average number of common shares outstanding. Our common stock equivalents, represented by convertible preferred stock and warrants, were not considered as including such would be anti-dilutive.
Results of Operations for the Twelve Months Ended December 31, 2012 and 2011
Revenues
During the years ended December 31, 2012 and 2011, we received proceeds from the sale of oil for test purposes from two wells on our sites in the amount of $26,702 and $111,606 respectively.
Operating Expenses
Selling, General and Administrative
Selling, general and administrative expenses decreased from $5,293,927 for the twelve months ended December 31, 2011 to $1,758,749 for the twelve months ended December 31, 2012. The decrease of $3,535,178 or 67% is primarily attributable to a decrease in equity based compensation to consultants and service providers of $2,751,192 along with a reduction in operations expenses due to funding constraints.
Impairment of undeveloped properties
Impairment of undeveloped properties in the current fiscal year decreased from $690,552 for the twelve months ended December 31, 2011 to $-0- for the twelve months ended December 31, 2012. This decrease of $690,552 is attributed to an reduced investments in our undeveloped properties.
Litigation Settlement
During the year ended December 31, 2012, we concluded litigation as described in our accompanying financial statements. As such, we incurred a $1,757,182 charge in the year ended December 31, 2012 comprised of additional shares of our common stock and an obligation to issue warrants based on certain conditions occurring. During the year ended December 31, 2011, we incurred costs of $247,438.
Depreciation and Amortization
In the twelve months ended December 31, 2012, depreciation and amortization decreased by $5,839 from $159,594 for the twelve months ended December 31, 2011 to $153,755 for the twelve months ended December 31, 2012. The decrease is attributable aging of our field equipment purchased in prior years.
Total Operating Expenses
Total operating expenses decreased to $3,669,686 for the year ended December 31, 2012 from $6,391,511 for the year ended December 31, 2011. The decrease of $2,721,825 is primarily attributable to a decrease in equity based compensation issued to consultants and services providers net with the settlement of litigation as described above.
Loss on change in fair value of derivative liabilities
During the year ended December 31, 2012, we issued convertible debentures with certain conversion features and entered into a settlement agreement requiring us to issue warrants and common stock with anti-dilution provisions, which we identified as embedded derivatives. All require us to fair value the derivatives each reporting period and mark to market as a non-cash adjustment to our current period operations. This resulted in a net loss of $149,965 for the year ended December 31, 2012, $-0- for the same period, last year.
Gain on settlement of debt
During the year ended December 31, 2012, we amended our previously acquired and expensed licensing agreement, reducing our remaining debt obligation from $469,500 to $69,500 realizing a gain from debt cancelation. In addition, we settled accounts payable, debt and related accrued interest by issuance of our common stock realizing a gain of $253,220. During the year ended December 31, 2011, we received notification of the cancellation of two vehicle notes from the financing company totaling $21,606; due to the cancellation of certain oil & gas leases, we were notified that certain lease payments totaling $25,698 were no longer payable; and a lender and a former consultant forgave a loan payable and an account payable, respectively, in the amount of $10,197 and $4,500. Accordingly, we recognized $62,002 included as gain on settlement of debt on the statement of operations.
Loss on Debt Modification
On October 26, 2012, we entered into a settlement agreement with our bridge note holders and High Capital Funding LLC, holder of $723,000 in matured notes payable. In connection with a forbearance on the security held, we agreed to issue common stock and warrants in conjunction with the settlement. In addition, we agreed to assume the legal costs incurred by the note holders. As such, we recorded the fair valve of the issued common, warrants and debt assumption as loss on debt modification of $426,980 for the year ended December 31, 2012.
Interest Expenses, net
Interest expense, net for the twelve months ended December 31, 2012 decreased by $38,218 to $511,943 from $69,374 for the twelve months ended December 31, 2011. The decrease in interest expense was due to issuing common shares in connection with our bridge financing charged to period interest in 2011.
Net (Loss)
Net loss for the twelve months ended December 31, 2012 decreased to $4,072,286 from a net loss of $6,767,737 for the twelve months ended December 31, 2011. The decrease of $2,695,451 is primarily attributable to the following factors: (i) a decrease in field operations expenses in our Montana field site and the Five-Well Program; (2) an decrease in equity based compensation to consultants and service providers; (iii) a decrease in the amount of impairment of undeveloped properties for the twelve months ended December 31, 2012 as compared to the twelve months ended December 31, 2011; (iv) gain on settlement of debt in 2012 of $653,220 and compared with $62,002 in 2011; (v) net with a loss on debt modification of $426,980 in 2012 as compared to nil in 2011 and a loss on change in fair value of derivatives of $149,965.
Liquidity, Capital Resources and Going Concern
We generated minimum revenues in the year ended December 31, 2012. We have continued to incur expenses and have limited sources of liquidity. Our limited financial resources have had an adverse impact on our liquidity, activities and operations. These limitations have also adversely affected our ability to obtain certain projects and pursue additional business ventures. We may have to borrow money from stockholders or issue debt or equity securities in order to find expenditures for exploitation and development and general administration or enter into a strategic arrangement with a third party. There can be no assurance that additional funds will be available to us on favorable terms or at all.
Our liquidity needs consist of our working capital requirements, indebtedness payments and property development expenditure funding. Historically, we have financed our operations through the sale of equity and debt, as well as borrowings from various credit sources, and we have adjusted our operations and development to our level of capitalization. On a going-forward basis, we anticipate that we may need approximately $250,000 to $350,000 annually to maintain our corporate existence and pay the expenses and costs that we likely will incur to ensure that we can remain a corporate enterprise with all of our attendant responsibilities, filings, and associated documentation.
As of December 31, 2012 we had a working capital deficit of $4,523,197. For the twelve months ended December 31, 2012, we generated a net cash flow deficit from operating activities of $529,723, consisting primarily of year to date loss of $4,072,286. Non cash adjustments included $153,755 in depreciation and amortization charges, $448,500 for equity based compensation, $27,901 amortization of debt discount, $426,980 loss on debt modification, $1,757,182 for fair value of common stock and warrants issued in litigation settlement, $87,514 non-cash interest paid, $149,965 for loss on change in fair value of derivative liabilities, $162,500 in fair value of vesting options and $185,306 for the fair value of warrants issued in connection with debt net with $663,220 gain on settlement of debt Additionally, we had a net decrease in assets of $64,455 and a net increase in current liabilities of $741,725. A net cash flow deficit from investing activities for the twelve months ended December 31, 2012 was nil. Cash provided by financing activities for the twelve months ended December 31, 2012 totaled $516,945, consisting of proceeds from the sale of our common stock and proceeds from loans and notes payable, net with repayments on loans and notes payable.
We expect that exploitation of potential revenue sources will be financed primarily through the private placement of securities, including issuance of notes payable and other debt or a combination thereof, depending upon the transaction size, market conditions and other factors.
While we have raised capital to meet our working capital and financing needs in the past, additional financing is required within the next three months in order to meet our current and projected cash flow deficits from operations and development. Our registered independent certified public accountants have stated in their report dated May 20, 2013, that we have incurred operating losses in the last year, and that we are dependent upon management’s ability to develop profitable operations and raise additional capital. These factors, among others, may raise substantial doubt about our ability to continue as a going concern.
We also are unable to determine whether we will generate sufficient cash flow from our future oil and gas operations to fund our future operations. Although we would expect cash flow from future operations to rise as our as we are able to improve our operations, post funding, and the number of projects we successfully develop grows, we will continue to focus, in the near term, on raising additional capital, probably through the private placement of equity securities, to assure we have the necessary liquidity for 2013.
We need to raise capital to fund the development of future wells. To the extent that additional capital is raised through the sale of equity or equity-related securities, the issuance of such securities would result in dilution of the existing stockholders’ shares. There can be no assurance that additional funding will be available on favorable terms, if at all. If adequate funds are not available within the next 12 months, we may be required to curtail our operations significantly or to obtain funds through entering into arrangements with collaborative partners or others that may require us to relinquish rights to certain of our assets that we would not otherwise relinquish.
Our long term viability depends on our ability to obtain adequate sources of debt or equity funding to meet current commitments and fund the continuation of our business operations, and our ability to ultimately achieve adequate profitability and cash flows from operations to sustain our operations.
Impact of Default
As we disclosed in our financial statements, our notes, loan payables and operating lease obligations are currently in default.
Notes and loans payable are being resolved through debt-to-equity conversion agreements. We plan to resolve our operating lease obligations by the future commencement of production, or by additional equity financing or debt financing.
Default on lease obligations could result in the impairment of our ability to conduct executive functions, which would be the case if we lost the New York executive office space. The loss any of our oil and gas leases will likely result in the curtailment of potential oil and gas production revenues to us. There are no other known alternative sources of funding to pay off or replace these obligations.
Going Concern
Our financial statements have been presented on the basis that we continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As shown in the accompanying financial statements, we incurred a net operating loss in the years ended December 31, 2012, 2011, 2010, 2009 and 2008, and have minimum revenues at this time. These factors create an uncertainty about our ability to continue as a going concern. We are currently trying to raise capital through a private offering of our stock. Our ability to continue as a going concern is dependent on the success of this plan. The financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.
Material Commitments
Among other debts, as of December 31, 2012, we owed:
·
Bridge Notes Payable of an aggregate of $750,000, that are secured by a first lien on certain oil and gas leases and related equipment and are already past due and are currently accruing interest at the rate of 12.00% per year as of November 1, 2012, increasing to 18% by May 1, 2014. On October 26, 2012, we entered into a settlement agreement and in connection with a forbearance not to exercise their security rights, we agreed to term modifications, issued warrants and common stock with anti-dilutive provisions and settled on payment terms based on future well production
·
Loans payable of an aggregate of $593,000, under the Loan Terms Agreement that are secured by a second lien on certain oil and gas leases and related equipment, bear interest at the rate of 6.25% per year and were due on February 29, 2012; these loans were part of the October 26, 2012 settlement.
·
SLA Notes payable of $130,000, under the Third Secured Loan Agreement that are secured by (i) a second lien pari pasu with the secured loans under the Loan Term Agreement and (ii) bear interest at the rate of 12% per year until February 29, 2012, at the rate of 15% per year until April 30, 2012, and at the rate of 18% per year after April 30, 2012, and that are due the earlier of (i) April 30, 2012; and (ii) the final closing of any equity and/or debt financing totaling at least $3,000,000 which occurs after December 31, 2011. These loans were part of the October 26, 2012 settlement
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, or result in changes in financial condition, revenues or expenses, results or operations, liquidity, capital expenditures or capital resources that is material to investors.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
We are a smaller reporting company as defined by Rule 12b-2 of the Securities Exchange Act of 1934 and are not required to provide the information under this item.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Our financial statements, together with the report of our independent registered public accounting firm, are contained in pages through which appear at the end of this Annual 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
Our management is responsible for establishing and maintaining disclosure controls and procedures that are designed to ensure that material information required to be disclosed in our periodic reports filed under the Securities Exchange Act of 1934, as amended (the “1934 Act”), is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to ensure that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure. We carried out an evaluation, under the supervision and with the participation of our management, including the principal executive officer and the principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2012. Based on this evaluation, and because of our limited resources and limited number of employees, management concluded that our disclosure controls and procedures were ineffective as of December 31, 2012.
Management’s Report on Internal Control over Financial Reporting
Our management is also responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurances regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.
Our Chief Executive Officer and Chief Financial Officer conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on our evaluation and the material weaknesses described below, our management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2012 based on the COSO framework criteria. Management has identified control deficiencies regarding the lack of segregation of duties and the need for a stronger internal control environment. These control deficiencies could result in a misstatement of account balances that would result in a reasonable possibility that a material misstatement to our consolidated financial statements may not be prevented or detected on a timely basis, and thus are a material weakness. Our management believes that these material weaknesses are due to the small size of our accounting staff due to financial restrictions. As we grow and obtain financing, we expect to increase our number of employees, which will enable us to implement adequate segregation of duties within the internal control framework.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, during the fourth fiscal quarter of December 31, 2012 that has materially affected, or is 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, Executive Offices and Corporate Governance.
Directors and Executive Officers
The following table and text sets forth the names and ages of all our directors and executive officers and our key management personnel as of December 31, 2012. All of our directors serve until the next annual meeting of stockholders and until their successors are elected and qualified, or until their earlier death, retirement, resignation or removal. Executive officers serve at the discretion of the Board of Directors, and are elected or appointed to serve until the next Board of Directors meeting following the annual meeting of stockholders. Also provided is a brief description of the business experience of each director and executive officer and the key management personnel during the past five years and an indication of directorships held by each director in other companies subject to the reporting requirements under the Federal securities laws.
Following is a brief summary of the background and experience of each director and executive officer of our Company:
Joseph G. D’Arrigo. Mr. D’Arrigo has served as our President, Chief Executive Officer and Chairman since our formation in January 2005. Since our inception, he has been responsible for guiding us through all aspects of our early stage development, including capital formation, project assessments, lease acquisitions, and tribal employment policy. In addition to his services as our officer and director, Mr. D’Arrigo has served as President, Chief Executive Officer and sole director of our subsidiary, NAEG Alaska Corporation (formerly Fowler Oil and Gas Corporation) since May 2009. Concurrently, he has served as President and director of Founders since our formation in April 2005. In November 2011, he was appointed as President and director of NEDC.
Raj S. Nanvaan. Mr. Nanvaan has served as our Chief Financial Officer, Vice President, Treasurer, and director since our formation in January 2005. He resigned from his position as our Corporate Secretary in July 2009 and was appointed Chief Operating Officer on that date. Concurrent with his services as our officer and director, Mr. Nanvaan has served as Secretary, Treasurer and director of Founders since our formation in April 2005. He resigned as Secretary of Founders in September 2010. In November 2011, he was appointed as Vice President, Treasurer and director of NEDC.
Richard Ross. Mr. Ross has served as our Chief Communications Officer in charge of Investor Relations since February 2005 and as Assistant Corporate Secretary from February 2005 through July 2009, when he was promoted to Corporate Secretary. Mr. Ross has served on our Board since December 2009. In addition to his services as our officer and director, he has served as Secretary and a member of the board of directors of Founders since September 2010. In November 2011, Mr. Ross was appointed as Corporate Secretary and director of NEDC.
Doyle A. Johnson. Mr. Johnson has provided consulting services to us since February 2005 through December 2008, and was appointed our Chief Geologist & Petroleum Engineer in July 2010. He is a third-generation oil and gas professional with over 35 years of oilfield exploration, production and engineering experience. Mr. Johnson has worked on over 5,000 oil & gas wells and has a good safety record. He has successfully managed operations in the most sensitive of natural areas and has established a good reputation in the industry.
Linda C. Chontos. Mrs. Chontos has advised our executives since 2005 on certain initiatives on a complimentary basis. She is credited for introducing us to certain relationships within the state of Alaska and has continued to help us cultivate and preserve certain key relationships in Alaska related to its Coal Bed Methane development initiative. On June 1, 2011, she was appointed as our Administrative Operations Officer. From March 2005 through June 2011, Mrs. Chontos previously served as the President of United Consultants, Inc. where she advised development stage companies on business development and administrative operations.
Family Relationships.
There are no family relationships between any of our directors or executive officers.
Involvement in Certain Legal Proceedings.
There have been no events under any bankruptcy act, any criminal proceedings or any judgments, injunctions, orders or decrees material to the evaluation of the ability and integrity of any director, executive officer, promoter or control person during the past ten years except as follows:
From February 1, 1998 to June 1, 1998, Raj S. Nanvaan, at the age of 20, was employed as a General Securities Representative by Renaissance Capital Management, Inc., a brokerage firm, the principal owners / officers of which were later criminally prosecuted for selling unregistered securities. While employed by such brokerage firm for such 5 month period, Mr. Nanvaan received compensation for normal brokerage commissions by the principals from an account that was used from October 1997 to March 1999. Mr. Nanvaan subsequently decided to leave the firm to become a Securities Compliance Manager by taking the Series 24 exam and established his own securities brokerage firm. Nearly two years later, in March 2000, Mr. Nanvaan was notified by the Securities and Exchange Commission (“SEC”) of a civil lawsuit whereby the SEC was seeking an injunctive action against several registered representatives who worked at Renaissance during the period from October 1997 to March 1999 for inducing investors to invest in a soon to be defunct corporation, making false representations regarding such corporation’s IPO and negligently or recklessly distributing materials containing misstatements and omissions. Mr. Nanvaan’s five month employment with Renaissance fell within such period.
Subsequently, the SEC charged the five individuals named in the complaint, which included Mr. Nanvaan, for violations of Sections 5 and 17(a) of the Securities Act of 1933, as amended (the “Securities Act”) and Section 10(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). On March 29, 2003, the district court in an administrative proceeding granted the SEC’s application to permanently enjoin each of the remaining securities representatives, including Mr. Nanvaan, from future violations of Sections 5(a), 5(c), and 17(a) of the Securities Act and Section 10(b) of the Exchange Act, and Rule 10b-5 promulgated thereunder. On October 31, 2003, Mr. Nanvaan was ordered to return $10,000 plus $4,273.26 in pre-judgment interest and pay a civil penalty of $10,000. In June 2005, the SEC and Mr. Nanvaan agreed to a settlement whereby Mr. Nanvaan neither admitted nor denied the findings of the Commission. As part of the settlement, the SEC imposed remedial sanctions pursuant to Section 15(b)(6) of the Exchange Act, barring Mr. Nanvaan from having any association with any broker or dealer. None of the above sanctions prohibit Mr. Nanvaan from being employed as an officer or director of a public or private company.
Since the year 2000, Mr. Nanvaan has not been associated with a broker or dealer or been involved in the securities industry. Since 2001, he has been actively involved in the energy industry. Since 2005, he has been employed by Native American Energy Group, Inc. He has at all times been in full compliance with the above administrative order.
Section 16(a) Beneficial Ownership Reporting Compliance.
Section 16 (a) of the Securities Exchange Act of 1934, as amended, requires our directors and officers, and persons who own more than ten percent (10%) of the our common stock, to file with the Securities and Exchange Commission reports of ownership on Form 3 and reports of change in ownership on Forms 4 and 5. Such officers, directors and ten-percent stockholders are also required to furnish us with copies of all Section 16(a) reports they file. Based solely on its review of the copies of such forms received by us and on written representations from certain reporting persons, we believe that all Section 16(a) reports applicable to its officers, directors and ten-percent stockholders with respect to the fiscal year ended December 31, 2012 were filed timely.
Code of Ethics
The Board of Directors adopted a Code of Business Conduct and Ethics (“Code of Ethics”) on May 3, 2011. The Code of Ethics is applicable to our employees, officers and directors, including the principal executive officer, the principal financial officer and the principal accounting officer. The Code of Ethics is posted and available on the Corporate section of our website, http://www.nativeamericanenergy.com, under Governance. Information on our website is not incorporated by reference in this Annual Report on Form 10-K.
Board of Directors
Our board currently consists of three directors. There have been no material changes to the procedures by which security holders may recommend nominees to the board of directors.
Audit Committee Financial Expert
The Board of Directors has not established any committees and acts as our Audit Committee. We have no qualified financial expert at this time because it has not been able to identify a qualified candidate. We intend to continue to search for a qualified individual for hire.
Item 11.
Item 11. Executive Compensation.
Summary Compensation Table
The following table sets forth all compensation earned for services rendered to us in all capacities for the fiscal years ended December 31, 2012 and 2011, by our principal executive officer, principal financial officer, and three of our other executive officers who served in such capacities as of the end of fiscal 2012, collectively referred to as the “Named Executive Officers.”
(1) In September 2011, we implemented a payroll system with Automatic Data Processing, Inc. (ADP), a company that provides payroll services for businesses. The payroll system was setup in anticipation of funding that was expected to be received, whereby we could begin paying salaries to its employees. We had never had a payroll system in place since our inception. During the payroll system and direct deposit setup process, three of our officers received $1,000 each for their services provided as an initial test of the payroll system and its initiation process.
(2) On June 1, 2011, Linda C. Chontos was appointed as our Administrative Operations Officer.
(3) On September 14, 2012, the Board of Directors granted 2,000,000 common stock options each to Mr. D’Arrigo and Mr. Nanvaan. The options are exercisable at $2.00 for five years with vesting in four year increments beginning the first anniversary. In addition, on September 14, 2012, the Board of Directors granted 2,000,000 common stock options each to Mr. Ross, Mr. Johnson and Ms. Chontos. The options are exercisable at $0.20 for ten years with vesting in four year increments beginning the first anniversary.
(4) Beginning October 1, 2012, the Company began accruing salaries for its five (5) employees in accordance with employment agreements executed on September 14, 2012. Each employee receives an annual salary of $48,000 at the rate of $4,000 per month. Currently the salaries are currently being deferred until the company is in a financial position to pay such salaries.
Members of the Board do not receive compensation but are entitled to reimbursement of their expenses incurred in attending Board meetings.
Employment Contracts
The Company has no pension, annuity, insurance, profit sharing or similar benefit plans; however, the Company may adopt such plans in the near future. On September 14, 2012, the Company entered into employment agreements with Joseph G. D’Arrigo, Raj S. Nanvaan, Richard Ross, Doyle A. Johnson and Linda C. Chontos. All Executives’ salaries are being deferred until sufficient capital is available.
Mr. D’Arrigo's agreement is for a period of 5 years and provides for payment of $48,000 annually in exchange for Mr. D’Arrigo's services as President and Chief Executive Officer of the Company. The Company will defer payment of Mr. D’Arrigo's base salary until sufficient capital is available.
Mr. Nanvaan's agreement is also for a period of 5 years and provides for payment of $48,000 annually in exchange for Mr. Nanvaan 's services as Chief Financial & Operations Officer of the Company. The Company will defer payment of Mr. Nanvaan's base salary until sufficient capital is available.
Mr. Ross’ agreement is also for a period of 5 years and provides for payment of $48,000 annually in exchange for Mr. Ross' services as Chief Communications Officer and Corporate Secretary of the Company. The Company will defer payment of Mr. Ross' base salary until sufficient capital is available.
Mr. Johnson’s agreement is also for a period of 5 years and provides for payment of $48,000 annually in exchange for Mr. Johnson’s services as Chief Geologist and Petroleum Engineer of the Company. The Company will defer payment of Mr. Johnson's base salary until sufficient capital is available.
Ms. Chontos’ agreement is also for a period of 5 years and provides for payment of $48,000 annually in exchange for Ms. Chontos' services as Administrative Operations Officer of the Company. The Company will defer payment of Mr. Chontos' base salary until sufficient capital is available.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth, as of May 20, 2013 the number of shares of (i) Common Stock and (ii) Series A Stock owned of record and beneficially by our current executive officers, directors and persons who hold 5% or more of the outstanding shares of Common Stock and Series A Stock, respectively, of us, and all of our current directors and executive officers as a group. Amounts reported under “Common Stock Beneficially Owned” includes the number of shares that could be acquired through the conversion of Series A Stock within 60 calendar days of this date. Except as otherwise indicated and subject to applicable community property laws, each owner has sole voting and investment power with respect to the securities listed. Further, unless otherwise indicated, each director’s, officer’s and beneficial owner’s address is c/o Native American Energy Group, Inc., 61-43 186th Street Suite 507 Fresh Meadows NY 11365.
(1)
Based on 40,522,018 shares of Common Stock outstanding as of May 20, 2013. Under Rule 13d-3(d) of the Exchange Act, shares not outstanding which are subject to options, warrants, rights or conversion privileges exercisable within 60 days are deemed outstanding for the purpose of calculating the number and percentage owned by such person, but are not deemed outstanding for the purpose of calculating the percentage owned by each other person listed.
(2)
Based on 500,000 shares of Series A Stock issued and outstanding as of May 20, 2013.
(3)
Includes 250,000 shares of Common Stock issuable upon conversion of Series A Stock issued to Mr. D’Arrigo on a one share of Series A Stock for one share of Common Stock basis. All such shares of Series A Stock are convertible as of the date of this Information Statement.
(4)
Each of Joseph G. D’Arrigo and Raj S. Nanvaan are the beneficial owners of 250,000 shares of Series A Stock, which have super-voting rights on the basis of 1,000 votes for each 1 share of Series A Stock. Therefore, each has 250,000,000 votes for the Voting Shares held by them, in addition to 5,045,751 votes for the 5,045,741 shares of Common Stock held by them.
(5)
Includes 250,000 shares of Common Stock issuable upon conversion of Series A Stock issued to Mr. Nanvaan on a one share of Series A Stock for one share of Common Stock basis. All such shares of Series A Stock are convertible as of the date of this Information Statement.
(6)
Includes 2,522,655 warrants which are exercisable within 60 days of May 20, 2013 but which may not be exercised to the extent such exercise would result in HCF beneficially owning more than 9.95% of NAGP common stock at any given time. As such, all 2,522,655 warrants are exercisable as of the Record Date.
Outstanding Equity Awards at May 20, 2013
The following table summarizes certain information regarding unexercised stock options outstanding for each of the Named Officers as of May 20, 2013.
The Company does not currently have in place or provide retirement, disability or other benefits to its employees.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
As of December 31, 2012, Joseph D’Arrigo has a loan outstanding to us of $10,550, and Raj Nanvaan has a loan outstanding to us of $36,418. These loans are included in our loans payable and were made interest free. There is no benefit to either Mr. D’Arrigo or Mr. Nanvaan directly or indirectly from providing such loans.
In addition to being officers and directors of Native American Energy Group, Inc., Joseph D’Arrigo, our President, Chief Executive Officer and Chairman, and Raj Nanvaan, our Chief Financial Officer, Chief Operations Officer, Vice President, Treasurer and Director, are directors and minority shareholders of NAEG Founders Holding Corporation, a private New York corporation that Messrs. D’Arrigo and Nanvaan formed to hold (i) Mr. D’Arrigo’s 2.5% Overriding Royalty interest in our future oil & gas production and (ii) Mr. Nanvaan’s 2.5% Overriding Royalty interest in our future oil & gas production. After the transfer of such interests to NAEG Founders Holding Corporation, Messrs. D’Arrigo and Nanvaan each had a remaining 0.5% Overriding Royalty interest in our future oil & gas production, which they voluntarily cancelled for no consideration. As the result of the assignment of the interests of both Messrs. D’Arrigo and Nanvaan to NAEG Founders Holding Corporation by way of a board resolution, NAEG Founders Holding Corporation held a total 5% Overriding Royalty Interest in the future oil & gas production from leasehold interests. As background, Messrs. D’Arrigo and Nanvaan had each been granted their respective 3% Overriding Royalty Interest in our future oil & gas production in exchange for the assignment of their respective interests in a drilling project associated with another company called Rockwell Petroleum. The project was called the Jones Draw Field. Such rights were acquired by them before our organization while working with other oil & gas companies as tribal liaisons prior to the formation of the Company. To date, Messrs. D’Arrigo and Nanvaan have not received any compensation or dividend distributions from NAEG Founders Holdings Corporation because such company has not had any commercial production to date.
In October 2011, we acquired a vehicle for a down payment of $12,000 towards the total purchase price of $29,500. For credit purposes only, the vehicle's title and related loan were issued in the name of our president. Upon settlement of the outstanding loan, the vehicle's ownership will be transferred to our name. For accounting purposes, the vehicle and related loan are recorded as part of our financial statements as assets and obligations, respectively.
In January 2013, Richard Ross loaned the company $18,950. The loan was made interest free. There is no benefit to Mr. Ross directly or indirectly from providing such loans.
Item 14.
Item 14. Principal Accountant Fees and Services.
Summary of Principal Accountant Fees for Professional Services Rendered
The following table presents the aggregate fees for professional audit services and other services rendered by Kalantry, LLP in 2012 and 2011:
(1)
Includes fees paid to Kalantry LLP are for reviews of the financial statements of our quarterly reports on Form 10-Q.
All services described above were approved by the Board.
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) The following documents are filed as part of this report:
1. Financial Statements.
Our consolidated financial statements are filed as a part of this Annual Report on Form 10-K.
2. Financial Statement Schedules.
All financial statement schedules have been omitted, since the required information is not applicable or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto.
3. Exhibits
The information required by this Item is set forth on the Exhibit Index that follows the financial statements at the end of this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NATIVE AMERICAN ENERGY GROUP, INC.
Dated: May 20, 2013
By:
/s/ Joseph G. D’Arrigo
Name: Joseph G. D’Arrigo
Title: President & Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons of the Registrant and in the capacities and on the dates indicated:
KALANTRY LLP
CERTIFIED PUBLIC ACCOUNTANTS
70-26 Groton Street Forest Hills NY 11375
Tel (718) 544 2772 | Fax (267) 295 8501
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Native American Energy Group Inc.
Fresh Meadows, New York
We have audited the accompanying consolidated balance sheets of Native American Energy Group, Inc. (the “Company”), a development stage company as of December 31, 2012 and 2011 and the related consolidated statements of operations, changes in stockholders’ equity 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 audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Native American Energy Group, Inc. as of December 31, 2012 and 2011 and the consolidated results of operations, changes in stockholders’ equity and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the accompanying consolidated financial statements, the Company has suffered recurring losses from operations and does not have sufficient cash or working capital to meet anticipated requirements through 2013. This raises substantial doubt about the Company's ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ Kalantry LLP
Forest Hills, New York
May 20, 2013
See the accompanying notes to the consolidated financial statements
See the accompanying notes to the consolidated financial statements
See the accompanying notes to the consolidated financial statements
See the accompanying notes to the consolidated financial statements
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies applied in the presentation of the accompanying financial statements follows:
Business and Basis of Presentation
The registrant, Native American Energy Group, Inc. (the “Company”), formerly Flight Management International, Inc. was incorporated under the laws of the State of Delaware on November 1, 1996. The Company leases and revitalizes oil fields which were previously developed using enhanced oil recovery capabilities. The oil and natural gas fields are owned by individual land owners and located on native and non-native American lands in the State of Montana and Alaska.
The consolidated financial statements include the accounts of the Company, including our wholly owned subsidiaries, NAEG Alaska Corporation (“NAEG Alaska”), a Delaware corporation incorporated in 2005 that was formerly known as Fowler Oil & Gas Corporation and NAEG CBM Operations LLC (“NAEG Operations”), an Alaskan limited liability company formed in August 2006 that was formerly known as Fowler Oil & Gas Alaska. All significant intercompany balances and transactions have been eliminated in consolidation.
To implement its current business plan, significant additional financing will be required and the Company will need to be successful in its efforts to identify, acquire and develop oil and gas reserves that are economically recoverable.
The Company is in the development stage as defined by Accounting Standards Codification subtopic 915-10 Development Stage Entities (“ASC 915-10”) with its efforts principally devoted to developing oil and gas reserves. To date, the Company, has not generated sales revenues, has incurred expenses and has sustained losses. Consequently, its operations are subject to all the risks inherent in the establishment of a new business enterprise. For the period from inception through December 31, 2012, the Company has accumulated losses of $31,347,079.
Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Property and Equipment
Property and equipment is recorded at cost. Depreciation of assets is provided by use of a straight line method over the estimated useful lives of the related assets. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred.
Undeveloped Oil and Gas Properties
Acquisition, exploration, and development of oil and gas activities are capitalized when costs are recoverable and directly result in an identifiable future benefit, following the full cost method of accounting. Improvements that increase capacity or extend the useful lives of assets are capitalized. Maintenance and turnaround costs are expensed as incurred.
Undeveloped oil and gas properties are assessed, at minimum annually or as economic events dictate, for potential impairment. Impairment is assessed by comparing the estimated net undiscounted future cash flows to the carrying value of the asset. If required, the impairment recorded is the amount by which the carrying value of the asset exceeds its fair value.
Capitalized costs are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves once determined by the independent petroleum engineers. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.
Costs of acquiring and evaluating unproved properties and major development projects are excluded from the depletion and depreciation calculation if and until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred.
Depletion and Amortization of Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of properties within a relatively large geopolitical cost center are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration, and development activities. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.
Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable cost center. The Company has assesses for impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool, less related deferred income taxes, should not exceed the following: (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves, plus (b) all costs being excluded from the amortization base, plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base, less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues should be based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test must take into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price should be consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities during the year ended December 31, 2012 and 2011. Application of the ceiling test is required for quarterly reporting purposes, and any write-downs cannot be reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.
During the years ended December 31, 2012 and 2011, the Company management performed an evaluation of its unproved properties for purposes of determining the implied fair value of the assets at the end of each respective year. The test indicated that the recorded remaining book value of its unproved properties exceeded its fair value for the year ended December 31, 2011. As a result, upon completion of the assessment, management recorded a non-cash impairment charge of $690,552, net of tax, or $0.02 per share during the year ended December 31, 2011 to reduce the carrying value of the unproved properties to $-0-. Considerable management judgment is necessary to estimate the fair value. Accordingly, actual results could vary significantly from management’s estimates.
Intangible assets
The Company accounts for and reports acquired goodwill and other intangible assets under Accounting Standards Codification subtopic 305-10, Intangibles, Goodwill and Other (“ASC 305-10”). In accordance with ASC 305-10, the Company tests its intangible assets for impairment on an annual basis and when there is reason to suspect that their values have been diminished or impaired. Any write-downs will be included in results from operations.
In March 2010, the Company executed an amendment to their original agreement with Windaus Energy Inc. (of Canada), whereby the Company acquired manufacturing, marketing, sales, sublicensing and distribution rights to bring to the U.S. market Windaus’ Vertical Axis Wind Turbine Energy Systems.
During the year ended December 31, 2010, the Company management performed an evaluation of its licensing agreement for purposes of determining the implied fair value of the asset at December 31, 2010. The test indicated that the recorded remaining book value of its licensing agreement exceeded its fair value for the year ended December 31, 2010. As a result, upon completion of the assessment, management recorded a non-cash impairment charge of $2,500,000, net of tax, or $0.13 per share during the year ended December 31, 2010 to reduce the carrying value of licensing agreement to $-0-. Considerable management judgment is necessary to estimate the fair value. Accordingly, actual results could vary significantly from management’s estimates.
Asset Retirement Obligations
The Company accounts for reclamation costs under the provisions of Accounting Standards Codification subtopic 410-20, Asset Retirement and Environmental Obligations, Asset Retirement Obligations (“ASC 410-20”). ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Specifically, the statement requires that retirement obligations be recognized when they are incurred and displayed as liabilities with the initial measurement being at the present value of estimated third party costs. In addition, the asset retirement cost is capitalized as part of the assets’ carrying value and subsequently allocated to expense over the assets’ useful lives. There are no changes in the carrying amounts of the asset retirement obligations as no expenses have yet been incurred.
The Company is obligated to maintain a surety bond in conjunction with certain acquired leases. Our obligation for site reclamation does not become a liability until production begins.
Comprehensive Income
The Company does not have any items of comprehensive income in any of the periods presented.
Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title passes from the Company to its petroleum or natural gas purchaser and collectability is reasonably assured.
Stock-based compensation
The Company accounts for its stock based awards in accordance with Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”), which requires a fair value measurement and recognition of compensation expense for all share-based payment awards made to its employees and directors, including employee stock options and restricted stock awards. The Company estimates the fair value of stock options granted using the Black-Scholes valuation model. This model requires the Company to make estimates and assumptions including, among other things, estimates regarding the length of time an employee will retain vested stock options before exercising them, the estimated volatility of our common stock price and the number of options that will be forfeited prior to vesting. The fair value is then amortized on a straight-line basis over the requisite service periods of the awards, which is generally the vesting period. Changes in these estimates and assumptions can materially affect the determination of the fair value of stock-based compensation and consequently, the related amount recognized in the Company’s statements of operations.
Total stock-based compensation expense for the years ended December 31, 2012 and 2011 amounted to $162,500 and $-0-, respectively.
Derivative financial instruments
Accounting Standards Codification subtopic 815-40, Derivatives and Hedging, Contracts in Entity’s own Equity (“ASC 815-40”) became effective for the Company on October 1, 2009. The Company’s convertible debt can be convertible into the Company’s common shares, at the holder’s option, at the conversion rates of 50% discount to the lowest bid price of the Company’s common shares during the ten-day period ending one trading day prior to the date of the conversion. In addition, the Company entered into a settlement agreement with certain note holders requiring the issuance of warrants and common stock with anti-dilutive provisions.
Fair Value of Financial Instruments
Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2012 and 2011. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash and accounts payable. Fair values were assumed to approximate carrying values for cash and payables because they are short term in nature and their carrying amounts approximate fair values or they are payable on demand.
Advertising Costs
The Company expenses advertising costs as incurred. Advertising expenses are $-0- for the years ended December 31, 2012, 2011 and from January 18, 2005 (date of inception) through December 31, 2012.
Income Taxes
The Company has adopted Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Temporary differences between taxable income reported for financial reporting purposes and income tax purposes are insignificant.
At December 31, 2012, the significant components of the deferred tax assets (liabilities) are summarized below:
Net Loss per Share
The Company follows Accounting Standards Codification subtopic 260-10, Earnings Per Share (“ASC 260-10”), which specifies the computation, presentation and disclosure requirements of earnings per share information. Basic earnings per share have been calculated based upon the weighted average number of common shares outstanding. The Company’s common stock equivalents, represented by convertible debt, convertible preferred stock, options and warrants, were not considered as including such would be anti-dilutive for the years ended December 31, 2012 and 2011.
Reliance on Key Personnel and Consultants
The Company has five full-time employees who are executive officers and no part-time employees. The Company’s officers do not receive any payroll and their assistance is now being provided on an expense reimbursement basis. This situation will remain constant until such time as the Company has sufficient capital to afford to pay salaries. Additionally, there are outside consultants performing various specialized services. The Company is heavily dependent on the continued active participation of these current executive officers, employees and key consultants. The loss of any of the senior management or key consultants could significantly and negatively impact the business of the Company until adequate replacements can be identified and put in place.
Concentrations of Credit Risk
The Company’s cash is exposed to a concentration of credit risk. Effective December 31, 2010 and extending through December 31, 2012, all non-interest-bearing transaction accounts are fully insured by the Federal Deposit Insurance Corporation (FDIC), regardless of the balance of the account. Generally, the Company’s cash and cash equivalents in interest-bearing accounts may exceed FDIC insurance limits. The financial stability of these institutions is periodically reviewed by senior management.
Reclassification
Certain reclassifications have been made in prior year’s financial statements to conform to classifications used in the current year.
Recent Accounting Pronouncements
There were various updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
NOTE 2 - GOING CONCERN MATTERS
The Company has incurred a net loss of $4,072,286 and $6,767,737 for the years ended December 31, 2012 and 2011, respectively. The Company has incurred significant losses and has an accumulated deficit of $31,331,949 at December 31, 2012. These factors raised substantial doubt about the Company’s ability to continue as a going concern.
There can be no assurance that sufficient funds will be generated during the next twelve months or thereafter from the Company’s current operations, or those funds will be available from external sources such as debt or equity financings or other potential sources. The lack of additional capital could force the Company to curtail or cease operations and would, therefore, have a material adverse effect on its business. Furthermore, there can be no assurance that any such required funds, if available, will be available on attractive terms or that they will not have a significant dilutive effect on the Company’s existing stockholders.
The accompanying financial statements do not include any adjustments related to the recoverability or classification of asset-carrying amounts or the amounts and classifications of liabilities that may result should the Company be unable to continue as a going concern.
NOTE 3 - OIL AND GAS PROPERTIES, UNEVALUATED
Unevaluated and Unproved properties are comprised of acquired leases on Native American tribal lands and non-native lands in the states of Montana and Alaska. All properties are in development stage with unproven and unevaluated reserves.
NOTE 4 - PROPERTY AND EQUIPMENT
Property and equipment are comprised of the following:
Depreciation is recorded ratably over the estimated useful lives of five to ten years. Depreciation expense was $153,755 and $159,594 for the year ended December 31, 2012 and 2011, respectively and $673,072 from January 18, 2005 (date of inception) through December 31, 2012 respectively.
In October 2011, we acquired a vehicle for a down payment of $12,000 towards the total purchase price of $29,500. For credit purposes only, the vehicle's title and related loan were issued in the name of our president. Upon settlement of the outstanding loan, the vehicle's ownership will be transferred to our name. For accounting purposes, the vehicle and related loan are recorded as part of our financial statements as assets and obligations, respectively.
NOTE 5 - SURETY BONDS
The Company has an aggregate of $175,381 and $175,030, as of December 31, 2012 and 2011, respectively, deposited in a financial institution as collateral for posted surety bonds with various governmental agencies as assurance for possible well-site reclamation, if required. The Company is obligated to maintain a surety bond in conjunction with certain acquired leases. Our obligation for site reclamation does not become a liability until production begins.
NOTE 6 - SECURITY DEPOSITS
The Company had an aggregate of -0- and $50,000 as of December 31, 2012 and 2011, respectively, deposited in two financial institutions as collateral for posted surety bonds with various governmental agencies in Alaska and Montana as assurance for possible well-site reclamation, if required. The Company is obligated to maintain a surety bond in conjunction with certain drilling permits. In March 2011 and in September 2012, the Company cancelled two of its oil and gas surety bonds in the aggregate amount $150,000 issued to the Alaska Oil & Gas Conservation Commission (“AOGCC”) and the Matanuska-Susitna Borough Planning Commission (“Mat-Su Borough”) for its Kircher Unit state and borough drilling permits in Alaska. As a result of the bond terminations, the financial institution returned the $150,000 cash collateral to the Company. In the event that the Company re-applies for the state and borough drilling permits with the AOGCC and the Mat-Su Borough, it will be required to re-post bonds in the amount of $100,000 and $50,000, respectively. During the year ended December 31, 2011, the Company forfeited an $8,590 deposit held as security for its corporate office lease in New York.
NOTE 7 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses are comprised of the following:
During the year ended December 31, 2012, the Company issued an aggregate of 281,650 shares of its common stock in settlement of $50,000 of notes payable and $387,100 of accounts payable and accrued interest recognizing a gain on settlement of debt of $253,220.
NOTE 8 - PUT LIABILITY
On June 28, 2011, the Company offered to certain purchasers of the Company’s common stock the right to rescind their previous common stock acquisitions and receive in exchange for any shares relinquished to the Company a payment equal to their original purchase price plus interest at the applicable statutory rate in the state they reside. The common stock subject to the rescission offers total 2,732,500 common shares and were sold in 2010 and 2011 at prices ranging from $0.08 to $0.10 per share. The rescission offer expired at 5:00 pm (EDT) on August 1, 2011.
On August 1, 2011, we received one acceptance of the rescission offer in the amount of 1,125,000 shares for the return of $100,000. Accordingly, the Company reclassified $100,000 from equity to a put liability as of June 30, 2011.
During the year ended December 31, 2012, the right or rescission as described above expired. Accordingly, the Company reclassified $100,000 from put liability to equity.
NOTE 9 - CONVERTIBLE DEBENTURES
On September 21, 2012, the Company issued two $25,000 Convertible Debenture Notes that mature on March 21, 2013 (“Six Month Anniversary”). The notes bear interest at a rate of 8%. At any time after the six month anniversary of the Original Issue Date until the Debenture is no longer outstanding, the Debenture shall be convertible, in whole or in part, into shares of Common Stock at the option of holder, subject to certain conversion limitations set forth in the Debenture, at the conversion rate of 50% of the lowest daily bid price for 10 days prior to notice of conversion.
The Company identified embedded derivatives related to the Convertible Debentures entered into on September 21, 2012. These embedded derivatives included certain conversion features. The accounting treatment of derivative financial instruments requires that the Company record the fair value of the derivatives as of the inception date of the Convertible Promissory Notes and to adjust the fair value as of each subsequent balance sheet date. At the inception of the Convertible Debentures, the Company determined a fair value of $90,858 of the embedded derivative. The fair value of the embedded derivative was determined using the Binomial Lattice Model based on the following assumptions:
The initial fair value of the embedded debt derivative of $90,858 was allocated as a debt discount up to the proceeds of the notes ($50,000) with the remainder ($40,858) charged to current period operations as interest expense.
During the year ended December 31, 2012, the Company amortized $27,901 to current period operations as interest expense.
NOTE 10 - CAPITAL LEASES AND NOTES PAYABLE
Notes payable are comprised of the following:
During the year ended December 31, 2011, the Company was notified by the lender that it will not be held responsible for an installment loan previously in default of $10,109 including accrued interest of $6,703 Accordingly, the Company recorded a gain on settlement of debt of $16,812.
During the year ended December 31, 2012, the Company amended a previously acquired licensing agreement with no remaining carrying value whereby the remaining debt obligation was reduced from $469,500 to $69,500. Accordingly, the Company recognized a gain on settlement of debt of $400,000 to current period operations.
NOTE 11 - LOANS PAYABLE
Loans payable are comprised of the following:
In connection with the issuance of debt on November 8, 2011, the Company issued an aggregate of 593,000 warrants to purchase the Company's common stock at $0.001 per share for five years from the date of issuance. The aggregate fair value of $157,130 was determined using the Black Scholes option pricing model based on the following assumptions: dividend yield: 0%; volatility: 369.88% to 375.20% and risk free rate of 0.96%. The determined fair value of the issued warrants are amortized ratably over the term of the loan. See discussion of settlement agreement the Company entered into on October 26, 2012 in Note 12 below.
In connection with the issuance of debt on December 12, 2011, the Company issued an aggregate of 55,000 warrants to purchase the Company's common stock at $0.001 per share for five years from date of issuance and 75,000 shares of the Company's common stock. The aggregate fair value of the warrants of $15,300 was determined using the Black Scholes option pricing model based on the following assumptions: dividend yield: 0%; volatility: 364.69% to 366.74% and risk free rate of 0.96%. The total determined fair value of the issued warrants and common stock of $37,800 is amortized ratably over the term of the loan. See discussion of settlement agreement the Company entered into on October 26, 2012 in Note 12 below.
During the year ended December 31, 2012, the Company issued 92,390 shares of its common stock in settlement of $50,000 notes payable and related accrued interest recognizing a gain on settlement of debt of $36,956.
NOTE 12 - NOTES PAYABLE-BRIDGE
On July 25, 2011, the Company began conducting a private placement of up to $600,000 of Bridge Units (the “Units”) at a price of $25,000 per Unit to accredited investors only (the “Offering”); provided, however, that up to an additional six Units may be offered to fill over-allotments. Each Unit consists of (1) a $25,000 promissory note (each, a “Bridge Note,” as more fully described below), unless extended pursuant to the Bridge Note, and (2) 50,000 shares of the Company’s common stock.
The Bridge Notes are secured by a first lien on certain oil and gas leases and related equipment and were initially due the earlier of (i) November 30, 2011 (subsequently extended to January 31, 2012 with the payment of accrued interest) or (ii) within two business days following the close of any debt or equity financing totaling $3,000,000 or more. The interest rate(s) is at 6.25% per annum through September 30, 2011; 8.25% per annum from October 1, 2011 through November 30, 2011; and 12.25% per annum thereafter (default interest). Interest is payable at the end of each period and payable monthly thereafter. During the year ended December 31, 2011, the Company issued an aggregate of $750,000 Units.
In connection with the issuance of the Units, the Company issued an aggregate of 1,500,000 shares of its common stock. The fair value of the common stock of $440,938 was recorded as a debt discount and amortized ratably to current period interest expense. During the year ended December 31, 2011, the Company has amortized $371,693 to interest expense.
During the months of August and September 2011, the Company entered into non-exclusive placement agent agreements (each, a “Placement Agent Agreement”) with the following broker-dealers registered with the SEC and who are members of the Financial Industry Regulatory Authority (“FINRA”): Beige Securities, LLC; ViewTrade Securities, Inc.; McNicoll, Lewis & Vlak LLC; Park City Capital, Inc.; and I-Bankers Securities, Inc. Aegis Capital Corporation and Halcyon Cabot Partners Ltd. Each Placement Agent Agreement provides that the respective placement agent will receive (1) a placement agent fee equal to 5% of the gross proceeds from sales of Units by such placement agent; and (2) a five-year warrant to purchase that certain number of shares of our common stock equal to 10% of the common stock sold in the offering by such placement agent exercisable at $0.60 per share. The term of each Placement Agent Agreement is coterminous with the term of the offering. During the year ended December 31, 2011, the Company charged the fair value of the warrants of $37,498 to current period operations. The estimated fair value of the issued warrants were determined using the Black Scholes option pricing model based on the following assumptions: dividend yield: 0%; volatility: 371.27% and risk free rate of 0.96%.
Settlement Agreement
On October 26, 2012, the Company entered into a Settlement Agreement (“Agreement”) whereby the bridge note holders in aggregate of $750,000, the loan note holder of a note issued on November 8, 2011 for $593,000 (Note 11) and the loan note holder of a note issued on December 12, 2011 for $130,000 (Note 11) agreed not to pursue foreclosure action against secured property in exchange for the Company agreeing to drop its counter claims subject to the following terms:
a.
Beginning November 1, 2012, the interest rate on the above described notes will be 12% per annum.
b.
Beginning November 1, 2013, the interest rate on the above described notes will increase to 15% per annum.
c.
Beginning on May 1, 2014, the interest rate on the above described notes will increase to 18% per annum.
d.
Until all obligations are paid in full (as defined), the Company will pay into an escrow 20% through February 28, 2013, 35% through April 30, 2013 and 35% thereafter, of all revenue paid to the Company by any purchaser of hydrocarbons from any of the Montana Leases. Application of funds to be applied as defined.
e.
Until all obligations are paid in full (as defined), the Company will pay into an escrow a 10% overriding royalty for any hydrocarbon wells other than the Montana Leases.
f.
The Company is required to issue an aggregate of 895,313 shares of common stock and 1,444,187 warrants to purchase the Company’s common stock at an exercise price of $0.001 for five years. Anti-dilutive rights were also provided to the note holders in connection with these issuances.
g.
For the two months ended December 31, 2012, the Company must deliver common stock or warrants, as the case may be, based on 0.1667 share (warrant) per dollar of principal outstanding at December 31, 2012. Anti-dilutive rights provided.
h.
Beginning for the three months ended March 31, 2013, the Company must deliver common stock or warrants, as the case may be, based on 0.25 share (warrant) per dollar of principal outstanding at December 31, 2012. Anti-dilutive rights provided.
In connection with the Settlement agreement, the Company recorded a loss on debt modification of $426,980 comprised of legal obligations incurred and assumed of $64,359 and $362,621 fair value of issued commons stock and warrants (see Note 13 below)
NOTE 13 - DERIVATIVE LIABILITIES
Company has identified embedded derivatives in connection with the issuance of convertible debentures and anti-dilutive rights embedded in the settlement warrants and common stock as discussed in Note 12 above. A summary of the derivative liabilities are as follows:
Convertible Debentures
The Company identified embedded derivatives related to the Convertible Debentures entered into on September 21, 2012. These embedded derivatives included certain conversion features. The accounting treatment of derivative financial instruments requires that the Company record the fair value of the derivatives as of the inception date of the Convertible Promissory Notes and to adjust the fair value as of each subsequent balance sheet date. At the inception of the Convertible Debentures, the Company determined a fair value of $90,858 of the embedded derivative. The fair value of the embedded derivative was determined using the Binomial Lattice Model based on the following assumptions:
The initial fair value of the embedded debt derivative of $90,858 was allocated as a debt discount up to the proceeds of the notes ($50,000) with the remainder ($40,858) charged to current period operations as interest expense.
The fair value of the described embedded derivative of $141,407 at December 31, 2012 was determined using the Binomial Lattice Model with the following assumptions:
At December 31, 2012, the Company adjusted the recorded fair value of the derivative liability to market resulting in non-cash, non-operating loss of $50,549 for the year ended December 31, 2012.
Settlement Agreement
The Company identified embedded derivatives related to warrants and common stock issued in connection with a settlement agreement entered into on October 26, 2012. These embedded derivatives included anti-dilutive features. The accounting treatment of derivative financial instruments requires that the Company record the fair value of the derivatives as of the issuance date and to adjust the fair value as of each subsequent balance sheet date. At the issuance date of the warrants and common stock (including anti-dilutive common stock and warrants issued for payment of interest), the Company determined a fair value of $391,955 as the embedded derivative. The fair value of the embedded derivative was determined using the Binomial Lattice Model based on the following assumptions:
The initial fair value of the embedded derivative of $391,956 was charged to current period operations as debt modification of $362,621 and $$29,335 as interest expense.
The fair value of the described embedded derivatives of $491,370 at December 31, 2012 was determined using the Binomial Lattice Model with the following assumptions:
At December 31, 2012, the Company adjusted the recorded fair value of the derivative liability to market resulting in non-cash, non-operating loss of $99,416 for the year ended December 31, 2012.
NOTE 14 - STOCKHOLDERS’ EQUITY
Preferred Stock
Amendments to Certificate of Incorporation; Designations of Preferred Stock
On May 8, 2012, the Company filed with the Delaware Secretary of State a Certificate of Amendment to its Certificate of Incorporation establishing a class of blank check preferred stock comprised of 20,000,000 shares, in addition to its 1,000,000,000 authorized common stock and 1,000,000 authorized Series A Convertible Preferred Stock (the “Series A”).
On May 9, 2012, the Company filed a Certificate of Designations designating 5,750,000 of the newly created blank check preferred as Series B Callable Preferred Stock (the “Series B”) and setting forth the rights, powers, designations and preferences of the Series B.
On May 10, 2012, the Company filed a Certificate of Amendment to its Certificate of Designations for the Series A dated September 22, 2009.
The Series A
The general attributes of the Series A is as follows:
Rank. The Series A ranks junior to the Senior B and pari passu with our common stock for liquidation and dividend rights.
Dividends. Holders of the Series A Convertible Preferred Stock shall be entitled to receive dividends when and if declared by the Board of Directors. Notwithstanding the forgoing, no dividends or other distributions shall be made or declared, in cash or in kind, to holders of the Series A or to our common unless and until a dividend of like amount is first paid in full to holders of the Series B.
Voting Rights. Holders of Series A Convertible Preferred Stock will have the right to that number of votes determined by multiplying the number of shares issuable upon conversion of the Series A Convertible Preferred Stock by 1,000.
Conversion. Holders of Series A Convertible Preferred Stock will have the right to convert the Series A Convertible Preferred Stock at the option of the holder, at any time, into same number of common shares, subject to certain fundamental transaction adjustments.
The Series B
The general attributes of the Series B is as follows:
Rank. The Series B ranks senior to the Senior A and our common stock for liquidation and dividend rights.
Dividends. Holders of the Series A shall be entitled to receive cumulative dividends quarterly at the rate of 13% per annum of (as adjusted for subdivisions, combinations, stock dividends, recapitalizations and the like, the “Original Issue Price”) for the first year following the original date of issuance of such share of Series B, and at the rate of 15% per annum of the Original Issue Price for each subsequent year until such share of Series B is redeemed. No dividends or other distributions shall be made or declared, in cash or in kind, to holders of the Series A or our common stockholders unless and until a dividend of like amount is first paid in full to holders of the Series B.
Redemption. The Series B shall not be redeemable by the Company prior to one year after the original date of issuance of each shares, after which time such share may be redeemed by the Company at any time at a redemption price of $1.00 plus all unpaid dividends thereon.
Common stock
The Company is authorized to issue 1,000,000,000 shares of its $0.001 par value common stock. As of December 31, 2012 there were 38,716,299 shares issued and outstanding.
On October 23, 2009, the Company affected a ten thousand-for-one (10,000 to 1) reverse stock split of its issued and outstanding shares of common stock, $0.001 par value. All references in the consolidated financial statements and the notes to consolidated financial statements, number of shares, and share amounts have been retroactively restated to reflect the forward split.
During the year ended December 31, 2005, the Company issued an aggregate of 920 shares of common stock for services rendered at approximately $500.00 per share.
During the year ended December 31, 2006, the Company issued an aggregate of 186 shares of common stock for services rendered and expenses at approximately $121.97 per share.
During the year ended December 31, 2009, the Company issued an aggregate of 10,045,000 shares of common stock for services rendered and expenses at approximately $0.80 per share.
On October 23, 2009, the Company affected a ten thousand-for-one (10,000 to 1) reverse stock split of its issued and outstanding shares of common stock, $0.001 par value. All references in the consolidated financial statements and the notes to consolidated financial statements, number of shares, and share amounts have been retroactively restated to reflect the forward split.
During the year ended December 31, 2010, the Company converted various outstanding debts including loans, equipment leases and account payables. Pursuant to the various debt conversion agreements and pay-off letters, the Company converted 13 promissory notes and accrued interest, an equipment lease and an account payable totaling $1,524,757 into the Company’s common stock at various conversion prices ranging from $0.07 to $0.80 per share. An aggregate of 10,040,702 shares of common stock were issued in exchange for full release from such debt obligations.
On May 24, 2010, the Company issued 375,000 shares to a consultant for consulting services.
During the year ended December 31, 2010, the Company issued an aggregate of 1,643,000 shares of common stock for services rendered and expenses at between approximately $0.18 and $1.18 per share.
During the year ended December 31, 2010, the Company issued 1,300,000 and 37,500 shares of common stock in settlement of ligation and notes payable, respectively. The common shares are held in escrow awaiting final resolution, therefore are reflected as issued, but not outstanding as of December 31, 2010.
During the year ended December 31, 2011, the Company issued an aggregate of 3,860,000 shares of common stock for services ranging from $0.20 to $0.87 per share.
During the year ended December 31, 2012, the Company issued an aggregate of 1,110,000 shares for services rendered valued at $494,399.
During the year ended December 31, 2012, the Company received and cancelled a net of 1,900,000 shares of common stock in connection with an amendment of a previously acquired license agreement.
NOTE 15 - COMMITMENTS AND OBLIGATIONS
Overriding Royalty Interests
On April 11, 2005, the principal stockholders of the Company formed NAEG Founders Holding Corporation (formerly NAEG Founders Corporation) for the purpose of selling a 5% overriding royalty interest in the Company’s future oil and gas production. The Company sold a 5% overriding royalty interest on future potential oil and gas production from oil and gas properties held and operated by the Company. During the years ended December 31, 2007 and 2008, the Company received payments of $1,715,000 and $1,208,570, respectively, and was recorded as additional paid in capital in each respectively year.
Mineral Royalty Payments and Oil & Gas Lease Payments
The Company is obligated to pay royalties to the lessors of its oil fields under the oil and gas leases with payments ranging from 16.67% to 20% of any production revenue. The Company is obligated for a minimum of $3.00 per acre per year in lease rental payments in Montana. The Company has fully paid-up several leases in advance or the leases are held by production or an extension provided by such Lessors and is therefore not at this time required to make any yearly lease rental payments.
Operating leases
1.
The Company leases office temporary space in New York at approximately $100 per month on a month to month basis.
2.
The Company currently leases a maintenance facility in Montana on a month-to-month basis at $1,500 per month.
3.
The Company currently leases an office/storage facility in Montana on a month-to-month basis at $1,100 per month.
The lease expenses for the Company’s field office, storage and maintenance facilities in Montana have been included on the balance sheet in Oil & Gas Properties.
Consulting agreements
The Company has consulting agreements with outside contractors. The Agreements are generally month-to-month.
Litigation
High Capital Funding, LLC. vs. Native American Energy Group, Inc. - Cause No. DV-12-30
On May 25, 2012, High Capital Funding LLC (“High Capital or Plaintiff”), filed a Complaint for Foreclosure in the Fifteenth Judicial District Court of the State of Montana, Roosevelt County, against the Company alleging that the Company is in default for nonpayment of monies owed under various loans made to the Company from the period beginning July 25, 2012 to December 12, 2012 (“the Loans”) during the Company’s field operations in Montana related to its 5 Well Workover and Enhanced Oil Recovery Program. In the Complaint, Plaintiff sought a judgment against the Company for the unpaid principal and interest owed under such loans.
On June 27, 2012, the Company filed a motion to dismiss Plaintiff’s complaint on the grounds that Plaintiff’s complaint failed to state a claim upon which relief can be granted (the “Motion”). On July 11, 2012, the Honorable Judge David Cybulski issued an order denying the Motion and allowed the Company 20 additional days to file its answer to the Complaint.
On August 13, 2012, the Company filed its “Answer and Counterclaim” in which the Company asserted various defenses to Plaintiff’s claims for relief as well as counterclaims against the Plaintiff for; Breach of Contract, Unjust Enrichment, Breach of Duty of Good Faith and Fair Dealing, Promissory Estoppel, Negligent Misrepresentation, and Constructive Fraud. In its Answer and Counterclaim, the Company is ultimately seeking damages to be proven at trial which include, but are not limited to; lost revenue from oil production continuing to accrue since September 2011 as a result of Plaintiff’s negligent and untimely remittance of loan proceeds as agreed to by both parties, recovery of various shares of the Company’s restricted common stock and five year exercise warrants for the purchase of the Company’s restricted common stock; and specific performance by the Plaintiff of its obligations under the Loans. On the same date, the Company also filed an “Application for Preliminary Injunction and Temporary Restraining Order” (the “Application”). In its Application, Company is seeking relief including but not limited to, an injunction preventing Plaintiff from transferring common shares or exercising warrants issued as partial consideration for such loans agreements.
On August 21, 2012, Judge David Cybulski issued an order granting the Company’s request for a Temporary Restraining Order, as stated above, and set the date for a show cause hearing for Wednesday, August 29, 2012.
On August 29, 2012, the parties agreed to stipulate in court to the entry of a Temporary Order in resolution to the Company’s Application for a Temporary Restraining Order and Preliminary Injunction. The Temporary Restraining Order and order to Show Cause dated August 22, 2012, was ordered, vacated and dissolved, permitting Plaintiff’s to transfer its Bridge Shares, LTA warrants, and SL3 warrants.
On October 26, 2012, in an effort to avoid further litigation, both parties agreed to terms for a Settlement Agreement. See discussion of Settlement Agreement in Note 12 above. On December 26, 2012, Native American Energy Group, Inc. and High Capital Funding LLC jointly executed a Stipulation of Dismissal of the Foreclosure Action and all Counterclaims alleged by the Company against High Capital Funding LLC in its Answer and Counterclaim filed with the court on August 13, 2012.
Steven Glodack vs. Native American Energy Group, Inc, Joseph D’Arrigo, Raj Nanvaan - Case No. 12-28983
On October 16, 2012, the Company was notified of a complaint filed in the Circuit Court of the 11th Judicial Circuit in and for Miami-Dade County, Florida. The complaint was filed by Steven Glodack, an unsecured creditor of the Company (“Plaintiff”) and names as Defendants, the Company, and Mr. Joseph D’Arrigo and Raj Nanvaan, in their individual capacity. Plaintiff’s complaint alleges, among other things, that the Company is in default for non-payment of monies owed under a loan made to the Company in August 2008 and seeks a judgment against the Defendants for the principal sum of $165,000 together with interest, costs and reasonable attorney’s fees. On November 5, 2012, Florida counsel entered a Notice of Special Appearance on behalf of the Company and Messrs. D’Arrigo and Nanvaan for the limited purposes of challenging the sufficiency of process, service of process and jurisdiction of the Florida court. On or about November 20, 2012, a Motion to Quash Service of Process and to Dismiss Plaintiff’s Complaint for lack of jurisdiction was filed with the Court on behalf of the Company and D’Arrigo and Nanvaan (collectively the “Motion to Dismiss”).
Subsequent to the filing of the Motion to Dismiss, the lawsuit has remained dormant and the parties have been attempting to negotiate an out-of-court settlement. Based upon the applicable facts and law, there exists a strong likelihood that, barring an out-of-court settlement, the litigation will be dismissed by the Florida court on procedural grounds. The Company intends to contest the case vigorously.
Other than the litigations disclosed above, there is no action, suit, proceeding, inquiry or investigation before or by any court, public board, government agency, self-regulatory organization or body pending or, to the knowledge of the executive officers of the Company or any of its subsidiaries, threatened against or affecting the Company, its common stock, any of its subsidiaries or the Company’s or the Company’s subsidiaries’ officers or directors in their capacities as such, in which an adverse decision could have a material adverse effect.
NOTE 16 - RELATED PARTY TRANSACTIONS
From January 18, 2005 (date of inception) through December 31, 2012, our principal stockholders have contributed an aggregate of $1,315,963 in working capital with the funds thereof reflected as additional paid in capital in the Company’s financial statements.
In conjunction with the reverse acquisition in 2009, the Company issued an aggregate of 10,000,000 shares of common stock and 500,000 shares of convertible preferred stock to two officers of Native American Energy Group, Inc.
As of December 31, 2012, Joseph D’Arrigo and family members have loans outstanding to the Company of $16,550, and Raj Nanvaan has a loan outstanding of $36,418. These loans are included in our loans payable and were made interest free. There is no benefit to either Mr. D’Arrigo or Mr. Nanvaan directly or indirectly from providing such loans.
In October 2011, the Company acquired a vehicle for a down payment of $12,000 towards the total purchase price of $29,500. For credit purposes only, the vehicle's title and related loan were issued in the name of our president. Upon settlement of the outstanding loan, the vehicle's ownership will be transferred to our name. For accounting purposes, the vehicle and related loan are recorded as part of our financial statements as assets and obligations, respectively.
In addition to being officers and directors of Native American Energy Group, Inc., Joseph D’Arrigo, our President, Chief Executive Officer and Chairman, and Raj Nanvaan, our Chief Financial Officer, Chief Operations Officer, Vice President, Treasurer and Director, are directors and minority shareholders of NAEG Founders Holding Corporation, a private New York corporation that Messrs. D’Arrigo and Nanvaan formed to hold (i) Mr. D’Arrigo’s 2.5% Overriding Royalty interest in our future oil & gas production and (ii) Mr. Nanvaan’s 2.5% Overriding Royalty interest in our future oil & gas production. After the transfer of such interests to NAEG Founders Holding Corporation, Messrs. D’Arrigo and Nanvaan each had a remaining 0.5% Overriding Royalty interest in our future oil & gas production, which they voluntarily cancelled for no consideration. As the result of the assignment of the interests of both Messrs. D’Arrigo and Nanvaan to NAEG Founders Holding Corporation by way of a board resolution, NAEG Founders Holding Corporation held a total 5% Overriding Royalty Interest in the future oil & gas production from leasehold interests. As background, Messrs. D’Arrigo and Nanvaan had each been granted their respective 3% Overriding Royalty Interest in our future oil & gas production in exchange for the assignment of their respective interests in a drilling project associated with another company called Rockwell Petroleum. The project was called the Jones Draw Field. Such rights were acquired by them before our organization while working with other oil & gas companies as tribal liaisons. To date, Messrs. D’Arrigo and Nanvaan have not received any compensation or dividend distributions from NAEG Founders Holdings Corporation because such company has not had any commercial production to date.
In connection with the execution of a capital lease obligation in March of 2006 regarding our Workover Rig, Messrs. D’Arrigo and Nanvaan and their respective relatives provided real estate collateral pledges and personal guarantees to the financial institution in exchange for an obligation fee of $325,000, of which $75,000 was payable to Joseph D’Arrigo, $150,000 was payable to Raj Nanvaan and the balance payable to the parents of Raj Nanvaan. The guarantee fees were being amortized ratably over the term of such lease, which was due to expire in 2014. On March 24, 2010, the capital lease obligation was converted to equity. As part of this conversion and settlement, the lien placed on Mr. Nanvaan’s home was lifted by the finance company.
In January 2013, Richard Ross loaned the company $18,950. The loan was made interest free. There is no benefit to Mr. Ross directly or indirectly from providing such loans.
NOTE 17 - STOCK OPTIONS AND WARRANTS
Stock Options
Employee options:
The following table summarizes the changes in employee options outstanding and the related prices for the shares of the Company’s common stock at December 31, 2012:
Transactions involving the Company’s employee option issuance are summarized as follows:
On September 14, 2012, the Company granted employee options to purchase an aggregate of 10,000,000 shares of the Company’s common stock to directors, officers and employees. The option grants are vesting at 25% per year, fully vest in four years and the exercise prices from $0.20 to $2.00 per share for five to ten years.
The fair value for these awards was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions, assuming no expected dividends:
During the year ended December 31, 2012, the Company charged the vesting fair value of employee options of $162,500 to current period operations.
Non- Employee options:
The following table summarizes the changes in non-employee options outstanding and the related prices for the shares of the Company’s common stock at December 31, 2012:
Transactions involving the Company’s non-employee option issuance are summarized as follows:
On September 14, 2012, the Company granted non-employee options to purchase 1,000,000 shares of the Company’s common stock to a consultant. The option grant vest at a rate of 50% per year and fully vest in two years with an exercise price of $0.20 per share.
Warrants
The following table summarizes the changes in warrants outstanding and the related prices for the shares of the Company’s common stock at December 31, 2012:
Transactions involving the Company’s warrant issuance are summarized as follows:
In November 2011, in connection with the issuance of bridge notes payable as described above, the Company issued an aggregate of 150,000 warrants to purchase the Company's common stock at $0.60 per share expiring five years from the date of issuance. The fair value of the warrants was determined using the Black Scholes option pricing model with the following assumptions:
The aggregate fair value of $37,198 was charged to period operations in 2011.
In November and December 2011, in connection with the issuance of notes payable as described above, the Company issued an aggregate of 648,000 warrants to purchase the Company's common stock at $0.001 per share expiring five years from the date of issuance. The fair value of the warrants was determined using the Black Scholes option pricing model with the following assumptions:
The aggregate fair value of $172,430 was recorded as a debt discount and amortized over the term of the note payable.
As per the Settlement Agreement entered into on January 27, 2012 and as previously reported in the 8-K filing with the Securities and Exchange Commission on January 31, 2012, on June 21, 2012, the Company issued an aggregate of 2,345,506 warrants to purchase the Company's common stock exercisable at $0.70 per share for two years from the date of issuance within 30 calendar days of the removal of the global lock by DTC. The Global Lock was removed by DTC on June 21, 2012. The Company recorded the estimated fair value of $1,381,403 as a charge to current period operations in 2012. The estimated fair value was determined using the Black Scholes option pricing method with the following assumptions: Dividend yield- 0%, risk free rate-0.12%, volatility- 431.55%, expected life-contract life.
As per the Settlement Agreement entered into on October 26, 2012, the Company issued an aggregate of 1,444,188 warrants to purchase the Company’s common stock at $0.001 for five years. The Company recorded the estimated fair value of $223,849 as a charge to current period operations in 2012 as loan modification expense. The estimated fair value was determined using the Binomial Lattice option pricing method with the following assumptions: Dividend yield- 0%, risk free rate-0.41%, volatility- 422.12%, expected life-contract life.
NOTE 18 - INCOME TAXES
The Company follows Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Temporary differences between taxable income reported for financial reporting purposes and income tax purposes are insignificant.
At December 31, 2012, the Company has available for federal income tax purposes a net operating loss carry forward of approximately $7,200,000 expiring in the year 2031 that may be used to offset future taxable income. The Company has provided a valuation reserve against the full amount of the net operating loss benefit, since in the opinion of management based upon the earnings history of the Company; it is more likely than not that the benefits will not be realized. Due to significant changes in the Company’s ownership, the future use of its existing net operating losses may be limited. Components of deferred tax assets as of December 31, 2011 are as follows:
The total provision differs from the amount that would be obtained by applying the federal statutory rate of 35% to income before income taxes, as follows:
NOTE 19 - SUBSEQUENT EVENTS
Related Party Transaction: The Company borrowed $18,950 from an officer of the Company in January 2013.
In February & March 2013, we issued and sold to 3 investors 125,000 shares of our common stock at a per share purchase price of $0.10 for proceeds of $12,500. In February 2013, we issued 200,000 shares of common stock to a law firm as collateral against an outstanding payable.
In May 2013, the Company moved its principal offices to 61-43 186th Street Suite 507 Fresh Meadows, NY 11365.
In March 2012, we issued 355,719 shares and 430,467 warrants in accordance with the settlement agreement executed with High Capital Funding LLC on December 26, 2012 as per Note 12 - Notes Payable Bridge - Settlement Agreement.