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, which had been formed in April 2007 in Nevada but had since lain dormant.
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 five well-workover program on our 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.
We have had only limited field operations since our inception. Currently, we have three principal projects:
·development of oil and gas interests in the Williston Basin in Montana;
·development of coal-bed methane natural gas (“CBM”) in the Cook Inlet Basin in Alaska; and
·the implementation of vertical axis wind turbine power generation technology for the production of clean, cost-efficient green energy throughout the United States, including Alaska and all U.S. Native American Indian reservations.
We have been in the process of developing several energy projects for the past seven years. This has included the acquisition of oil properties in Montana and natural gas properties in Alaska. Since the acquisition of these properties, we have had limited oil and gas operations in Montana and Alaska. Our management believes, however, that properties in these two states have potential based on the limited 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 Oklahoma on trust lands belonging to the Apache, Commanche, Kiowa and Seminole Tribes and their allotted members.
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 Development 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 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.
In addition, we have identified several prospects for development of oil from the Bakken Shale formation on the Fort Peck Indian Reservation in Northeast Montana. A U.S. Geological Services (“USGS”) study released in April 2008 (the “Study”) revealed that up to several hundred millions of barrels of oil are pooled under the Fort Peck Indian Reservation. The Study further estimated a total of 3.65 billion barrels of oil are under the Bakken formation, which stretches from eastern Montana into Central Dakota. The USGS typically reassess oil formations and field reservoirs every ten years, however due to the increased production from the Bakken formation and other data received by the USGS, analysts have determined that the Bakken formation estimates may have been conservative which prompted the USGS to reassess the Bakken oil formation sooner than the typical 10-year timeframe. In October 2011, the USGS began the reassessment and it is expected to be completed by late 2013.
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 our 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 are leveraging 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:
·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;
·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;
·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;
·unlock and stimulate trapped oil reserves beyond any near wellbore damage by displacing acid, specialty fluids or microbial products into the laterals;
·penetrate the reservoir and open up larger producing channels without using conventional perforating guns, which can damage the formation and are hazardous; and
·create a low pressure, high velocity circulating environment within the wellbore to ensure cuttings removal, geological samples and efficient well cleaning;
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.
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 April 10, 2012, the EIA projects that the West Texas Intermediate (“WTI”) spot prices are expected to average about $106 per barrel in 2012, which is $11 higher than the average WTI price of crude oil during 2011. 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 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 permit was for 5 years and is set to expire on October 1, 2012. Although the permit expires on October 1, 2012, in April 2012, we initiated discussions with the Mat-Su Borough to extend the permit or provide for a resubmission of the permit application binder similar to the Alaska state permit as described below.
Our State permit was approved by the Alaska Oil & Gas Conservation Commission (“AOGCC”) on February 25, 2008. Although the State permit expired on February 28, 2010, AOGCC has informed us that AOGCC will renew our application for another two years as long as we have a valid Mat-Su Borough drilling permit. Although we will be required to re-submit the application with the same information that was provided in our initial application, the AOGCC informed us that it would not be subject to the intense review process that our application underwent back for the period 2007 to 2008. As per discussions with the permitting division at the AOGCC in April 2012, they further informed us that the re-permitting process in our case will take approximately three weeks.
Due to the dwindling supply of natural gas in the Cook Inlet for local & commercial consumption, we believe that there is a viable market for unconventional natural gas such as CBM. 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, we have continued to maintain communication with the various prospective purchasers in the Cook Inlet area such as Conoco, Chugach Electric Association Inc. (“Chugach”) and the Matanuska Electric Association (“MEA”). In addition, MEA is working to build their own power generation facilities. In 2009, MEA acquired about 70 acres of land located northeast of the Eklutna Interchange of the Glenn Highway. The 70 acres are divided into parcels that are re-zoned as I-3 (industrial 3, rural industrial district). MEA's plans, include up to a 180 megawatt natural gas generation plant and related facilities (the “Power Plant”). Building a natural gas power plant at Eklutna is part of MEA’s mission of bringing reliable, affordable power to the residents of the Cook Inlet. Construction of the plant is scheduled to begin in April 2012 and they expect to be ready for testing by October 2014. MEA currently has a power purchase agreement with Chugach which expires on December 31, 2014. Due to MEA’s need for natural gas for their power plant, we feel that CBM production from our Kircher Unit CBM well and any additional development could contribute towards the power plant’s growing needs. MEA expects to begin generating their own power by January 1, 2015.
According to the U.S. Energy Information Administration’s (“EIA”) Short-Term Energy Outlook, (the “Report”) dated April 10, 2012, EIA’s average 2012 Henry Hub natural gas spot price forecast is $2.51 per million British thermal units (MMBtu), a decline of $1.49 per MMBtu from the 2011 average spot price. EIA expects that Henry Hub spot prices will average $3.40 per MMBtu in 2013. It is very important to realize that the price of natural gas in Alaska is typically three to four times the Henry Hub natural gas spot price which is generally the primary price set for the natural gas market in the lower 48 states. Below is a graph showing the historical prices for natural gas sold to commercial consumers in Alaska since 1990. The graph is also available at the following link: http://www.eia.gov/dnav/ng/hist/n3020ak3m.htm
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) (together, the “Territory”).
As per the Amendment, the Territory now equals approximately 2.3 billion acres, and the license granted under the Amendment applies to all wind turbine products and systems developed by Windaus currently and in the future. We intend to manufacture these turbines in the United States at various manufacturing facilities to be established per our plan of action post-certification in accordance with certain standards maintained by Underwriters Laboratories (“UL”) and the American Wind Energy Association (“AWEA”).
Contingent on funding and capital availability, we intend to engage in three 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.
3.Manufacturing: strategic establishment of various manufacturing facilities throughout the United States in key regional locations, including forming partnerships with Native American tribes which will provide employment opportunities for tribal members and qualify for various grant funding opportunities from the Office of Indian Energy and the Department of Energy.
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 Program
Below are background information and a field update on each well in the Five-Well 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 after completion of a private placement offering. 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 2012 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 early summer of 2012 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 summer of 2012 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.
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 workover, lateral jetting and winterization 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 2012 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. Once these items are installed, we will 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.
Upon the completion of a private placement offering and receipt of net proceeds, we plan to commence the workover and EOR operations on the Beery 22-24 well.
Other Oil & Gas Wells
Kircher Unit Lease - 840 Acres in Palmer, Alaska (Mat-Su Valley)
In June 2008, we contracted AMAQ Excavating out of Palmer, Alaska to construct the drilling pad and access road leading to the drill site for the Kircher Unit Pilot Well. The construction was completed in July 2008. The well site is ready for drilling operations. Although our drilling permit with the Mat-Su Borough expires on October 1, 2012, in April 2012, we initiated discussions with the Mat-Su Borough to extend the permit or provide for a resubmission of the permit application binder similar to the Alaska state permit as described below. In addition, although our State permit expired on February 28, 2010, the Alaska Oil & Gas Conservation Commission (“AOGCC”) has informed us that they will renew our application for another two years as long as we have a valid Mat-Su Borough drilling permit. Although we will be required to re-submit the application with the same information that was provided in our initial application, the AOGCC informed us that it would not be subject to the intense review process that our application underwent back for the period 2007 to 2008. As per discussions with the permitting division at the AOGCC in April 2012, they further informed us that the re-permitting process in our case will take approximately three weeks.
Facilities
Corporate Office - We maintain our current principal office at 108-18 Queens Blvd., Suite 901, Forest Hills, NY 11375. Our current space consists of approximately 1600 square feet of office space that is leased by us. While the lease term expires December 31, 2010, we are currently leasing the space on a month to month basis. The monthly rental payment is $4,766.70.
Alaska Field Office - We maintain a field office at the Wells Fargo Building, 705 S. Bailey Street, Palmer, Alaska 99645. The space consists of approximately 275 square feet of office space that is leased by us. The monthly rent is $593.00.
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. The monthly rent is $1500.00
Item 3.
Item 3. Legal Proceedings.
Steven Freifeld, et al. v. Native American Energy Group, Inc., et al., Index No. 005503-2010.
On March 19, 2010, Plaintiffs, the putative investors in NAEG Founders Holding Corporation (“Founders”), filed a complaint in the Supreme Court of the State of New York, Nassau County, against us, Joseph D’Arrigo, in his capacity as our President and CEO, Raj Nanvaan, in his capacity as our CFO, COO, Vice President and Treasurer, and others (together, the “Defendants”). We and Messrs. D’Arrigo and Nanvaan were named in this complaint because Messrs. D’Arrigo and Nanvaan are each officers and directors of both us and Founders. Plaintiffs’ complaint alleged, among other things, that we and/or our affiliates and officers have breached fiduciary duties purportedly owed Plaintiffs and committed common law fraud through misrepresentations in the course of soliciting investments. The claims primarily resulted from Founders’ transfer of its fractional ownership of its interests and the sale of some of its royalty interest to third parties (some of which are also Plaintiffs in this proceeding), and the use of the proceeds resulting from such transfer and sale to fund the operating needs of Native American Energy Group. Specifically, the Plaintiffs allege that they invested in one or more of the named entity Defendants based on misleading representations about such entity Defendant’s potential success. Further, the Plaintiffs claimed that the individual Defendants changed the names and/or the states of incorporation under the same name of the entity Defendants without going through the proper corporate formalities. The Plaintiffs also alleged that they were not provided with stock certificates, did not receive any notice of shareholders’ meetings and were denied access to one or more of the entity Defendants’ books and records. Plaintiffs sought an order granting to Plaintiffs certain disclosures, unfettered access to various corporate books and records, and termination of our current officers and directors. Plaintiffs also sought compensatory damages in an amount to be determined at trial, but alleged in the complaint to equal or exceed the amount of their putative investments in us and/or our affiliates.
In an effort to avoid further litigation, we, on behalf of Defendants, have agreed to issue to the Plaintiffs an aggregate of 606,756 shares of our common stock in addition to the 1,738,750 shares already held in escrow for a total of 2,345,506 shares of our Common Stock (the "Settlement Shares"). We have further agreed that within 30 calendar days of the removal of the global lock by DTC, we will issue each Plaintiff an individual warrant. The term of each individual warrant shall be for two years from the date of the removal of the DTC Global Lock (as defined and described under “Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities-Market Information”) and shall be for the purchase of a number of shares of our common stock equal to the number of Settlement Shares received by that individual Plaintiff, with an exercise price of $0.70 per share.
In consideration for the above, the Plaintiffs agreed to dismiss all claims alleged in the lawsuit with prejudice and on January 30, 2012 filed with the Court a Notice of Voluntary Dismissal with Prejudice.
To the best knowledge of management, there are no material litigation matters pending or threatened against us.
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 May 27, 2010, the Depository Trust & Clearing Corporation (“DTC”) suspended trade and settlement services (known as a “Global Lock” or “Chill”) for our Company’s security, resulting in our common stock being ineligible for delivery, transfer or withdrawal through the DTC system until the Global Lock is removed by DTC. The compliance department at DTC informed us that the Global Lock or Chill had been instituted due to their uncertainty about the shares of Halstead Energy Corporation held in street name under their nominee Cede & Co that were erroneously comingled with our Company’s shares in February 2005. Although management is diligently working on having this Global Lock removed, there can be no assurance that we will be successful. Investors are cautioned that our shares are ineligible for delivery, transfer or withdrawal through the DTC system in secondary trading until the Global Lock is removed by DTC.
Holders
As of April 5, 2012, we had 753 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 having at least a majority of the total votes as of April 5, 2012, which written consent shall be effective 20 calendar days from the mailing of a definitive information statement to our shareholders of record as of April 5, 2012. A preliminary information statement was filed with the SEC on April 6, 2012, and the definitive information statement is expected to be sent on or about April 17, 2012.
Recent Sales of Unregistered Securities
In the fiscal year ended December 31, 2011, 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:
·During the three months ended March 31, 2011, we issued and sold to one investor an aggregate of 250,000 shares of our common stock at a per share purchase price of $.10 for proceeds of $25,000.
·On March 17, 2011 we issued 360,000 shares of our common stock to a non-affiliate in connection with an amendment to a consulting agreement originally entered into on June 10, 2010. Under the amendment, we had agreed to pay a monthly fee of $3,000, payable through the issuance of 360,000 shares of common stock at a market value of $0.10 per share, as additional compensation in exchange for extending the term of the consulting agreement until March 14, 2012.
·On May 29, 2011, we entered into a Strategic Consulting Agreement (the “Agreement”) with Insource Insight Services, LLC (“Insight”), pursuant to which we issued to Insight, in consideration for the services provided under the Strategic Consulting Agreement, 3,250,000 restricted shares of our common stock.
·During the three months ended June 30, 2011, we issued and sold to 17 investors an aggregate of 1,584,000 shares of our common stock at a per share purchase price from $0.10 to $0.25 for proceeds of $180,000.
·On June 28, 2011, we issued and sold to one investor 40,000 shares of our common stock at a per share purchase price of $0.25 for proceeds of $10,000.
·On October 25, 2011, we issued and sold to four investors an aggregate of 18,800 shares of our common stock at a per share purchase price of $0.50 for proceeds of $9,400.
·During the three months ended December 31, 2011, we issued a total of 30 Bridge Units (the “Units”) to 29 investors for an aggregate of $750,000 (the “Offering”). Each Bridge Unit is comprised 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 or (ii) within two business days following the close of any debt or equity financing totaling $3,000,000 or more. We extended the repayment of the Bridge Notes for the Extension Period, and the Bridge Notes were due to be paid on January 30, 2012. 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. We 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”): ViewTrade Securities, Inc.; MLV & Co., LLC; Park City Capital, Inc.; I-Bankers Securities, Inc.; Halcyon Cabot Partners, Ltd.; Gentry Securities, LLC (f/k/a Beige Securities, LLC); and Aegis Capital Corp. Under such Placement Agent Agreements, we paid to such broker-dealers (1) a placement agent fee equal to 5% of the gross proceeds from sales of Units by such broker-dealer; 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 Company has extended the repayment of the Bridge Notes for the Extension Period, and the Bridge Notes are due to be paid on November 30, 2011. HCF and an affiliate of HCF purchased an aggregate of 12 Units in the Offering.
·On November 11, 2011, we entered into a Loan Terms Agreement (the “Loan Term Agreement”) with High Capital Funding, LLC (“HCF”) pursuant to which we have issued to HCF an aggregate of $593,000 secured loans bearing interest at the rate of 6.25% per year and maturing on February 29, 2012 (the “Secured Loans”). The Secured Loans are secured with the same collateral securing the Bridge Notes but are subordinate to the Bridge Notes. The Secured Loans shall be prepaid at the final closing of any equity and/or debt financing of at least $3,000,000 which occurs after November 30, 2011; provided, however, that any remaining outstanding Bridge Notes shall be repaid prior to the repayment of any of HCF’s Secured Loans. Under the Loan Term Agreement and in lieu of equity kicker shares as provided for investors in the Offering, HCF is also received five-year cashless exercise warrants to purchase 591,000 shares of our common stock at par value; provided, however, that (i) the exercise terms of the warrants restrict HCF from being the beneficial owner of more than 9.5% of our common stock immediately following any warrant exercise; and (ii) each warrant is deemed to have a value for tax purposes of $0.10 per share.
·As of December 12, 2011, we entered into a Third Secured Loan Agreement with HCF and one other investor pursuant to which we have issued $55,000 in secured notes to HCF and a $75,000 secured note to the other investor (collectively, the “SLA3 Notes”). The SLA3 Notes are secured by the same collateral securing the Bridge Notes and the Secured Loans, and are subordinate to the Bridge Notes and pari pasu with the Secured Loans, and are secured by a first lien on our well servicing and workover rig. The SLA3 Notes are payable at 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, and 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. In addition to the SLA3 Notes and pursuant to the Third Secured Loan Agreement, (i) HCF received five year warrants to purchase 55,000 shares of our common stock at par value; provided, however, that (a) the exercise terms of the warrants restrict HCF from being the beneficial owner of more than 9.5% of our common stock immediately following any warrant exercise; and (b) each warrant is deemed to have a value for tax purposes of $0.10 per share; and (ii) the other investor was issued 75,000 shares of our common stock.
·On January 27, 2012, we (i) agreed to issue to the Plaintiffs the Settlement Shares; and (ii) further agreed that within 30 calendar days of the removal of the DTC Global Lock, we will issue each Plaintiff an individual two-year warrant for the purchase of a number of shares of the Company's common stock equal to the number of Settlement Shares received by that individual Plaintiff, with an exercise price of $0.70 per share, in exchange for the dismissal of the litigation described under Item 3. Legal Proceedings.
·In January 2012, we issued and sold to 3 investors 232,000 shares of our common stock at a per share purchase price of $0.25 for proceeds of $58,000, and 60,000 shares of common stock to 1 entity for services provided, valued at $30,000.
·In March 2012, we issued and sold to 12 investors 360,000 shares of our common stock at a per share purchase price of $0.25 for proceeds of $90.000.
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 three principal projects: development of oil & gas interests in the Williston Basin; development of CBM in the Cook Inlet Basin in Alaska; and implementation of vertical-axis wind turbine power generation technology for the production of clean, cost-efficient green energy throughout the USA, including Alaska and all U.S. 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, 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, 2011, the Company has accumulated losses of $27,274,793.
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, 2011 and 2010. 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, 2011 and 2010, 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, 2011 and 2010. 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 and $81,683, net of tax, or $0.00 per share during the year ended December 31, 2010 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.
Other Income
During the years ended December 31, 2011 and 2010, we received proceeds from the sale of oil from two wells on our sites in the amount of $111,606 and $21,174 respectively, included as other income on the statement of operations. 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.
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.
At December 31, 2011, the significant components of the deferred tax assets (liabilities) are summarized below:
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.
Reclassification
Certain reclassifications have been made in prior year’s financial statements to conform to classifications used in the current year.
Results of Operations for the Twelve Months Ended December 31, 2011 and 2010
Revenues
We have operated as a development stage company for the twelve months ended December 31, 2011 and 2010 and have generated no revenues.
Operating Expenses
Selling, General and Administrative
Selling, general and administrative expenses increased from $1,232,186 for the twelve months ended December 31, 2010 to $5,541,365 for the twelve months ended December 31, 2011. The increase of $4,309,179 or 349% is primarily attributable to an increase in field operations expenses as we mobilized to the Montana field site and began the Five-Well Program as well as an increase in equity based compensation to consultants and service providers.
Impairment of undeveloped properties
Impairment of undeveloped properties in the current fiscal year increased from $81,683 for the twelve months ended December 31, 2010 to $690,552 for the twelve months ended December 31, 2011. This increase of $608,869 is attributed to an increased investment in our undeveloped properties.
Impairment of acquired licenses
Impairment of acquired licenses in the current fiscal year decreased from $2,500,000 for the twelve months ended December 31, 2010 to $0 for the twelve months ended December 31, 2011. This decrease of $2,500,000 is attributed to the non-cash impairment of the licensing agreement to reduce the carrying value to its fair value in the prior year.
Loss on repossession of fixed assets
Loss on repossession of fixed assets in the current fiscal year decreased from $56,622 for the twelve months ended December 31, 2010 to $0 for the twelve months ended December 31, 2011. This decrease is attributed to the return of certain vehicles owned, but financed by the Company due to the inability to make timely payments or negotiate a settlement with such financial institutions in the prior year.
Depreciation and Amortization
In the twelve months ended December 31, 2011, depreciation and amortization increased by $31,039 from $128,555 for the twelve months ended December 31, 2010 to $158,594 for the twelve months ended December 31, 2011. The increase is attributable to the depreciation on the additional field equipment purchased during the year ended December 31, 2011.
Total Operating Expenses
Total operating expenses increased to $6,391,511 for the twelve months ended December 31, 2011 from $3,999,046 for the twelve months ended December 31, 2010. The increase of $2,392,465 primarily attributable to (i) an increase in field operations expenses as we mobilized to the Montana field site and began the Five-Well Program; (2) an increase in equity based compensation to consultants and service providers; (iii) an increase in the amount of impairment of undeveloped properties for the twelve months ended December 31, 2011 as compared to the twelve months ended December 31, 2010; (iv) a decrease in the non-cash impairment of the licensing agreement; (v) a decrease due to loss on repossession of fixed assets; and (vi) and an increase in depreciation and amortization attributable to the additional field equipment purchased during the year ended December 31, 2011.
Gain on Settlement of Debt
Gain on settlement of debt for the twelve months ended December 31, 2011 increased from $0 for the twelve months ended December 31, 2010 to $62,002 for the twelve months ended December 31, 2011. The revenue was a result of cancellation of debt in the sum amount of $62,002 representing various non-recurring events during the current year.
Other Income
Other income for the twelve months ended December 31, 2011 increased from $64,274 for the twelve months ended December 31, 2010 to $111,606 for the twelve months ended December 31, 2011. The revenue was from the sale of oil collected as a byproduct of well testing in the amount of $111,606.
Interest Expenses, net
Interest expense, net for the twelve months ended December 31, 2011 increased by $480,787 to $550,161 from $69,374 for the twelve months ended December 31, 2011. The increase in interest expense was due to issuing common shares in connection with our bridge financing charged to period interest.
Net (Loss)
Net loss for the twelve months ended December 31, 2011 increased to $6,767,737 from a net loss of $4,003,071 for the twelve months ended December 31, 2010. The increase of $2,764,666 is primarily attributable to the following factors: (i) an increase in field operations expenses as we mobilized to the Montana field site and began the Five-Well Program; (2) an increase in equity based compensation to consultants and service providers; (iii) an increase in the amount of impairment of undeveloped properties for the twelve months ended December 31, 2011 as compared to the twelve months ended December 31, 2010; (iv) a decrease in the non-cash impairment of the licensing agreement; (v) a decrease due to loss on repossession of fixed assets; and (vi) and an increase in depreciation and amortization attributable to the additional field equipment purchased during the year ended December 31, 2011.
Liquidity, Capital Resources and Going Concern
We did not generate any revenues in the year ended December 31, 2011, although we did account for Other Income of $111,606 resulting from the sale of oil produced from primarily two wells during the first phase of our Five Well Program which commenced in August 2011. 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.
Further, on May 27, 2010, DTC suspended trade & settlement services (also known as a global lock) on our common stock, preventing us from receiving any commitment from any source of capital that will allow us to meet our minimum capital requirements, which are estimated at $4,300,000, to expand to our full capabilities. Although our management is diligently working on having this global lock removed, there can be no assurance that we will be successful. Investors are cautioned that our shares are ineligible for delivery, transfer or withdrawal through the DTC system in secondary trading until the global lock is removed by DTC. Our shares may still trade in certificate form.
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, 2011 we had a working capital deficit of $4,933,325. For the twelve months ended December 31, 2010, we generated a net cash flow deficit from operating activities of $911,229, consisting primarily of year to date loss of $6,767,737. Non cash adjustments included $159,594 in depreciation and amortization charges, $690,552 in impairment losses, $3,199,692 for equity based compensation, $62,002 gain on settlement of debt, $374,769 for common stock issued in connection with debt, and $75,789 for the fair value of warrants issued in connection with debt. Additionally, we had a net decrease in assets of $131,590 and a net increase in current liabilities of $2,785,341. A net cash flow deficit from investing activities for the twelve months ended December 31, 2011 totaled $905,297, consisting of investment in oil and gas properties and purchase of property and equipment. Cash provided by financing activities for the twelve months ended December 31, 2011 totaled $1,828,433, 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 April 16, 2012, 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 2012.
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, 2010, 2009, and 2008, and have no 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
We issued 2,000,000 shares of our common stock to Windaus and undertook the obligation to pay an additional $500,000 in cash consideration for the exclusive manufacturing, marketing, sales, sublicensing and distribution rights for Windaus’ proprietary vertical axis wind turbine energy systems. This license was granted pursuant to a March 2010 amendment to our Technology License and Distribution Agreement, dated February 17, 2007, with Windaus. The total acreage covered under this exclusive license agreement is approximately 2.3 billion acres and covers the entire United States, including Alaska and all Native American lands in the United States. The exclusive license also applies to all wind turbine products and systems developed by Windaus. While the terms of payment of the $500,000 were not definitively memorialized in the March 2010 amendment, it is contemplated to involve partial payment if and when we receive funding and/or when we have generated sufficient cash flow from net income. The commitment is contemplated to be paid in full by March 31, 2012; and, since March 2010, we have made payments totaling $30,500, leaving a current outstanding balance due under this commitment of $469,500. Despite the outstanding balance due, we have been granted full and complete use of the license by Windaus.
Among other debts, as of December 31, 2011, we owed:
·Bridge Notes Payable of an aggregate of $680,755, net of debt discounts, 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 12.25% per year;
·Loans payable of an aggregate of $509,568, net of debt discounts, 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 are due on February 29, 2012; and
·SLA Notes payable of $97,368, net of debt discounts, 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) a first lien on our workover and well-servicing rig, 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.
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, 2011. 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, 2011.
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, 2011 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, 2011 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, 2011 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, 2011. 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.
Name
Age
Position
Joseph G. D’Arrigo
President, Chief Executive Officer and Chairman
Raj S. Nanvaan
Chief Financial Officer, Chief Operations Officer,
Vice President, Treasurer and Director
Richard Ross
Corporate Secretary, Chief Communications Officer and Director
Doyle A. Johnson
Chief Geologist & Petroleum Engineer
Linda C. Chontos
Administrative Operations Officer
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, 2011 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, 2011 and 2010, 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 2011, collectively referred to as the “Named Executive Officers.”
Summary Compensation Table
(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.
Members of the Board do not receive compensation but are entitled to reimbursement of their expenses incurred in attending Board meetings.
As of April 16, 2012, we have not granted any Stock Awards under our 2011 Equity Incentive Plan.
Employment Contracts
Currently, we do not have employment agreements with any of its employees.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
The following table sets forth, as of April 5, 2012, 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., 108-18 Queens Blvd., Suite 901, Forest Hills, 11375.
(1)Based on 36,387,336 shares of Common Stock outstanding as of April 5, 2012. 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 April 5, 2012.
(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)Maurice Deschamps, the President of Windaus Energy, Inc., has control of the voting and dispositive rights for the shares held by Windaus Energy, Inc.
(7)Includes 648,000 warrants which are exercisable within 60 days of April 5, 2012, 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, only 478,112 warrants are exercisable as of the Record Date.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
As of December 31, 2011, Joseph D’Arrigo has a loan outstanding to us of $11,050, and Raj Nanvaan has a loan outstanding to us of $86,083.24. 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. 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 and well-servicing 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 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.
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 2011 and 2010:
(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: April 16, 2012 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:
Dated: April 16, 2012 /s/ Joseph G. D’Arrigo
Name: Joseph G. D’Arrigo
Title: President, CEO and Director
(Principal Executive Officer)
Dated: April 16, 2012 /s/ Raj S. Nanvaan
Name: Raj S. Nanvaan
Title: Chief Financial Officer and Director
(Principal Accounting Officer)
Dated: April 16, 2012 /s/ Richard Ross
Name: Richard Ross
Title: Director
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.
Forest Hills, 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, 2011 and 2010 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 the above present fairly, in all material respects, the financial position of Native American Energy Group, Inc. as of December 31, 2011 and 2010 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 2012. 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
April 16, 2012
NATIVE AMERICAN ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2011 AND 2010
See the accompanying notes to the consolidated financial statements
NATIVE AMERICAN ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(a development stage company)
See the accompanying notes to the consolidated financial statements
NATIVE AMERICAN ENERGY GROUP, INC
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (DEFICIT)
(a development stage company)
FROM JANUARY 18, 2005 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2011
See the accompanying notes to the consolidated financial statements
NATIVE AMERICAN ENERGY GROUP, INC
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (DEFICIT)
(a development stage company)
FROM JANUARY 18, 2005 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2011
See the accompanying notes to the consolidated financial statements
NATIVE AMERICAN ENERGY GROUP, INC
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (DEFICIT)
(a development stage company)
FROM JANUARY 18, 2005 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2011
See the accompanying notes to the consolidated financial statements
NATIVE AMERICAN ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
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 using enhanced oil recovery capabilities, revitalizes abandoned oil fields which were previously developed and capped. 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, LLC, are our operating entities in 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, 2011, the Company has accumulated losses of $27,274,793.
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, 2011 and 2010. 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, 2011 and 2010, 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 years ended December 31, 2011 and 2010. 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 and $81,683, net of tax, or $0.00 per share during the year ended December 31, 2010 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. The management has estimated value of these rights $2,500,000.
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.
Other Income
During the years ended December 31, 2011 and 2010, we received proceeds from the sale of oil from two wells on our sites in the amount of $111,606 and $21,174 respectively, included as other income on the statement of operations. 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.
Stock-Based Payments
The Company follows the Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”), which requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. This statement does not change the accounting guidance for share-based payment transactions with parties other than employees provided in ASC 718-10. The Company implemented AC 718-10 on January 1, 2006 using the modified prospective method.
As of December 31, 2011 and 2010, there were no outstanding employee stock options.
Fair Values
The Company follows the Accounting Standards Codification subtopic 820-10, Fair Value Measurements and Disclosures (“ASC 820-10”). ASC 820-10 defines fair value, establishes a framework for measuring fair value, and enhances fair value measurement disclosure. ASC 820-10 delays, until the first quarter of fiscal year 2009, the effective date for ASC 820-10 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of ASC 820-10 did not have a material impact on the Company’s financial position or operations.
Advertising Costs
The Company expenses advertising costs as incurred. Advertising expenses are $-0- for the years ended December 31, 2011, 2010 and from January 18, 2005 (date of inception) through December 31, 2011.
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, 2011, 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 preferred stock and warrants, were not considered as including such would be anti-dilutive.
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 $6,767,737 and $4,003,071 for the years ended December 31, 2011 and 2010, respectively. The Company has incurred significant losses and has an accumulated deficit of $27,274,793 at December 31, 2011. 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 5 to 10 years. Depreciation expense was $159,594, $128,555 and $383,731 for the years ended December 31, 2011 and 2010 and from January 18, 2005 (date of inception) through December 31, 2011 respectively.
During the year ended December 31, 2010, the Company returned certain vehicles owned, but financed by the Company due to the inability to make timely payments or negotiate a settlement payment with such financial institutions. As such, the Company recorded a loss of $56,622 in current period operations representing the remaining book value as of December 31, 2010.
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 $175,030 and $174,703, as of December 31, 2011 and 2010, 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 has an aggregate of $50,000 and $150,000 as of December 31, 2011 and 2010, 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, the Company cancelled one of its oil and gas surety bonds in the amount $100,000 issued to the Alaska Oil & Gas Conservation Commission (“AOGCC”) for its Kircher Unit state drilling permit in Alaska. As a result of the bond termination, the financial institution returned the $100,000 cash collateral to the Company. In the event that the Company re-applies for the state drilling permit with the AOGCC, it will be required to re-post a bond in the amount of $100,000. 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:
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 Company made the rescission offer as it believes that the prior issuances of common stock to such purchasers may have been brokered by unregistered persons and thus may have been made in violation of the Securities Act of 1933, as amended (the “Securities Act”). 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.
As disclosed in our Quarterly Report on Form 10-Q for the quarter ended June 30, 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.
NOTE 9 - 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.
NOTE 10 - 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.
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.
NOTE 11 - 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. As of 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%.
NOTE 12 - STOCKHOLDERS’ EQUITY
Preferred Stock
The Company is authorized to issue 1,000,000 shares of its $0.0001 par value preferred stock. As of December 31, 2011 and 2010, there were 500,000 shares issued and outstanding.
On September 22, 2009, the Company’s Board of Directors designated 1,000,000 shares of its authorized preferred stock to be Series A Convertible Preferred Stock. The general attributes of the Series A Convertible Preferred Stock is as follows:
Dividends. Holders of 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, in any other shares of the Company without the consent of the holders of Series A Convertible Preferred Stock unless and until a dividend of like amount is first paid in full to holders of Series A Convertible Preferred Stock.
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.
On October 23, 2009, in conjunction with the reverse acquisition, the Company issued an aggregate of 500,000 shares of Series A Preferred Stock to principal officers of the Company.
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, 2011 there were 35,128,580 shares issued; 33,389,830 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.
NOTE 13 - COMMITMENTS AND OBLIGATIONS
Overriding Royalty Interests
On April 11, 2005, the principal shareholders 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 space in New York at approximately $4,766 per month. The lease term expired December 31, 2010 and the Company is currently leasing the space on a month to month basis.
2.The Company currently leases office space in Alaska. The lease has a two-year term expiring on February 28, 2013, and the rent is $593 per month.
3.The Company currently leases a maintenance facility in Montana on a month-to-month basis at $1,500 per month.
At December 31, 2011, future minimum lease payments are as follows:
The office lease expenses for the Company’s field offices in Alaska and 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.
On March 15, 2011, the Company amended its agreement with an independent consultant for consulting and advisory services whereby it extended the agreement for one year beginning March 15, 2011 and ending March 14, 2012. Pursuant to the agreement, the consultant’s monthly fee of $3,000, totaling $36,000 per year, was prepaid by issuance of the Company’s common stock.
On May 29, 2011, the Company entered into a Strategic Consulting Agreement with Insource Insight Services, LLC (“Insight”), pursuant to which Insight will, among other things, provide advice to, and consult with, the Company on business planning, financial strategy, financial strategy implementation and corporate structure. The agreement has an initial term of six months commencing on May 16, 2011 and ending on November 15, 2011. On November 3, 2011, the term of the consulting agreement was extended to December 31, 2011. In consideration for the services, the Company issued to Insight a total of 3,250,000 shares of its common stock and agreed to pay to Insight $10,000 per month for the first three months of the agreement and $10,000 per month for each subsequent month subject to certain milestones. The issued shares were valued at $2,827,500 and were recorded as a prepaid expenses amortized over the term of the agreement.
Litigation
Steven Freifeld, et al. v. Native American Energy Group, Inc., et al., Index No. 005503-2010.
On March 19, 2010, Plaintiffs, the putative investors in NAEG Founders Holding Corporation (“Founders”), filed a complaint in the Supreme Court of the State of New York, Nassau County, against us, Joseph D’Arrigo, in his capacity as our President and CEO, Raj Nanvaan, in his capacity as our CFO, COO, Vice President and Treasurer, and others (together, the “Defendants”). We and Messrs. D’Arrigo and Nanvaan were named in this complaint because Messrs. D’Arrigo and Nanvaan are each officers and directors of both us and Founders. Plaintiffs’ complaint alleged, among other things, that we and/or our affiliates and officers have breached fiduciary duties purportedly owed Plaintiffs and committed common law fraud through misrepresentations in the course of soliciting investments. The claims primarily resulted from Founders’ transfer of its fractional ownership of its interests and the sale of some of its royalty interest to third parties (some of which are also Plaintiffs in this proceeding), and the use of the proceeds resulting from such transfer and sale to fund our operating needs of Native American Energy Group. Specifically, the Plaintiffs allege that they invested in one or more of the named entity Defendants based on misleading representations about such entity Defendant’s potential success. Further, the Plaintiffs claimed that the individual Defendants changed the names and/or the states of incorporation under the same name of the entity Defendants without going through the proper corporate formalities. The Plaintiffs also alleged that they were not provided with stock certificates, did not receive any notice of shareholders’ meetings and were denied access to one or more of the entity Defendants’ books and records. Plaintiffs sought an order granting to Plaintiffs certain disclosures, unfettered access to various corporate books and records, and termination of our current officers and directors. Plaintiffs also sought compensatory damages in an amount to be determined at trial, but alleged in the complaint to equal or exceed the amount of their putative investments in us and/or our affiliates.
In an effort to avoid further litigation, we, on behalf of Defendants, have agreed to issue to the Plaintiffs an aggregate of 606,756 shares of our common stock in addition to the 1,738,750 shares already held in escrow for a total of 2,345,506 shares of our Common Stock (the "Settlement Shares"). We have further agreed that within 30 calendar days of the removal of the global lock by DTC, we will issue each Plaintiff an individual warrant. The term of each individual warrant shall be for two years from the date of the removal of the DTC Global Lock (as defined and described under “Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities-Market Information”) and shall be for the purchase of a number of shares of our common stock equal to the number of Settlement Shares received by that individual Plaintiff, with an exercise price of $0.70 per share.
In consideration for the above, the Plaintiffs agreed to dismiss all claims alleged in the lawsuit with prejudice and on January 30, 2012 filed with the Court a Notice of Voluntary Dismissal with Prejudice.
To the best knowledge of management, there are no material litigation matters pending or threatened against us.
NOTE 14 - RELATED PARTY TRANSACTIONS
From January 18, 2005 (date of inception) through December 31, 2011, principal shareholders 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, 2011, Joseph D’Arrigo has a loan outstanding to us of $11,050, and Raj Nanvaan has a loan outstanding to us of $86,083.24. 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, 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 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.
NOTE 15 -STOCK OPTIONS AND WARRANTS
Stock Options
As of December 31, 2011 and 2010, there were no outstanding options.
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, 2011:
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 current period operations.
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.
NOTE 16 - 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, 2011 the Company has available for federal income tax purposes a net operating loss carry forward of approximately $7,500,000 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 17 - SUBSEQUENT EVENTS
Legal Proceeding Update:
On January 27, 2012, we (i) agreed to issue to the Plaintiffs the Settlement Shares; and (ii) further agreed that within 30 calendar days of the removal of the DTC Global Lock, we will issue each Plaintiff an individual two-year warrant for the purchase of a number of shares of the Company's common stock equal to the number of Settlement Shares received by that individual Plaintiff, with an exercise price of $0.70 per share, in exchange for the dismissal of the litigation described under Item 3. Legal Proceedings.
In January 2012, we issued and sold to 3 investors 232,000 shares of our common stock at a per share purchase price of $0.25 for proceeds of $58,000, and 60,000 shares of common stock to 1 company for services provided, valued at $30,000 in aggregate.
In March 2012, we issued and sold to 12 investors 360,000 shares of our common stock at a per share purchase price of $0.25 for proceeds of $90,000.
EXHIBIT INDEX
Exhibit
Number
Description
2.1
Plan of Merger and Merger Agreement entered into October 19, 2009 by and between Flight Management International, Inc. and Native American Energy Group, Inc. (incorporated by reference to Exhibit 2.5 to Amendment No. 1 to Form 10 filed with the SEC on November 16, 2010)
3.1
Certificate of Incorporation of American Entrepreneurial Funding Corp.*
3.2
Certificate of Merger of Franchise Management International, Inc. into American Entrepreneurial Funding Corp.*
3.3
Certificate of Amendment of Certificate of Incorporation of Franchise Management International, Inc.*
3.4
Bylaws of Native American Energy Group, Inc. (incorporated by reference to Exhibit 3.2 to Form 10 filed with the SEC on August 20, 2010)
3.5
Certificate of Designations of Series A Convertible Preferred Stock of Flight Management International, Inc. (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to Form 10 filed with the SEC on November 16, 2010)
3.6
Certificate of Amendment to Certificate of Incorporation of Flight Management International, Inc.*
3.7
Certificate of Merger of Native American Energy Group, Inc. into Flight Management International, Inc.*
10.1
Lease Purchase Agreement, dated September 11, 2006 between Shell Oil Trading (US) Company and Native American Energy Group, Inc. (incorporated by reference to Exhibit 10.1 to Amendment No. 1 to Form 10 filed with the SEC on November 16, 2010)
10.2
Amendment to Lease Purchase Agreement, dated October 24, 2008 between Shell Trading (US) Company and Native American Energy Group, Inc. (incorporated by reference to Exhibit 10.2 to Amendment No. 1 to Form 10 filed with the SEC on November 16, 2010).
10.3
Amendment No. 2 to Lease Purchase Agreement, dated June 1, 2011, between Shell Trading (US) Company and Native American Energy Group, Inc.*
10.4
Technology License and Distribution Agreement dated February 17, 2007 from Windaus Energy, Inc. in favor of Native American Energy Group, Inc. (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to Form 10 filed with the SEC on November 16, 2010)
10.5
First Amendment dated March 8, 2010 to Technology License and Distribution Agreement dated February 17, 2007 from Windaus Energy, Inc. in favor of Native American Energy Group, Inc. (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to Form 10 filed with the SEC on November 16, 2010)
10.6
Summary of Oral Agreement Regarding Schedule of Payments of $500,000 Partial License Fee payable to Windaus Energy, Inc. (incorporated by reference to Exhibit 10.8 to Amendment No. 4 to Form 10 filed with the SEC on March 11, 2011)
10.7
Form of Debt Conversion Agreement (incorporated by reference to Exhibit 10.6 to Amendment No. 3 to Form 10 filed with the SEC on February 1, 2011)
10.8
Payoff Letter dated March 25, 2010 from Dakota Financial, LLC to Native American Energy Group, Inc. (incorporated by reference to Exhibit 10.7 to Amendment No. 3 to Form 10 filed with the SEC on February 1, 2011)
10.9
Native American Energy Group, Inc. 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 7, 2011)
10.10
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 7, 2011)
10.11
Strategic Consulting Agreement between Insource Insight Services, LLC and Native American Energy, Inc. dated May 28, 2011 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 23, 2011)
10.12
Amendment to Strategic Consulting Agreement dated November 3, 2011 between Insource Insight Services, LLC and Native American Energy, Inc.*
10.13
Commercial Proposal dated July 28, 2011 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)**
10.14
Financing Agreement dated as of July 25, 2011 with High Capital Funding, LLC, David A. Rapaport, and investors signatory thereto (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.15
Mortgage, Security Agreement and Financing Agreement dated July 28, 2011, with High Capital Funding, LLC (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.16
Form of Placement Agent Agreement (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.17
Form of Bridge Unit Subscription Agreement (incorporated by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.18
Form of Bridge Unit Investor Representations and Warranties Agreement (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.19
Form of Bridge Note (incorporated by reference to Exhibit 10.7 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.20
Loan Terms Agreement dated as of November 8, 2011 with High Capital Funding, LLC (incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.21
Mortgage, Security Agreement and Financing Agreement dated November 8, 2011, with High Capital Funding, LLC (incorporated by reference to Exhibit 10.9 to our Quarterly Report on Form 10-Q filed with the SEC on November 14, 2011)
10.22
Consulting Agreement with J.R. Bautista dated June 10, 2010, as Amended on March 15, 2011 and May 27, 2011.*
10.23
Third Secured Loan Agreement dated as of December 12, 2011 with High Capital Funding, LLC and the lenders signatory thereto.*
10.24
Form of Warrant to High Capital Funding, LLC*
10.25
Form of Warrant to Placement Agents*
14.1
Code of Business Conduct and Ethics*
21.1
Subsidiaries of the Registrant*
31.1
Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
31.2
Certification of Principal Accounting Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
32.1
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
* Filed herewith
** Confidential Treatment has been requested with respect to certain provisions of this agreement. Omitted portions have been filed separately with the SEC.