Item 1. Business.
Corporate History
We were originally incorporated as Poway Muffler and Brake Inc. in California on August 15, 2003 to enter the muffler and brake business. On December 15, 2008, a merger was effected with Ross Investments Inc., a Colorado shell corporation. Ross Investments was the acquirer and the surviving corporation. Ross Investments Inc. then changed its name to Poway Brake and Muffler Inc. On May 25, 2012, we filed an Amendment to our Certificate of Incorporation by which we changed our name from Poway Muffler and Brake, Inc., a Colorado corporation, to Stratex Oil and Gas Holdings, Inc., with the Secretary of the State of Colorado.
On July 6, 2012, Stratex Acquisition Corp., a wholly-owned subsidiary of Stratex Oil & Gas Holdings, Inc. merged with and into Stratex Oil & Gas, Inc., a Delaware corporation (“Stratex”). Stratex was the surviving corporation of that Merger. As a result of the merger, we acquired the business of Stratex, and continue the business operations of Stratex as a wholly-owned subsidiary.
Business Model
We are an independent energy company focused on the exploration, acquisition and production of crude oil in North Dakota, Montana, Colorado, Kansas, and Nebraska. Our oil and natural gas operations are primarily concentrated in the Williston Basin of North Dakota and Montana and the Denver-Julesburg Basin in Colorado. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects, and evaluate those prospects using subsurface geology, geophysical data and exploratory drilling. Using this strategy, we intend to develop an oil portfolio of proven reserves, as well as developmental and exploratory drilling opportunities.
Our core operating areas are in the Williston Basin in North Dakota and Montana and the Denver-Julesburg Basin in Colorado. In the Williston Basin, we focus on oil production from multiple zones including the Bakken Shale, and Three Forks Sanish Formations. In the Denver-Julesburg Basin we focus on the Niobrara Formations.
We use geologists, petroleum engineers and geophysicists that have years of relevant industry experience in the basins where we operate.
We explore and produce oil and gas through a non-operator business model. We participate in wells proportionately to the leasehold interest in each drilling unit that is drilled by its operating partners. As a non-operating participant we seek to minimize operating and overhead costs, however, we are liable for our share of the operating and capital costs incurred for each property by its operator. This low-cost model allows us to diversify through different operators and regions. We operate 1 oil well known as Tininenko 4-19 in Roosevelt County MT. At its discretion management may decide to acquire additional operating assets.
Operations
Our management team has structured our operations in a manner that minimizes operating and overhead costs as a leasehold interest owner. As a non-operating participant, we intend to rely on operating partners to conduct the drilling process and to bear operating and overhead costs, which should allow us to invest the highest possible working interest while minimizing costs.
Drilling and Acreage Plans
Our primary focus is acquiring leasehold interests in the Bakken Formation, Three Forks-Sanish Formation, and Niobrara Formation.
The Bakken Formation
The Bakken Formation is an oil-bearing strata underlying parts of the Williston Basin of Montana and North Dakota. The Bakken is located between 8,000 and 11,000 feet below surface and is comprised of three members: the lower shale, middle dolomite, and upper shale. The middle member holds the majority to the oil reserves. Oil production in this region dates back to the 1950s, but was largely unsuccessful. The vertical wells drilled around this time couldn’t produce oil at high rates. The vertical wells only had about 50 to 100 feet of the shaft that reached the middle Bakken. The application of horizontal wells with fracturing technology has allowed production to dramatically increase.
Niobrara Formation
The Niobrara Formation is a shale rock underlying parts of Colorado and Wyoming. Oil and natural gas can be found at depths from 3,000 to 14,000 feet. The Niobrara is a new oil formation that is part of the Denver-Julesburg basin. Oil exploitation activities in the Niobrara formation have recently begun. The performance of the Niobrara and Bakken are being compared as part of the operators’ evaluation procedures.
The Three Forks-Sanish Formation
The Three Forks-Sanish Formation is an oil area below the Bakken Shale zone.
Drilling
Hydraulic Fracturing
Hydraulic Fracturing is a technique that can increase the flow of oil or gas from a well. The procedure is done by pumping high quantities of liquid down a well into the reservoir rock at a high pressure to fracture the rock. The technique creates a network of interconnected fractures that allow more oil to flow through the rock.
Horizontal Drilling
Horizontal Drilling is useful in reaching targets and stimulating reservoirs in ways that cannot be achieved with vertical wells. A rock unit that is only 50 feet thick is limited to a pay zone that is 50 feet in length with a vertical well. A well drilled horizontally can expand the limited pay zone thousands of feet. Also, horizontal drills can deliberately intersect fractures. The productivity of these wells can be increased tremendously with the use of horizontal drills.
Marketing and Customers
As a non-operator, we intend to rely on outside operators for the transportation, marketing/sales and account reporting for all production. The operators of our wells will be responsible for the marketing and sales of all production to regional purchasers of petroleum products, and we intend to evaluate the credit worthiness of those purchasers periodically.
Disclosure of Reserves
Below is a summary of oil and gas reserves as of the fiscal-year ended December 31, 2012.
Our proved oil and natural gas reserves are all located in the United States, primarily in the Bakken and the Williston Basin in Montana. The reservoir engineering reports used in this Report on Form 10-K is calculated as of December 31, 2012. The estimates of proved reserves at December 31, 2012 are based on reports prepared by LaRoche Petroleum Consultants, Ltd. (the “Engineering Reports”). Proved reserves were estimated in accordance with the guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”).
Proved reserves and future net revenue to the evaluated interests were based on economic parameters and operating conditions considered applicable as of December 31, 2012 and are pursuant to the financial reporting standards of the SEC and prepared in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The reserves projections in this evaluation are based on the use of the available data and accepted industry-engineering methods.
Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process
Our policies regarding internal controls over the recording of reserves estimates requires reserves to comply with the SEC definitions and guidance and be prepared in accordance the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. Our procedures require that our reserve report be prepared by a third-party registered independent engineering firm at the end of every year based on information we provide to such engineer. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer and Chief Financial Officer provide a final review of our reserve report and the assumptions relied upon in such report.
William M. Kazmann, Petroleum Engineer and Geological Advisor, was our third party reserve engineer for the preparation of our reserve reports for the past 2 years. Mr. Kazmann has been a petroleum engineering and geological advisor for more than 34 years with multi-disciplinary experience in the oil and gas industry. He meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Proved Undeveloped Reserves
As of December 31, 2012, there were 1,088 (Barrels) of oil and 1,183 (Mcf) of gas in undeveloped reserves.
During fiscal year 2012, we focused primarily on the acquisition of existing wells properties. As a result, investment in converting proved undeveloped reserves to proved developed reserves was limited.
Oil and Gas Production, Production Prices and Production Costs
Oil and Gas Production
The following table summarizes the production of oil and natural gas by geographical area for the fiscal year ended December 31, 2012.
The following table summarizes gross and net productive oil wells by state as of December 31, 2012.
Production Prices
The following table summarizes the average sales price per unit of oil and natural gas by geographical area for the fiscal year ended December 31, 2012:
(a)
We used the 12 month first day of the month unweighted average prices realized as a basis for all oil calculations and Henry Hub natural gas spot price for gas.
The following table summarizes the weighted average prices utilized in the reserve estimates for 12/31/12 as adjusted for location, grade and quality:
(a)
The pricing used to estimate our December 31, 2012 reserves were based on a 12-month unweighted average realized price as adjusted for location, grade and quality.
Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
Average production costs per BOE including ad valorem and severance taxes were $19.78 in 2012. Excluding severance taxes, production costs per BOE were $9.58.
Dry Holes
Through the date of this Report on 10-K, we experienced zero dry holes.
Drilling Activity and other Exploratory and Development Activities
Productive and Exploratory Wells Drilled
In the fiscal year ended December 31, 2012, operators drilled and completed 3 gross and net exploratory wells on our leaseholds.
Productive and Dry Development Wells Drilled
In the fiscal year ended December 31, 2012, we participated on a non-operated basis in 21 gross and 1.31 net development wells on minority working interest acreage.
Present Activities
We currently have 4 wells that are in the process of being drilled in Billings County, North Dakota.
Delivery Commitments
We do not currently have any delivery commitments for product obtained from our wells.
Oil and Gas Properties, Wells, Operations and Acreage
The following table summarizes as of December 31, 2012, the total gross and net productive wells, expressed separately for oil and gas and the total gross and net developed acreage (i.e., acreage assignable to productive wells).
The following table summarizes as of December 31, 2012, the amount of undeveloped leasehold acreage expressed in both gross and net acres by geographic area and the minimum remaining terms of leases and concessions.
As of December 31, 2012, we have approximately 14,287 net acres in Sheridan County, Roosevelt County, Montana, Williams County, Divide County, Mountrail County, Golden Valley County, and Stark County, North Dakota, Sioux County, Nebraska, and Lane County Kansas. The expiration of the majority of these leases ranges from 3 to 5 years and in some instances, the acreage has additional options to extend the lease maturity. We do not own the majority working interest in this acreage, nor do we have any ability to influence the potential development of this acreage within the terms of the lease. We are currently evaluating our options to selectively drill some of these leases to hold this acreage by production.
Our non-operated minority interest acreage is primarily not held by production as of today, with 14,261 of our 14,834 net acres undeveloped or subject to drilling in progress. Our acreage exposure is very granular; we hold 8 leases with a typical working or royalty interest ranging from less than 1% to 20%. We hold approximately 14,261 net acres that expire from 2014 to 2019 with the majority of the leases not having any extension options.
Competitive Advantage
We believe our competitive advantage is our streamlined operating model, which we believe may enable us to grow leasehold acquisition and acreage development at an accelerated pace in the future. We intend to utilize our capital to expand our lease holdings and contract with third party operators to drill our majority working interest leasehold acreage. By eliminating the staffing required to manage this process internally, we reduce our fixed employee cost structure and overhead. Further, utilizing a non-operator business model, we are not limited in acquisition size of leasehold acreage and participation. Therefore, we believe we have more opportunity to acquire smaller, but more numerous, leasehold acreage in and around prolific areas which, although beneficial to us, are not preferred by larger, operating-oriented companies.
Employees
We currently have a full-time staff of 2 employees. We may selectively increase staff during 2013, anticipated to be in the area of land acquisition and accounting personnel.
Environmental Matters
The operations of our properties are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We and our operating partners maintain insurance against costs of clean-up operations, but we and our operating partners are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.
Public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, in March 2010, the Environmental Protection Agency (the “EPA”) announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. According to the EPA’s website, “some energy extraction activities, such as new techniques for oil and gas extraction and coal mining, pose a risk of pollution of air, surface waters and ground waters if not properly controlled.” To address these concerns, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. This initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our operating partners’ facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us and/or our operating partners.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of the operations of our properties, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that our operating partners are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.
The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:
Hazardous Substances and Wastes. CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Resource Conservation and Recovery Act (“RCRA”) generally does not regulate wastes generated by the exploration and production of natural gas and oil. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. An environmental organization recently petitioned the EPA to reconsider certain RCRA exemptions for exploration and production wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
We lease onshore properties that for a number of years have been used for or associated with the exploration and production of natural gas and oil. Although our operating partners may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, these properties, prior to our obtaining an interest therein, may have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the CWA, the RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.
Waste Discharges. The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment beams and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. We believe that the operations of our properties are in substantial compliance with the CWA for the well that we operate.
On February 16, 2012, the EPA issued the final 2012 construction general permit (“CGP”) for storm water discharges from construction activities involving more than one acre, which will provide coverage for a five year period. The 2012 CGP modifies the prior CGP to implement the new Effluent Limitations Guidelines and New Source Performance Standards for the Construction and Development Industry. The new rule includes new and more stringent restrictions on erosion and sediment control, pollution prevention and stabilization, although a numeric turbidity limit for certain larger construction sites has been stayed as of January 4, 2011.
Air Emissions. The CAA and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants and greenhouse gases (“GHGs”) have been developed by the EPA and may increase the costs of compliance for some facilities.
Oil Pollution Act. The Oil Pollution Act of 1990, as amended (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.
Endangered Species Act. The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that our operations are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
Worker Safety. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
Hydraulic Fracturing. Our operating partners ordinarily use hydraulic fracturing as a means to maximize the productivity of our oil and gas wells in the basins in which our properties are located. Our net acreage position in the basins in which hydraulic fracturing is utilized total approximately 22,337 net acres and represents approximately 100% of our domestic proved undeveloped oil and gas reserves. The average drilling and completion costs for each basin will vary, as will the cost of each well within a given basin. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget.
The protection of groundwater quality is extremely important to us. We intend to require that our operating partners follow applicable standard industry practices and legal requirements for groundwater protection in operating our wells. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (BLM) with respect to federal acreage), which conduct many inspections during operations that include hydraulic fracturing. Industry standards and legal requirements for groundwater protection focus on five principal areas: (i) pressure testing of well construction and integrity, (ii) lining of pits used to hold water and other fluids used in the drilling process isolated from surface water and groundwater, (iii) casing and cementing practices for wells to ensure separation of the production zone from groundwater, (iv) disclosure of the chemical content of fracturing liquids, and (v) setback requirements as to the location of waste disposal areas. The legal requirements relating to the protection of surface water and groundwater vary from state to state and there are also federal regulations and guidance that apply to all domestic drilling. In addition, the American Petroleum Institute publishes industry standards and guidance for hydraulic fracturing and the protection of surface water and groundwater. Our policy and practice will be to require our operating partners to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing.
In addition to the required use of and specifications for casing and cement in well construction, we expect that our operating partners will observe regulatory requirements and what they consider best practices to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These may include some or all of the following:
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Prior to perforating the production casing and hydraulic fracturing operations, the casing is pressure tested.
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Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all pressurized lines and connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, specialized equipment is utilized to monitor and record surface pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Should any problem be detected during the hydraulic fracturing treatment, the operation is shut down until the problem is evaluated, reported and remediated.
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As a means to protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing operation, special precautions are taken to ensure proper containment and storage of fluids. For example, any earthen pits containing non-fresh water must be lined with a synthetic impervious liner. These pits are tested regularly, and in certain sensitive areas have additional leak detection systems in place. At least two feet of freeboard, or available capacity, must be present in the pit at all times. In addition, earthen berms are constructed around any storage tanks, any fluid handling equipment, and in some cases around the perimeter of the location to contain any fluid releases. These berms are considered to be a “secondary” form of containment and serve as an added measure for the protection of groundwater.
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Conduct baseline water monitoring in certain of the basins in which hydraulic fracturing is used:
o
In Colorado, baseline water monitoring may be required by the Colorado Oil and Gas Conservation Commission (“COGCC”) or BLM as a condition of approval for the drilling permit, but otherwise it is not a requirement. Industry worked with the Colorado Oil & Gas Association as well as the COGCC to adopt a voluntary baseline groundwater quality sampling program. Our operating partner in Colorado has committed to the program that went into effect in August 2011.
o
There are currently no regulatory requirements to conduct baseline water monitoring in the Bakken Shale. We expect our operating partners to voluntarily conduct water monitoring in the Bakken Shale.
Once a pipe is set in place, cement is pumped into the well where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design essentially eliminates a “pathway” for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. Furthermore, in the basins in which our operating partners may conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable underground aquifers by thousands of feet of impermeable rock layers. This wide separation serves as a protective barrier, preventing any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones.
In addition, the vendors our operating partners may employ to conduct hydraulic fracturing will likely be required to monitor all pump rates and pressures during the fracturing treatments. This monitoring typically occurs on a real-time basis and data is recorded to ensure protection of groundwater.
The cement and steel casing used in well construction can have rare failures. Any failure in isolation is reported to the applicable oil and gas regulatory body. A remediation procedure is written and approved and then completed on the well before any further operations or production is commenced. Possible isolation failures may result from:
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Improper cementing work. This can create conditions in which hydraulic fracturing fluids and other natural occurring substances can migrate into the surrounding geological formation. Production casing cementing tops and cement bond effectiveness are evaluated using either a temperature log or an acoustical cement bond log prior to any completion operations. If the cement bond or cement top is determined to be inadequate for zone isolation, remedial cementing operations are performed to fill any voids and re-establish integrity. As part of this remedial operation, the casing is again pressure tested before fracturing operations are initiated.
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Initial casing integrity failure. The casing is pressure tested prior to commencing completion operations. If the test fails due to a compromise in the casing, the applicable oil and gas regulatory body will be notified and a remediation procedure will be written, approved and completed before any further operations are conducted. In addition, casing pressures are monitored throughout the fracturing treatment and any indication of failure will result in an immediate shutdown of the operation.
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Well failure or casing integrity failure during production. Loss of wellbore integrity can occur over time even if the well was correctly constructed due to downhole operating environments causing corrosion and stress. During production, the bradenhead, casing and tubing pressures are monitored and a casing failure can be identified and evaluated. Remediation could include placing additional cement behind casing, installing a casing patch, or plugging and abandoning the well, if necessary.
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Fluid “leakoff” during the fracturing process. Fluid leakoff can occur during hydraulic fracturing operations whereby some of the hydraulic fracturing fluid flows through the artificially created fractures into the micropore or pore spaces within the formation, existing natural factures in the formation, or small fractures opened into the formation by the pressure in the induced fracture. Fluid leakoff is accounted for in the volume design of nearly every fracturing job and “pump-in” tests are often conducted prior to fracturing jobs to estimate the extent of fluid leakoff. In certain situations, a very fine grain sand is added in the initial part of the treatment to seal-off any small fractures of micropore spaces and mitigate fluid leak-off.
Approximately 99% of hydraulic fracturing fluids are made up of water and sand. Our operating partners utilize major hydraulic fracturing service companies whose research departments conduct ongoing development of “greener” chemicals that are used in fracturing. Our operating partners evaluate, test, and where appropriate adopt those products that are more environmentally friendly.
Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate are considering Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) bills and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. If the exemption for hydraulic fracturing is removed from the SDWA, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.
Federal agencies are also considering regulation of hydraulic fracturing. The EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, the EPA’s interpretation without formal rule making has been challenged and industry groups have filed suit challenging the EPA’s interpretation. If the EPA prevails in this lawsuit, its interpretation could result in enforcement actions against service providers or companies that used diesel products in the hydraulic fracturing process or could require such providers or companies to conduct additional studies regarding diesel in the groundwater.
On October 21, 2011, the EPA announced its intention to propose regulation by 2014 under the CWA to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The EPA is also collecting information as part of a study into the effects of hydraulic fracturing on drinking water. The results of this study, expected in late 2012, could result in additional regulations, which could lead to operational burdens similar to those described above.
In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a report on hydraulic fracturing in August 2011. The report concludes that the risk of fracturing fluids contaminating drinking water sources through fractures in the shale formations “is remote.” It also states that development of the nation’s shale resources has produced major economic benefits. The report includes recommendations to address concerns related to hydraulic fracturing and shale gas production, including but not limited to conducting additional field studies on possible methane leakage from shale gas wells to water reservoirs and adopting new rules and enforcement practices to protect drinking and surface waters. The Government Accountability Office is also examining the environmental impacts of produced water and the Counsel for Environmental Quality has been petitioned by environmental groups to develop a programmatic environmental impact statement under the National Environmental Policy Act for hydraulic fracturing. The United States Department of the Interior is also considering whether to impose disclosure requirements or other mandates for hydraulic fracturing on federal land.
Several states, including Colorado and North Dakota, have adopted or are considering adopting, regulations that could restrict or impose additional requirements related to hydraulic fracturing. Since June 2009, Colorado has required all operators to maintain a chemical inventory by well site for each chemical product used downhole or stored for use downhole during drilling, completion and workover operations, including fracture stimulation in an amount exceeding 500 pounds during any quarterly reporting period. Colorado adopted its final hydraulic fracturing chemical disclosure rules on December 13, 2011. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.
Global Warming and Climate Change. Recent scientific studies have suggested that emissions of Green House Gases (GHGs), including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. Both houses of Congress have previously considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The EPA has begun to regulate GHG emissions. On December 7, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. EPA issued a final rule that went into effect in 2011 that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions. On November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Several of the EPA’s GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact our operations. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources and may increase our litigation risk for such claims. New legislation or regulatory programs that restrict emissions of or require inventory of GHGs in areas where we operate may adversely affect our operations by increasing costs.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas or otherwise cause us to incur significant costs in preparing for or responding to those effects.
Item 1A.
Item 1A. Risk Factors.
I. Risks Related to our Business
We are an early stage company. We are a non-operator oil and natural gas company. We may never attain profitability.
The business of acquiring, exploring for, developing and producing oil and natural gas reserves is inherently risky. We have a limited operating history for you to consider in evaluating our business and prospects. Our operations are therefore subject to all of the risks inherent in acquiring, exploring for, developing and producing oil and natural gas reserves, particularly in light of our limited experience in undertaking such activities, including:
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our ability to raise adequate working capital;
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success of our development and exploration;
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demand for natural gas and crude oil;
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the level of our competition;
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our ability to attract and maintain key management and employees;
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our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or crude oil in a highly competitive and speculative environment while maintaining quality and controlling costs; and
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Availability of leases at competitive rates and in locations that actually have oil that is recoverable.
We may never overcome these obstacles.
Our lack of diversification will increase the risk of an investment in us and our financial condition and results of operations may deteriorate if we fail to diversify.
Our business is focused on a limited number of properties in the Williston Basin of North Dakota and Montana, Denver-Julesburg Basin of Colorado and the Green River basin of Wyoming. We do not intend to limit our focus to any single geographic area because we want to remain flexible and intend to pursue the best opportunities available to us, which may be outside Montana, North Dakota, and Wyoming as well. We expect to commit funds to joint venture partners to acquire and develop drilling facilities on our leased acreage.
Our required capital commitment may grow if the opportunity presents itself and depends upon the results of initial testing and development activities. Larger companies have the ability to manage their risk by diversification. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than if our business were more diversified enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.
We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.
We expect that our cash position, private equity capital raising attempts, and our extremely limited revenues from crude oil sales will be sufficient to fund our existing 2013 drilling program and land reserve acquisition program. However, those funds may not be sufficient to fund both continuing operations and our planned growth. We may require additional capital to continue to grow our business via acquisitions and to further expand our exploration and development programs. We may be unable to obtain additional capital if and when required or if available on terms and conditions acceptable to management.
Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, transportation of exploited reserves, as well as legal compliance costs and accounting expenses) will require a substantial amount of capital and cash flow, which may not be available when and as needed.
We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our current operations or our planned expansion of operations in the future.
Our properties may be or become landlocked since they are remote without benefit of roads and other infrastructure.
Our current properties, while amassing to some 50,000 acres, are relatively small amounts of land in the areas of the Williston Basin and Bakken formation within such basin. There are very limited roadways and infrastructure providing access to these areas and our properties. . It is possible that private landowners may restrict our ability to enter and transport any recovered reserves from these properties. If so our properties will be considered landlocked and we may not have the ability to export any crude oil or natural gas reserves.
Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.
Our ability to successfully acquire additional properties, to discover reserves, to participate in exploration opportunities and to identify and enter into commercial arrangements with customers depend on developing and maintaining close working relationships with industry participants, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.
To further develop our business, we will attempt to use the business relationships of our management, consultants and advisors to enter in to strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. Our ability to successfully operate any joint venture depends on a variety of factors, many of which will be entirely outside our control. We may not be able to establish this and other strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse affect on our results of operation.
We have only participated in wells operated by third-parties. Our current ability to develop successful business operations depends on the success of our consultants and drilling partners. As a result, we do not control the timing or success of the development, exploitation, production and exploration activities relating to our leasehold interests. If our consultants and drilling partners are not successful in such activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.
We may not be able to effectively manage our growth, which may harm our profitability.
Our strategy includes expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure that we will be able to:
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meet our capital needs;
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expand our systems effectively or efficiently or in a timely manner;
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allocate our human resources optimally;
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identify and hire qualified employees or retain valued employees; or
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effectively integrate the components of any business or properties that we may acquire in our effort to achieve growth.
If we are unable to manage our growth, our financial condition and results of operations may be materially adversely affected.
Competition in obtaining rights to explore and develop crude oil and natural gas reserves and to market our production may impair our business.
The crude oil and natural gas industry is highly competitive. Other crude oil and natural gas companies may seek to acquire crude oil and natural gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate. This competition is increasingly intense as prices of crude oil and natural gas on the commodities markets have risen in recent years.
Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. If we are unable to compete effectively or respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.
We are highly dependent on Stephen Funk, our Chief Executive Officer, and Director, Timothy Kelly, President, COO, and Director, and Thomas Hayes, Director of Land Acquisitions. The loss of any of them, upon whose knowledge, leadership and technical expertise we rely, would harm our ability to execute our business plan.
Our success depends heavily upon the continued contributions of Steve Funk, Tim Kelly and Tom Hayes, and the other members of our management team, whose knowledge, leadership and technical expertise would be difficult to replace. If we were to lose their services, our ability to execute our business plan would be harmed and we may be forced to cease operations until such time as we are able to suitably replace them.
II. Risks Related To Our Industry
Crude oil and natural gas prices are very volatile. A protracted period of depressed crude oil and natural gas prices may adversely affect our business, financial condition, results of operations or cash flows.
The crude oil and natural gas markets are very volatile, and we cannot predict future crude oil and natural gas prices. The price we receive for our crude oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
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changes in global supply and demand for crude oil and natural gas;
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the actions of the Organization of Petroleum Exporting Countries;
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political and economic conditions, including embargoes, in crude oil-producing countries or affecting other crude oil-producing activity;
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the level of global crude oil and natural gas exploration and production activity;
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weather conditions;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations;
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proximity and capacity of crude oil and natural gas pipelines and other transportation facilities;
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the price and availability of competitors’ supplies of crude oil and natural gas in captive market areas; and
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the price and availability of alternative fuels.
Lower crude oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of crude oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings. A substantial or extended decline in crude oil or natural gas prices may result in impairments of our proved crude oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
We may not be able to develop crude oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.
If we continue to succeed in discovering crude oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable.
Future crude oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. While we will attempt to effectively manage these conditions, we cannot assure you that we will be successful. These conditions could diminish our revenue and cash flow levels and result in the impairment of our crude oil and natural gas interests.
We may have difficulty distributing our production, which could harm our financial condition.
In order to sell the crude oil and natural gas that we are able to produce, the operators of our wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. These factors may affect our ability to explore and develop properties and to store and transport our crude oil and natural gas production and may increase our expenses.
Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of crude oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.
Our business of exploring for crude oil and natural gas is risky and may not be commercially successful, and the advanced technologies we use cannot eliminate exploration risk.
Our future success will depend on the success of our exploratory drilling program. Crude oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our expenditures on exploration may not result in new discoveries of crude oil or natural gas in commercially viable quantities. Projecting the costs of implementing an exploratory drilling program is difficult due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions.
If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.
Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.
There are risks associated with the drilling of crude oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results.
Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.
We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of crude oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
We will rely on technology to conduct our business, and our technology could become ineffective or obsolete.
We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired.
Estimates of crude oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.
We make estimates of crude oil and natural gas reserves, upon which we base our financial projections. We make these reserve estimates using various assumptions, including assumptions as to crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions.
As a result, our reserve estimates will be inherently imprecise. Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our crude oil and natural gas interests.
The possibility of a global financial crisis may significantly impact our business and financial condition for the foreseeable future.
The credit crisis and related turmoil in the global financial system may adversely impact our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have a material negative impact on our flexibility to react to changing economic and business conditions. The economic situation could have a material negative impact on operators upon whom we are dependent for drilling our wells, our lenders or customers, causing them to fail to meet their obligations to us. Additionally, market conditions could have a material negative impact on our crude oil hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. We believe we will have sufficient capital to fund our 2013 drilling program. However, additional capital would be required in the event that we accelerate our drilling program or that crude oil prices decline substantially resulting in significantly lower revenues.
Our ability to generate revenue from existing operations is speculative and dependent upon market prices.
Our ability to generate revenue from existing operations is speculative. Our resulting financial performance is significantly affected by the prices we receive for crude oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which crude oil and natural gas trade in the open market have experienced significant volatility and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:
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domestic and foreign demand for crude oil and natural gas by both refineries and end users;
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the introduction of alternative forms of fuel to replace or compete with crude oil and natural gas;
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domestic and foreign reserves and supply of crude oil and natural gas;
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competitive measures implemented by our competitors and domestic and foreign governmental bodies;
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political climates in nations that traditionally produce and export significant quantities of crude oil and natural gas (including military and other conflicts in the Middle East and surrounding geographic region) and regulations and tariffs imposed by exporting and importing nations;
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weather conditions; and
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domestic and foreign economic volatility and stability.
III. Regulatory and Legal Risks
Environmental risks may adversely affect our business.
All phases of the crude oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with crude oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures, and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of crude oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.
Our business will suffer if we cannot obtain or maintain necessary licenses.
Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governmental authorities, among other factors. Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations or otherwise materially adversely affect our financial condition and results of operations.
Challenges to title and our properties that may impact our financial condition.
Title to crude oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired. To mitigate title problems, common industry practice is to obtain a title opinion from a qualified crude oil and natural gas attorney prior to the drilling operations of a well.
Penalties we may incur could impair our business.
Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.
IV. Risks Related to our Common Stock
Our securities are a “Penny Stock" and subject to specific rules governing their sale to investors
The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to our Common Stock, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require that a broker or dealer approve a person’s account for transactions in penny stocks; and the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.
In order to approve a person’s account for transactions in penny stocks, the broker or dealer must obtain financial information and investment experience objectives of the person; and make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.
The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form sets forth the basis on which the broker or dealer made the suitability determination; and that the broker or dealer received a signed, written agreement from the investor prior to the transaction.
Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors sell shares of our common stock.
Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.
There is minimal trading activity in our Common Stock and there is no assurance that an active market will develop in the future.
There is minimal trading activity in our Common Stock. Further, although our Common Stock is currently quoted on the OTC Bulletin Board, trading of our Common Stock may be extremely sporadic. For example, several days may pass before any shares may be traded. As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations of the price of our Common Stock. There can be no assurance that a more active market for our Common Stock will develop, or if one should develop, there is no assurance that it will be sustained. This severely limits the liquidity of our Common Stock, and would likely have a material adverse effect on the market price of our Common Stock and on our ability to raise additional capital.
Our operating results may fluctuate significantly, and these fluctuations may cause the value of our common stock to decline.
Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the coming to market of crude oil and natural gas reserves that we are able to discover and develop, expenses that we incur, the prices of crude oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.
We do not expect to pay dividends in the foreseeable future.
We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and shareholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock.
Investors may experience dilution of their ownership interests because of the future issuance of additional shares of our Common Stock.
In the future, we may issue additional authorized but previously unissued equity securities, resulting in the dilution of the ownership interests of our present stockholders. We may also issue additional shares of our Common Stock or other securities that are convertible into or exercisable for our Common Stock in connection with hiring or retaining employees, future acquisitions, future sales of our securities for capital raising purposes, or for other business purposes. The future issuance of any such additional shares of Common Stock may create downward pressure on the trading price of our Common Stock. There can be no assurance that the we will not be required to issue additional shares, warrants or other convertible securities in the future in conjunction with any capital raising efforts, including at a price (or exercise prices) below the price at which shares of our Common Stock is currently quoted on the OTC Bulletin Board.
Because we became public by means of a “reverse merger” we may not be able to attract the attention of brokerage firms.
Additional risks may exist since we became public through a “reverse merger.” Securities analysts of brokerage firms may not provide coverage of us since there is little incentive to brokerage firms to recommend the purchase of our Common Stock. No assurance can be given that brokerage firms will want to conduct any secondary offerings on our behalf in the future.
Compliance with the reporting requirements of federal securities laws can be expensive.
We are a public reporting company in the United States, and accordingly, subject to the information and reporting requirements of the Exchange Act and other federal securities laws, and the compliance obligations of the Sarbanes-Oxley Act. The costs of preparing and filing annual and quarterly reports and other information with the SEC and furnishing audited reports to stockholders are substantial.
Item 1B.
Item 1B. Unresolved Staff Comments.
Not Applicable
Item 2.
Item 2. Properties.
Office Locations
Our corporate offices are located at 30 Echo Lake Road, Watertown, CT, 06795. Additionally, we have a field office located at 2906 First Ave. North, Billings, MT, 59104; which is leased on a month by month basis.
Leasehold Holdings
The following represent our mineral lease holdings as of December 31, 2012.
Unproven Properties:
55,259 gross and 6,322 net mineral acres in Golden Valley, North Dakota. We have leaseholds totaling 55,259 gross acres in Golden Valley, North Dakota which were acquired under a long-term lease option. The conventional oil play consists of two objective formations; 1) Bakken - A sandstone that has produced over 80M barrels of oil and is present over our acreage, 2) Three Forks Sanish.
7,274 gross and 1,661 net mineral acres located in Sheridan County, Montana.
60,000 gross and 6,000 net mineral acres located in Sioux, Nebraska. This lease has the potential for over 800 horizontal wells. With a 10% interest in the field this could yield 80 net wells for Stratex.
640 gross and 121 net mineral acres in Stark County, North Dakota. Stark County has seen significant development recently as firms are exploring the potential of the Bakken play in the county.
640 gross and 120 net mineral acres in Mountrail County, North Dakota. We have gained a foothold in Mountrail County, which has been the focal point of drilling in the Williston Basin and the best performing county in North Dakota. The North Dakota State Industrial Commission has reported Mountrail’s most recent monthly production rate, December 2011, at 5.1 million barrels of oil.
1,313 gross and 37 net mineral acres in Williams County, North Dakota. Williams County has also been a top producing county in North Dakota and the most recent production statistics by the North Dakota Industrial Commission (NDIC) report monthly production at 2.4 million barrels of oil.
640 gross and 4 net mineral acres in Divide County, North Dakota. We have acquired small leasehold in Divide County, which has picked up in development lately. The lease currently has 1 well being drilled with a working interest of 5.00%.
Proven Properties:
2,080 gross and 25 net mineral acres located in Acres located in Lane and Ellis Counties, Kansas with 8 operating wells. The lease currently has 5 producing wells with an average royalty interest of 1.620%, and 3 producing wells with an average working interest of 6.503%. There is also additional spacing for 18 wells.
420 gross and 260 net mineral acres operating well in Roosevelt County, Montana with one operating well. The Operating well (Tininenko 4-19) is producing 27 barrels per day with one Bakken drilling unit of 320 acres.
6,662 gross and 87 net mineral acres in Stark, Williams and Sheridan County, North Dakota, with 6 operating wells. The Operating wells are producing 3 barrels per day.
17,920 gross and 197 net mineral acres in Billings and Stark County, North Dakota, with 13 operating wells, and 3 wells in process of being drilled. These working interest wells are producing 3 barrels per day. There is also 6,353 gross and 26 net mineral acres in Billings County that are undeveloped and unproven.
Stratex also holds an overriding royalty interest in 138 wells in Weld County, Colorado. The lease currently has 138 producing wells with an average royalty interest of .110076%.
ITEM 3.
ITEM 3. Legal Proceedings.
None.
ITEM 4.
ITEM 4. Mine Safety Disclosures.
None.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Shares of the Company’s common stock are currently quoted on the Over-The-Counter Bulletin Board under the symbol “STTX.” Prior to April 2012, zero shares of our stock had traded.
Holders
As of April 4, 2013, there are 44,281,127 shares of common stock issued and outstanding. These shares of common stock are held of record by 176 registered shareholders.
Dividends
We have not paid dividends on our common stock and do not expect to declare and pay dividends on our common stock in the foreseeable future.
Securities Authorized for Issuance under Equity Compensation Plans
The following is certain information about our equity compensation plans as of December 31, 2012:
In 2012, we adopted a new Stock Incentive Plan (the “2012 Plan”), under which we approved and reserved 12,000,000 shares of common stock to be issued as stock options to our employees, officers, directors and outside advisors.
Item 6.
Item 6. Selected Financial Data.
Not applicable.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation
Overview
Our business involves the aggregation of oil and gas leases on properties primarily in the Bakken formation in North Dakota and Montana even though we own leases in other formations and locations. We currently do not intend to primarily operate the drilling programs pertaining to our holdings, but rather to participate in the cash flow though a carried interest in each property. However, as we are continually evaluating new opportunities in which we may invest, our business plan may shift to operating additional properties.
We currently own an interest in 167 oil wells which is the source of our cash flow. One of these wells is 100% owned, is located in Roosevelt County Montana, and we are the operators. We control leases in North Dakota, Montana, Nebraska, Colorado and Kansas; these leases are expected to provide a source of future oil drilling properties which, due to their locations, are expected to become more valuable particularly as the Bakken formation is further developed. There is no assurance that such an outcome will be realized.
As of December 31, 2012, we have approximately 14,860 net acres in Sheridan, Montana, Williams, Divide, Mountrail, and Stark, North Dakota, Sioux, Nebraska, and Weld, Colorado. We do not own the majority working interest in this acreage, nor do we have any ability to influence the potential development of this acreage within the terms of the appropriate leases. These working interests grant us the right, as the lessee of the property, to explore for, develop and produce oil, natural gas and other minerals, while bearing our portion of related exploration, development and operating costs.
The Bakken formation is recognized internationally as a major source of oil reserves. The United States Geological Survey (USGS) estimates that the Bakken has some 4.3 billion barrels of recoverable oil. The Keystone pipeline, which runs along the US-Canada border, was halted by President Obama and we expect it to be approved and construction to be resumed in the near future. If approved, it will be a principal means of transporting the Bakken oil from the Canadian and US portions of the formation to the refineries. It is believed that the Bakken oil fields and the shale gas fields in other parts of the US will make the US energy independent this decade.
We have acquired these properties for cash in all cases (raised through equity sales of our common stock and a small amount of debt securities) except for our latest acquisition that closed in November 2012. That acquisition, valued at almost $700,000, the Divide County, North Dakota properties, was acquired by means of a cash payment and the issuance of shares of our common stock. We believe that we can finance such acquisitions through various capital raising programs and the use of our shares as a partial payment.
We expect to continue to acquire oil and gas properties and to build our asset base. As we continue to review business opportunities, we believe that we will need to raise additional capital through equity sales and debt financing to continue to acquire more properties, and business opportunities, such properties are expected to generate cash flow from participation in the development of the drilling programs that each property is designed to support.
Commodity Prices
Our results of operations are heavily influenced by commodity prices. Factors that may impact future commodity prices, including the price of oil and natural gas, include:
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developments generally impacting the Middle East, including Iraq, Iran, Libya and Egypt;
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the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas;
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the overall global demand for oil;
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overall North American natural gas supply and demand fundamentals;
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the impact of the condition of the United States economy;
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weather conditions; and
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liquefied natural gas deliveries to the United States.
Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we may evaluate the benefits of hedging a portion of our commodity price risk to mitigate the impact of price volatility on our business.
Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were substantially higher during the comparable periods of 2012 measured against 2011. The following table sets forth the average New York Mercantile Exchange (NYMEX) oil and natural gas prices for the years ended December 31, 2012 and 2011, as well as the high and low NYMEX price for the same periods:
Results of Operations for the twelve months ended December 31, 2012 as compared to the twelve months ended December 31, 2011:
Revenues:
We generated revenues of $959,388 for the twelve months ended December 31, 2012 and $240,122 for the twelve months ended December 31, 2011. The increase in revenue reflects an increase in sales volumes as a result of additional producing wells during the twelve months ended December 31, 2012. The Company was newly formed and was acquiring properties during 2011.
Operating Expenses:
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Production expense was $235,845 for the twelve months ended December 31, 2012 and $101,265 for the period ended December 31, 2011. The increase in expense reflects an increase in the properties and producing wells during the twelve months ended December 31, 2012. The Company was newly formed and was acquiring properties during 2011.
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General and administrative expense was $5,461,053 for the twelve months ended December 31, 2012 and $828,229 for the period ended December 31, 2011. The increase in expense is primarily attributable to an increase in professional fees for the Company’s merger, an increase in salaries and payroll related expenses, and an increase in stock based compensation to consultants, the majority of which was related to the financing commitment for Stratex's attempted acquisition of Magellan Petroleum. In addition, the company engaged key consultants to assist in the oil and gas efforts.
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Depletion, depreciation and amortization expense was $484,853 for the twelve months ended December 31, 2012 and $110,793 for the period ended December 31, 2011. The increase in expense reflects an increase in the properties and producing wells during the twelve months ended December 31, 2012. The Company was formed incepted and was acquiring properties during 2011.
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Impairment of oil and gas assets was $1,307,782 for the twelve months ended December 31, 2012 and $0 for the period ended December 31, 2011. The impairment loss was recognized to reflect the annual reserve report obtained by the company’s third party engineers.
Other Income and (Expense):
Other income (expense) was $(933,149) for the twelve months ended December 31, 2012 and $(184,394) for the twelve months ended December 31, 2011. Other income (expense) consisted of interest expense on the notes and convertible notes entered into during the period January 25, 2011 (Date of Inception) through December 31, 2012. In addition, the company accretes debt discount associated with the derivative liability through interest expense and recognized a major increase in fair market value of the derivative liability during the twelve months ended December 31, 2012. In addition, the Company recorded a $258,848 loss on the change in fair value of derivative liabilities embedded in the Company’s convertible notes during the year ended December 31, 2012.
Liquidity and Capital Resources:
We have incurred net operating losses and operating cash flow deficits since inception, continuing through the first quarter of 2013. We are in the early stages of acquisition and development of oil and gas leaseholds and properties, and we have been funded primarily by a combination of equity issuances and debt, and to a lesser extent by operating cash flows, to execute on our business plan of acquiring working interests in oil and gas properties and for working capital for production. At December 31, 2012, we had cash and cash equivalents totaling approximately $75,103.
Our ability to obtain financing may be impaired by many factors outside of our control, including the capital markets (both generally and in the crude oil and natural gas industry in particular), our limited operating history, the location of our crude oil and natural gas properties and prices of crude oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and other factors. Further, if crude oil or natural gas prices on the commodities markets decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital.
Any new debt or equity financing arrangements may not be available to us, or may be available only on unfavorable terms. Additionally, these alternatives could be highly dilutive to our existing stockholders, and may not provide us with sufficient funds to meet our long-term capital requirements. We have and may continue to incur substantial costs in the future in connection with raising capital to fund our business, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we will be required to reduce operating costs, which could jeopardize our future strategic initiatives and business plans, and we may be required to sell some or all of our properties (which could be on unfavorable terms), seek joint ventures with one or more strategic partners, strategic acquisitions and other strategic alternatives, cease our operations, sell or merge our business, or file a petition for bankruptcy.
Our financial statements for the twelve months ended December 31, 2012 were prepared assuming we would continue as a going concern, which contemplates that we will continue in operation for the foreseeable future and will be able to realize assets and settle liabilities and commitments in the normal course of business. These financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that could result should we be unable to continue as a going concern.
Cash from Operating Activities
Cash used for operating activities was approximately $856,499 for the twelve months ended December 31, 2012, as compared to cash used for operating activities of approximately $601,796 during the period ended December 31, 2011. The increase in cash used in operating activities is due to the higher expenses associated with the continuing increase in activities of oil and gas production, an increase in professional fees for the Company’s merger and an increase in salaries and payroll related expenses.
Cash from Investing Activities
Cash used for investing activities for the twelve months ended December 31, 2012 was approximately $1,401,938 as compared to approximately $2,892,808 during the period ended December 31, 2011. The decrease is due to a decrease in capital acquisition during 2012 as compared to the comparable period ended 2011.
Cash from Financing Activities
Total net cash provided by financing activities was approximately $1,747,735 for the twelve months ended December 31, 2012, from various debt and equity offerings. Total net cash provided by financing activities during the period ended December 31, 2011 was approximately $4,080,409 from various debt and equity offerings. For more details about these debt and equity financings, see Notes to the Consolidated Financial Statements for the year ended December 31, 2012 and the twelve months ended December 31, 2011, incorporated by reference herein.
Planned Capital Expenditures
Dependent on our ability to obtain sufficient financing, development plans for 2013 include identifying and acquiring additional properties and leases in different operators and regions as well as participating in ongoing Authorization for Expense (AFE) process for the existing properties.
The Company incurred approximately $1,196,000 in development costs related to the purchase of working interest in wells during the calendar year 2012. Unrelated to any potential acquisitions the Company expects to incur maintenance and operating costs of approximately $45,000 to $60,000 per month for the next twelve months to maintain these assets.
Critical Accounting Policies and Estimates:
Our discussion of our financial condition and results of operations is based on the information reported in our financial statements. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are described in Note 2 -Summary of Significant Accounting Policies to our consolidated financial statements and notes. We have outlined below certain of these policies that have particular importance to the reporting of our financial condition and results of operations and that require the application of significant judgment by our management.
Key Definitions
Proved reserves, as defined by the SEC, are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Valuations include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Prices do not include the effect of derivative instruments, if any, entered into by us.
Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods. Additional oil and gas volumes expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery would be included as proved developed reserves only after testing of a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves are those reserves that are expected to be recovered from new wells on non-drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on non-drilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other non-drilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.
Estimation of Reserves
Volumes of reserves are estimates that, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. There are numerous uncertainties in estimating crude oil and natural gas reserve quantities, projecting future production rates and projecting the timing of future development expenditures. Natural gas and oil reserve engineering must be recognized as a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. Estimates of independent engineers that we use may differ from those of other engineers. The accuracy of any reserve estimate is a function of the quantity and quality of available data and of engineering and geological interpretation and judgment. Accordingly, future estimates are subject to change as additional information becomes available.
The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depletion, depreciation and amortization of oil and gas properties and the estimate of any impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the annual year end disclosure of the related standardized measure of discounted future net cash flows.
Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. We recognize a receivable or liability only to the extent that we have an imbalance on a specific property greater than our share of the expected remaining proved reserves. For oil sales, this occurs when the customer's truck takes delivery of oil from the operators’ storage tanks
Successful Efforts Accounting
We utilize the successful efforts method to account for our natural gas and oil operations. Under this method, all costs associated with natural gas and oil lease acquisitions, successful exploratory wells and all development wells are capitalized. Development costs of producing properties are amortized on a units-of-production basis over the remaining life of proved developed producing reserves, and leasehold costs associated with producing properties are amortized on a units-of-production basis over the remaining life of all proved reserves associated with the leases on which producing properties are drilled. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are expensed when incurred.
Impairment of Properties
We review our proved properties for potential impairment at the field level when management determines that events or circumstances indicate that the recorded carrying value of any of the properties may not be recoverable. Such events include a projection of future natural gas and oil reserves that will be produced from a well, the timing of this future production, future costs to produce the natural gas and oil, and future inflation levels. If the carrying amount of an asset exceeds the sum of the discounted estimated future net cash flows, we recognize impairment expense equal to the difference between the carrying value and the fair market value of the asset, which is estimated to be the expected discounted value of future net cash flows from reserves, without the application of any estimate of risk. We cannot predict the amount of impairment charges that may be recorded in the future. Unproved leasehold costs are reviewed periodically and impairment is recognized to the extent, if any, that the cost of the property has been impaired. We follow the Accounting Standards Codification ASC 360 Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.
Proved Reserves
Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and amortization expense and the impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. We engage independent reserve engineers to estimate our proved reserves.
Share-Based Compensation
Compensation expense has been recorded for grants of restricted common stock and options based on the fair value of the common stock on the measurement date. We estimate the fair value of each stock option awarded at the grant date by using the Black-Scholes option pricing model. FASB ASC Topic No. 718-10 establishes standards for transactions in which an entity obtains employee services in share-based payment transactions. The guidance requires that the fair value of such equity instruments be recognized as expense in the historical financial statements as services are performed. Standards of accounting for transactions in which an entity exchanges its equity instruments for goods and services by a consultant or contractor are further governed by FASB ASC Topic No. 505-50 by which the grant is measured at the fair value of the stock exchanged and the associated expense is recorded according to the category of the good or service rendered.
Derivative Valuation
We estimate the fair value of financial assets and liabilities based on a three-level valuation hierarchy for disclosures of fair value measurement and enhance disclosure requirements for fair value measures.
The three levels are defined as follows:
Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.
All derivative instruments are recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current period earnings.
New Accounting Pronouncements
We do not expect the adoption of any recently issued accounting pronouncements to have a significant impact on our results of operations, financial position or cash flows.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
Item 8.
Item 8. Financial Statements and Supplementary Data.
STRATEX OIL & GAS HOLDINGS, INC.
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE PERIOD JANUARY 25, 2011 (DATE OF INCEPTION) TO DECEMBER 31, 2012
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Consolidated Financial Statements
December 31, 2012 and 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of
Stratex Oil & Gas Holdings, Inc. and Subsidiary
We have audited the accompanying consolidated balance sheets of Stratex Oil & Gas Holdings, Inc. and Subsidiary (a development stage company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the year ended December 31, 2012 and each of the periods from January 25, 2011 (date of inception) to December 31, 2011 and 2012. Stratex’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Stratex Oil & Gas Holdings, Inc. and Subsidiary as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the periods from January 25, 2011 (date of inception) to December 31, 2011 and 2012 in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming that the company will continue as a going concern. As discussed in Note 3 to the financial statements, the company has suffered losses from operations and has an accumulated deficit, which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters also are described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/S/ MAHONEY SABOL & COMPANY, LLP
Glastonbury, Connecticut
April 4, 2013
See accompanying notes to financial statements.
See accompanying notes to financial statements.
See accompanying notes to financial statements.
See accompanying notes to financial statements.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Note 1 Nature of Operations and Basis of Presentation:
Nature of Operations
Stratex Oil & Gas Holdings, Inc. (the “Company”) (“Pubco”) was incorporated in August 15, 2003. The Company was originally incorporated as Poway Muffler and Brake Inc. in California on August 15, 2003 to enter the muffler and brake business. On December 15, 2008, a merger was effected with Ross Investments Inc., a Colorado shell corporation. Ross Investments was the acquirer and the surviving corporation. Ross Investments Inc. then changed its name to Poway Brake and Muffler Inc. On May 25, 2012, we filed an Amendment to our Certificate of Incorporation by which we changed our name from Poway Muffler and Brake, Inc., a Colorado corporation, to Stratex Oil and Gas Holdings, Inc., with the Secretary of the State of Colorado.
On July 6, 2012, Stratex Acquisition Corp., a wholly-owned subsidiary of Stratex Oil & Gas Holdings, Inc. merged with and into Stratex Oil & Gas, Inc., a Delaware corporation (“Stratex”). Stratex was the surviving corporation of that Merger. As a result of the merger, we acquired the business of Stratex, and continue the business operations of Stratex as a wholly-owned subsidiary.
The Company is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves in the Bakken, Three Forks, Heath and Tyler Formations in North Dakota, Montana, Kansas, Nebraska, and Colorado.
The Company’s major assets are an oil well in Roosevelt County, Montana and leaseholds affording drilling rights in North Dakota, Montana, Kansas, Nebraska and Colorado.
Mergers
The Company was capitalized in 2000 and made preparations to enter business, but no revenue was subsequently earned. The Company was dormant in 2007 and 2008 until a merger with Poway Muffler and Brake, Inc. was effected on December 15, 2008. Poway Muffler and Brake, Inc. was a closely held private company operating a brake and muffler business in Poway, California. Ross Investments, Inc. was the acquirer and surviving company.
On May 25, 2012, Poway Muffler and Brake, Inc. filed an Amendment to the Certificate of Incorporation by which Poway Muffler and Brake, Inc., a Colorado corporation, changed its name to Stratex Oil and Gas Holdings, Inc. (“Pubco”), with the Secretary of the State of Colorado.
On July 6, 2012 (the “Closing Date”), Stratex Acquisition Corp. (“Acquisition Corp.”), a wholly-owned subsidiary of Pubco, merged (the “Merger”) with and into Stratex Oil & Gas, Inc., a Delaware corporation (“Stratex”). Stratex was the surviving corporation of that Merger. As a result of the Merger, Pubco acquired the business of Stratex, and will continue the existing business operations of Stratex as a wholly-owned subsidiary, in a transaction treated as a reverse acquisition. Pubco had minimal operations and majority-voting control was transferred to Stratex. The transaction also requires a recapitalization of Stratex. Since Stratex acquired a controlling voting interest, it was deemed the accounting acquirer, while Pubco was deemed the legal acquirer. The historical financial statements of the Company are those of Stratex, and of the consolidated entities from the date of merger forward.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Simultaneously with the Merger, on the Closing Date, all of the issued and outstanding shares of Stratex common stock converted, on a 2 for 1 basis, into shares of the Company’s common stock, (“Common Stock”). Also on the Closing Date, all of the issued and outstanding options to purchase shares of Stratex common stock, and all of the issued and outstanding warrants (collectively the “Stratex Convertible Securities”) to purchase shares of Stratex Common Stock, upon the exercise or conversion of the Stratex Convertible Securities, shall have the right to convert such Stratex Convertible Securities into the kind and amount of the Company’s shares of Common Stock and other securities and property which such holder would have owned or have been entitled to receive of Stratex prior to the Closing of the Merger, on a 2 for 1 basis. The options will be administered under Stratex’s 2012 Equity Incentive Plan (the “Stratex Plan”), which the Company assumed and adopted on the Closing Date in connection with the Merger.
On the Closing Date, (i) approximately 33,372,550 shares of Common Stock were issued to former Stratex stockholders; (ii) 100 shares of Series A Preferred Stock were issued to former holders of Stratex Series A Preferred Stock, (iii) options to purchase 3,000,000 shares of Common Stock granted under the Stratex Plan pursuant to the assumption of the Stratex Plan; (iv) Warrants to purchase 675,000 shares of Common Stock at $0.70 per share issued to holders of 1,350,000 Stratex Warrants (that were exercisable at a price of $0.35 per share) were assumed by the Company. In addition, pre-Merger stockholders of Pubco retained 6,110,000 shares of Common Stock.
The financial statements presented for all periods through and including December 31, 2012 are those of Stratex. As a result of this Merger, the equity sections of Stratex for all prior periods presented reflect the recapitalization described above and are consistent with the December 31, 2012 balance sheet presented for the Company.
Since the transaction is considered a reverse acquisition and recapitalization, the presentation of pro-forma financial information was not required.
Basis of Presentation
The accompanying financial statements and related notes have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
Development Stage Company
The Company is a development stage company since it has not yet generated substantial revenue from the sale of oil and gas and, through December 31, 2012, its efforts have been principally devoted to the regulatory, legal and research requirements for the development of a portfolio of proven oil and gas reserves. The accompanying consolidated financial statements have been prepared in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 915-205-45.
Note 2 Summary of Significant Accounting Policies:
Principles of Consolidation
All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Such estimates and assumptions impact, among others, the following: allowance for bad debt, inventory obsolescence, the fair value of share-based payments, fair value of derivative liabilities, estimates of the probability and potential magnitude of contingent liabilities and the valuation allowance for deferred tax assets due to continuing operating losses.
Making estimates requires management to exercise significant judgment. It is at least reasonably possible that the estimate of the effect of a condition, situation or set of circumstances that existed at the date of the consolidated financial statements, which management considered in formulating its estimate could change in the near term due to one or more future confirming events. Accordingly, the actual results could differ significantly from our estimates.
The accompanying consolidated financial statements contain estimates of the Company’s proved reserves and the estimated future net revenues from the proved reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
The process of estimating oil and gas reserves is complex and involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, the Company’s management may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond the Company’s control. The Company’s properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
The present value of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of the Company’s estimated oil and natural gas reserves. The estimated discounted future net cash flows from the Company’s proved reserves is based on the average, first-day-of-the-month price during the 12-month period preceding the measurement date. Actual future net cash flows from oil and natural gas properties also will be affected by factors such as actual prices received for oil and gas, actual development and production costs, the amount and timing of actual production, the supply of and demand for oil and gas, and changes in governmental regulations or taxes.
The timing of the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor used when calculating discounted future net cash flows for financial statement disclosure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.
Risks and Uncertainties
The Company operates in an industry that is subject to intense competition and change in consumer demand. The Company's operations are subject to significant risk and uncertainties including financial and operational risks including the potential risk of business failure.
The Company’s future success depends largely on its ability to find and develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces the reserves produced through successful development, exploration or acquisition activities, proved reserves will decline over time. Recovery of any additional reserves will require significant capital expenditures and successful drilling operations. The Company may not be able to successfully find and produce reserves economically in the future. In addition, the Company may not be able to acquire proved reserves at acceptable costs.
Cash and Cash Equivalents
The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. There were no cash equivalents at December 31, 2012 and 2011.
The Company minimizes its credit risk associated with cash by periodically evaluating the credit quality of its primary financial institution.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable consist primarily of oil and gas receivables, net of a valuation allowance for doubtful accounts. As of December 31, 2012 and 2011, the allowance for doubtful accounts was $0.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Inventories
Inventories are stated at the lower of cost or market using the first-in, first-out (FIFO) valuation method.
Oil and Gas Properties, Successful Efforts Method
The Company uses the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. The Company evaluates its proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. The Company follows FASB ASC 360 - Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value. During the year ended December 31, 2012 and 2011, the Company recorded an impairment on oil and gas assets of $1,059,297 and $-, respectively. In addition, during the year ended December 31, 2012, the Company recorded a loss on abandonment of oil and gas assets of $455,815.
Support Facilities and Equipment
Our support facilities and equipment are generally located in proximity to certain of our principal fields. Depreciation of these support facilities is provided on the straight-line method based on estimated useful lives of 7 to 20 years.
Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.
Proved Reserves
Estimates of the Company’s proved reserves included in this report are prepared in accordance with U.S. GAAP and guidelines from the United States Securities and Exchange Commission (“SEC”). The Company’s engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of the Company’s estimated proved reserves. The Company engages independent reserve engineers to estimate its proved reserves.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Asset Retirement Obligations
The Company follows the provisions of the FASB ASC 410 - Asset Retirement and Environmental Obligations. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. As of December 31, 2012 and 2011, the Company’s obligations were immaterial. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligations relate to the abandonment of oil and gas producing facilities. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate.
Debt Issue Costs and Debt Discount
The Company may pay debt issue costs, and record debt discounts in connection with raising funds through the issuance of convertible debt. These costs are amortized over the life of the debt to interest expense. If a conversion of the underlying debt occurs, a proportionate share of the unamortized amounts is immediately expensed.
Original Issue Discount
For certain debt issued in 2012 and 2011, the Company provided the debt holder with an original issue discount. The original issue discount was equal to simple interest at 10% -20% of the proceeds raised. The original issue discount was recorded to debt discount reducing the face amount of the note and is being amortized to interest expense over the maturity period of the debt.
Derivative Financial Instruments
Fair value accounting requires bifurcation of embedded derivative instruments such as ratchet provisions or conversion features in convertible debt or equity instruments, and measurement of their fair value for accounting purposes. In determining the appropriate fair value, the Company utilized an option pricing model. In assessing the Company’s convertible debt instruments, management determines if the convertible debt host instrument is conventional convertible debt and further if there is a beneficial conversion feature requiring measurement. If the instrument is not considered conventional convertible debt, the Company will continue its evaluation process of these instruments as derivative financial instruments.
Once determined, the derivative liabilities are adjusted to reflect fair value at each reporting period end, with any increase or decrease in the fair value being recorded in results of operations as an adjustment to fair value of derivatives. In addition, the fair value of freestanding derivative instruments such as warrants, are also valued using the option pricing model.
Revenue Recognition
Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Share-Based Payments
Generally, all forms of share-based payments, including stock option grants, warrants, restricted stock grants and stock appreciation rights are measured at their fair value utilizing an option pricing model on the awards’ grant date, based on the estimated number of awards that are ultimately expected to vest. Share-based compensation awards issued to non-employees for services rendered are recorded at either the fair value of the services rendered or the fair value of the share-based payment, whichever is more readily determinable. The expenses resulting from share-based payments are recorded in cost of goods sold or general and administrative expense in the statement of operations, depending on the nature of the services provided.
Income Taxes
The Company is a taxable entity and recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect when the temporary differences reverse. The effect on the deferred tax assets and liabilities of a change in tax rates is recognized in income in the year that includes the enactment date of the rate change. A valuation allowance is used to reduce deferred tax assets to the amount that is more likely than not to be realized. Interest and penalties associated with income taxes are included in selling, general and administrative expense.
The Company has adopted ASC 740 “Accounting for Uncertainty in Income Taxes” which prescribes a comprehensive model of how a company should recognize, measure, present, and disclose in its consolidated financial statements uncertain tax positions that the company has taken or expects to take on a tax return. ASC 740 states that a tax benefit from an uncertain position may be recognized if it is "more likely than not" that the position is sustainable, based upon its technical merits. The tax benefit of a qualifying position is the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority having full knowledge of all relevant information.
Earnings Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) by weighted average number of shares of common stock outstanding during each period. Diluted earnings (loss) per share is computed by dividing net income (loss), adjusted for changes in income or loss that resulted from the assumed conversion of convertible shares, by the weighted average number of shares of common stock, common stock equivalents and potentially dilutive securities outstanding during the period.
The Company had the following potential common stock equivalents at December 31, 2012:
The Company had the following potential common stock equivalents at December 31, 2011:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Since the Company reflected a net loss in 2012 and 2011, the effect of considering any common stock equivalents, would have been anti-dilutive. A separate computation of diluted earnings (loss) per share is not presented.
Fair Value of Financial Instruments
The Company follows FASB ASC 820-10-35-37 (“Paragraph 820-10-35-37”) to measure the fair value of its financial instruments and FASB ASC 825-10-50-10 for disclosures about fair value of its financial instruments. Paragraph 820-10-35-37 establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, Paragraph 820-10-35-37 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The three (3) levels of fair value hierarchy defined by Paragraph 820-10-35-37 are described below:
Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable.
The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
The carrying amounts of the Company’s financial assets and liabilities, such as cash, inventory, prepaid expenses and other current assets, accounts payable and accrued liabilities approximate their fair values because of the short maturity of these instruments.
The Company’s Level 3 financial liabilities consist of the derivative warrant issued with the 2011 notes payables for which there is no current market for this security such that the determination of fair value requires significant judgment or estimation. The Company valued the reset adjustments in the warrant on subsequent potential equity offerings using an option pricing model, for which management understands the methodologies. These models incorporate transaction details such as the Company’s stock price, contractual terms, maturity, risk-free rates, as well as assumptions about future financings, volatility, and holder behavior as of the date of issuance and each balance sheet date.
Transactions involving related parties cannot be presumed to be carried out on an arm's-length basis, as the requisite conditions of competitive, free-market dealings may not exist. Representations about transactions with related parties, if made, shall not imply that the related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions unless such representations can be substantiated.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis
The Company uses Level 3 of the fair value hierarchy to measure the fair value of the derivative liabilities and revalues its derivative warrant liability and derivative feature of convertible notes at every reporting period and recognizes gains or losses in the statements of operations attributable to the change in the fair value of the derivatives.
Financial assets and liabilities measured at fair value on a recurring basis are summarized below and disclosed on the balance sheets as follows:
The table below provides a summary of the changes in fair value, including net transfers in and/or out, of all financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period January 25, 2011 (Date of Inception) to December 31, 2012:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Recent Accounting Pronouncements
In February 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income , an amendment to FASB ASC Topic 220. The update requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present either on the face of the statement of operations or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period. For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. This ASU is effective prospectively for the Company fiscal years, and interim periods within those years beginning after December 15, 2012. The Company will comply with the disclosure requirements of this ASU for the quarter ending March 31, 2013. The Company does not expect the impact of adopting this ASU to be material to the Company’s financial position, results of operations or cash flows.
In January 2013, the FASB issued ASU 2013-01 which clarifies which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The new ASU addresses preparer concerns that the scope of the disclosure requirements under ASU 2011-11 was overly broad and imposed unintended costs that were not commensurate with estimated benefits to the financial statement users. In choosing to narrow the scope of the offsetting disclosures, the Board determined that it could make them more operable and cost effective for prepares while still giving financial statement users sufficient information to analyze the most significant presentation differences between financial statements prepared in accordance with U.S. GAAP and those prepared under International Financial Reporting Standards (IFRS). ASU 2013-01 is effective for all entities (public and private) for the fiscal years beginning on or after January 1, 2013, and interim periods within. Retrospective application is required for any period presented that begins before the entity’s initial application of the new requirements. The Company does not expect the adoption of this ASU will have a material impact on it consolidate financial statements.
In July 2012, the FASB issued the ASU 2012-02, Intangibles-Goodwill and Other: Testing Indefinite-Lived Intangible Assets for Impairment, that allows entities to have the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with ASC 350-30. An entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The Company does not expect the adoption of these provisions to have a significant effect on its financial statements.
In December 2011, the FASB issued the ASU 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, that deferred the effective date for amendments to the presentation of reclassifications of items out of other comprehensive income. ASU 2011-12 was issued to allow the FASB time to redeliberate the presentation requirements for reclassifications out of accumulated other comprehensive income for annual and interim financial statements for public, private, and non-profit entities. During the redeliberation period, entities will continue to report reclassifications out of accumulated other comprehensive income using guidance in effect before ASU 2011-05 was issued. ASU 2011-05 is to be applied retrospectively and is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011. The adoption of these provisions did not have a material effect on the Company’s financial statements.
In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The guidance in ASU 2011-04 changes the wording used to describe the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, including clarification of the FASB's intent about the application of existing fair value and disclosure requirements and changing a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this ASU should be applied prospectively and are effective for interim and annual periods beginning after December 15, 2011. Early adoption by public entities is not permitted. The adoption of this guidance is not expected to have a material impact on the Company’s financial position or results of operations.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Note 3 Going Concern:
As reflected in the accompanying consolidated financial statements, the Company has a net loss of $7,670,624, $984,559 and $8,655,183 for the year ended December 31, 2012, for the period from January 11, 2011 (date of inception) to December 31, 2011 and for the period from January 25, 2011 (date of inception) to December 31, 2012, respectively. Additionally, the Company had net cash used in operations of $856,499, $601,796 and $1,458,295 for the year ended December 31, 2012, for the period from January 11, 2011 (date of inception) to December 31, 2011 and for the period from January 25, 2011 (date of inception) to December 31, 2012, respectively, and has a working capital deficit of $1,095,359 at December 31, 2012.
The ability of the Company to continue its operations is dependent on Management's plans, which include the raising of capital through debt and/or equity markets with some additional funding from other traditional financing sources, including term notes, until such time that funds provided by operations are sufficient to fund working capital requirements. The Company may need to incur additional liabilities with certain related parties to sustain the Company’s existence.
The Company will require additional funding to finance the growth of its current and expected future operations as well as to achieve its strategic objectives. The Company believes its current available cash along with anticipated revenues may be insufficient to meet its cash needs for the near future. There can be no assurance that financing will be available in amounts or terms acceptable to the Company, if at all.
The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. These consolidated financial statements do not include any adjustments relating to the recovery of the recorded assets or the classification of the liabilities that might be necessary should the Company be unable to continue as a going concern.
Note 4 Oil and Gas Assets:
The following table summarizes the Company’s oil and gas assets:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
The Company owns support facilities and equipment which serve its oil and gas production activities. The following table details these properties and equipment, together with their estimated useful lives:
During the year ended December 31, 2012 and during the period January 25, 2011 to December 31, 2011, the Company recorded $484,311 and $110,703 to depletion expense.
During the year ended December 31, 2012, an abandonment charge to income in the amount of $455,815 was recognized related to the Company’s Golden Valley Land Lease.
On November 1, 2012, the Company entered into a Purchase & Sale Agreement (the “Agreement”) with Fortuna Energy, Inc. (“Fortuna Energy”). Pursuant to the Agreement, the Company purchased certain oil & gas property located in Divide County North Dakota from Fortuna Energy for consideration of $200,000 cash and 250,000 shares of our common stock.
Note 5 Furniture and Equipment:
The following table summarizes furniture and equipment:
During the year ended December 31, 2012 and during the period January 25, 2011 to December 31, 2011, the Company recorded $542 and $90, respectively to depreciation expense.
Note 6 Demand Notes Payable:
(A)
Notes Payable - 10%
During the period February 22, 2011 to June 6, 2011, the Company issued nineteen (19) promissory notes to certain accredited investors in an aggregate amount of $845,000. The loans bear 10% interest. These loans had a maturity of 6 months and were unsecured.
During the period ended December 31, 2011, sixteen (16) note-holders converted $615,000 in notes payable and $4,147 of accrued interest into 2,476,585 shares of the Company’s common stock at a conversion rate of $0.25/share.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
During the period ended December 31, 2011, three (3) note-holders were re-paid $230,000 in principal.
The following is a summary of notes payable - related parties:
(B)
Notes Payable - Convertible
On October 19, 2011, the Company sold a convertible promissory note in the aggregate principal amount of $1,100,000 for proceeds of $1,000,000 payable May 24, 2012 and a five (5) year common stock purchase warrant exercisable for up to 500,000 shares of common stock at $0.70 per share to an accredited investor. The note is convertible at a rate of $0.70 per share. The note is unsecured.
During the period ended December 31, 2011, the Company sold four (4) convertible promissory notes in the aggregate principal amount of $328,000 for proceeds of $300,000 with a one (1) year maturity and a five (5) year common stock purchase warrant exercisable for up to 145,000 shares of common stock at $0.70 per share to an accredited investor. The notes are convertible at a rate of $0.70 per share. The notes are unsecured.
During the year ended December 31, 2012, the Company sold two (2) convertible promissory notes in the aggregate principal amount of $72,000 for proceeds of $60,000 with a one year maturity and a five (5) year common stock purchase warrant exercisable for up to 30,000 shares of common stock at $0.70 per share to an accredited investor. The notes are convertible at a rate of $0.70 per share. The notes are unsecured.
The following is a summary of notes payable - convertible:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
(C)
Note Payable Due on Demand
As of December 31, 2012, two (2) convertible notes for an aggregate principal amount of $180,000 matured. These notes were reclassified and are recorded as due on demand.
(D)
Promissory Note
On November 12, 2012, the Company issued a promissory note with principal of $288,750. The Company received proceeds of $275,000. The Company recorded the original issue discount of $13,750 and is accreting the discount to interest expense over the life of the note. The note matures on May 11, 2013 and is secured by assets of the Company. In addition, the noteholder received 1,000,000 shares of common stock of the Company. The issuance was recorded as a debt discount up to the face amount of the note. The amount in excess of the face amount of the note was recorded to interest expense on the date of issuance.
(E)
Debt Issuance Costs
Debt issuance costs, net are as follows:
Note 7 Stockholders’ Equity:
Simultaneously with the Merger with Stratex (See Note 1), on the Closing Date, all of the issued and outstanding shares of Stratex common stock converted, on a 2 for 1 basis, into shares of the Company’s common stock, (“Common Stock”). Also on the Closing Date, all of the issued and outstanding options to purchase shares of Stratex common stock, and all of the issued and outstanding warrants (collectively the “Stratex Convertible Securities”) to purchase shares of Stratex Common Stock, upon the exercise or conversion of the Stratex Convertible Securities, shall have the right to convert such Stratex Convertible Securities into the kind and amount of the Company’s shares of Common Stock and other securities and property which such holder would have owned or have been entitled to receive of Stratex prior to the Closing of the Merger, on a 2 for 1 basis. The options will be administered under Stratex’s 2012 Equity Incentive Plan (the “Stratex Plan”), which the Company assumed and adopted on the Closing Date in connection with the Merger.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
On the Closing Date, (i) approximately 33,372,550 shares of Common Stock were issued to former Stratex stockholders; (ii) 100 shares of Series A Preferred Stock were issued to former holders of Stratex Series A Preferred Stock; (iii) options to purchase 3,000,000 shares of Common Stock granted under the Stratex Plan pursuant to the assumption of the Stratex Plan; (iv) Warrants to purchase 675,000 shares of Common Stock at $0.70 per share issued to holders of 1,350,000 Stratex Warrants (that were exercisable at a price of $0.35 per share) were assumed by the Company. In addition, pre-Merger stockholders of Pubco retained 6,110,000 shares of Common Stock.
(A)
Preferred Stock
During the year ended December 31, 2012, the Company issued the following preferred stock:
(B)
Common Stock
During the year ended December 31, 2012, the Company issued the following common stock:
During the period January 25, 2011 (Date of Inception) to December 31, 2011, the Company issued the following common stock:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
(C) Warrants
The following is a summary of the Company’s warrant activity:
At December 31, 2012 and 2011, the total intrinsic value of warrants outstanding and exercisable was $168,750 and $0, respectively.
(D) Options
The following is a summary of the Company’s option activity:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
At December 31, 2012 and 2011, the total intrinsic value of options outstanding and exercisable was $675,617 and $0, respectively.
Note 8 Commitments and Contingencies:
Litigations, Claims and Assessments
From time to time, the Company may become involved in various lawsuits and legal proceedings, which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm its business. The Company is currently not aware of any such legal proceedings or claims that they believe will have, individually or in the aggregate, a material adverse affect on its business, financial condition or operating results.
Oil and Gas Prices
The prices of oil, natural gas, methane gas and other fuels have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including but not limited to the worldwide and domestic supplies of oil and gas, changes in the supply of and demand for such fuels, political conditions in fuel-producing and fuel-consuming regions, weather conditions, the development of other energy sources, and the effect of government regulation on the production, transportation and sale of fuels. These factors and the volatility of energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. A decline in prices could adversely affect the Company’s financial position, financial results, cash flows, access to capital and ability to grow.
Environmental Liabilities
Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or other well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings, and separated cables. If any of these circumstances occur, the Company could sustain substantial losses as a result of injury or loss of life, destruction of property and equipment, damage to natural resources, pollution or other environmental damages, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, and compliance with environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing, restrictions on drilling and completion operations and other laws and regulations. The Company’s potential liability for environmental hazards may include those created by the previous owners of properties purchased or leased prior to the date we purchase or lease the property. The Company maintains insurance against some, but not all, of the risks described above. Insurance coverage may not be adequate to cover casualty losses or liabilities.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Employment Contracts
On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Executive Officer. The terms of the Agreement are as follows:
●
Term - 5 years,
●
Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%),
●
Option Grant - 1,500,000 options to acquire restricted stock, (adjusted for post 2:1 stock split),
●
Preferred Share Grant - 50 shares of Preferred Stock which entitle the CEO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.
On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Operating Officer. The terms of the Agreement are as follows:
●
Term - 5 years,
●
Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%),
●
Option Grant - 1,500,000 options to acquire restricted stock, (adjusted for post 2:1 stock split),
●
Preferred Share Grant - 50 shares of Preferred Stock which entitle the COO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.
Note 8 Income Taxes:
At December 31, 2012, the Company has a net operating loss carry-forward of approximately $5,193,000 available to offset future taxable income expiring through 2031. Utilization of these net operating losses may be limited due to potential ownership changes under Section 382 of the Internal Revenue Code.
The valuation allowance at December 31, 2012 was $1,997,000. The net change in valuation allowance during the year ended December 31, 2012 was an increase of $1,709,000. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred income tax assets will not be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on consideration of these items, Management has determined that enough uncertainty exists relative to the realization of the deferred income tax asset balances to warrant the application of a full valuation allowance as of December 31, 2012 and 2011.
Significant deferred tax assets at December 31, 2012 and 2011 are as follows:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
There was no income tax expense for the years ended December 31, 2012 and 2011 due to the Company’s net losses. The Company’s tax expense differs from the “expected” tax expense for the years ended December 31, 2012 and 2011, (computed by applying the Federal Corporate tax rate of 34% to loss before tax and 6.75% for State Corporate taxes for the years ended December 31, 2012 and 2011, the blended rate used was 38% for the years ended December 31, 2012 and 2011, as follows:
The following is a reconciliation of the provision for income taxes at the United States federal income tax rate to the income taxes reflected in the statement of operations:
Note 9. Supplemental Information on Oil and Gas Operations (Unaudited):
This supplementary oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 - “Extractive Activities - Oil and Gas”.
The Company retains qualified independent reserves evaluators to evaluate the Company’s proved oil reserves. The Company does not have any natural gas reserves. For the year ended December 31, 2012 the report by LaRoche Petroleum Consultants (“LaRoche”) covered 100% of the Company’s proved oil reserves.
Proved oil and natural gas reserves, as defined within the SEC Rule 4-10(a)(22) of Regulation S-X, are those quantities of oil and gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time of which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether determinable or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Developed oil and natural gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate is the extraction is by means not involving a well. Estimates of the Company’s oil reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change.
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
The following table summarizes the Company’s proved developed and undeveloped reserves (all oil) within the United States, net of royalties, as of December 31, 2012 and 2011:
Stratex Oil & Gas Holdings, Inc.
(A Development Stage Company)
Notes to Consolidated Financial Statements
December 31, 2012 and 2011
Standardized Measure of Discounted Future Net Cash Flows From Proved Oil Reserves and Changes Therein:
The following standardized measure of discounted future net cash flows from proved oil reserves has been computed using the average first-day-of-the-month price during the previous 12-month period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including:
•
Future production will include production not only from proved properties, but may also include production from probable and possible reserves;
•
Future production of oil and natural gas from proved properties may differ from reserves estimated;
•
Future production rates may vary from those estimated;
•
Future rather than average first-day-of-the-month prices during the previous 12-month period and costs as at the balance sheet date will apply;
•
Economic factors such as changes to interest rates, income tax rates, regulatory and fiscal environments and operating conditions cannot be determined with certainty;
•
Future estimated income taxes do not take into account the effects of future exploration expenditures; and
•
Future development and asset retirement obligations may differ from those estimated.
Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved oil reserves based on the standardized measure as prescribed in FASB Topic 932 - “Extractive Activities - Oil and Gas”:
Note 10 Subsequent Events:
The Company has evaluated for any subsequent events through April 4, 2013, which is the date these consolidated financial statements were available to be issued.
On March 15, 2013, the Company issued a promissory note with principal of $400,000 for proceeds of $400,000. The note bears interest at 12% per annum and will be due in interest only payments for the first 24 months. The note matures on March 14, 2015. In addition, the Company issued the purchaser, 500,000 warrants to purchase shares of the common stock of the Company at $0.85 per share. The warrants mature on March 15, 2018. The note is secured by certain oil and gas assets of the Company.
On January 27, 2013, a noteholder converted $36,000 of principal and interest into 51,429 shares of the Company’s common stock.
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 Our Disclosure Controls
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our periodic reports filed under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our chief executive and chief financial officer, to allow timely decisions regarding required disclosure. As of the end of the period covered by this annual report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our principal executive and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13(a)-15(e) under the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that, as of December 31, 2012, our disclosure controls and procedures were effective.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is 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 consolidated financial statements in accordance with U.S. generally accepted accounting principles, or GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree or compliance with the policies or procedures may deteriorate.
With the participation of our chief executive and chief financial officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based upon our assessment and the COSO criteria, management concluded that our internal control over financial reporting was effective as of December 31, 2012.
Limitations on Effectiveness of Controls and Procedures
Our management, including our chief executive and chief financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include, but are not limited to, the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
Changes in Internal Controls over Financial Reporting
During the fiscal year ended December 31, 2012, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The following persons are our executive officers, non-executive officers and directors and hold the positions set forth opposite their name.
Stephen Funk, Chief Executive Officer and Chairman of the Board
Stephen Funk has served as our Chief Executive Officer since January 2011 and devotes 100% of his professional time to our business. From March 2008 to December 2010, through Alta Investments, LLC, Mr. Funk was a managing member of Cherokee Enterprises LLC, a construction dewatering company to the heavy construction industry whose main services involved drilling water wells and pumping water to lower water tables near major construction projects. From 1999 to March 2008, Mr. Funk operated Alta Investments LLC.
Mr. Funk graduated from Marist College in 1984 with a B.S. in Business Administration, Finance.
Relating to Mr. Funk’s employment with Wellesley Services LLC in 1999: On March 31, 2006, Mr. Funk entered into a Consent Order with the New Jersey Bureau of Securities for alleged violations of the New Jersey Uniform Securities Law, pursuant to which, he agreed to permanent injunctive relief from directly or indirectly violating the NJ Securities Law.
Timothy Kelly, President & Chief Operating Officer, Secretary and Director
Tim Kelly has served as our President and Chief Operating Officer since January 2011 and devotes 100% of his professional time to our business. From May 2009 to January 2011, Mr. Kelly served as General Partner at Lynden Capital where he directed investments in small cap public and private companies. From January 2003 to May 2009, Mr. Kelly served as a Registered Representative at Thomas Group Capital. From March 2001 to October 2002, Mr. Kelly served as a Registered Representative at Donaldson Lufkin & Jenrette Securities Corporation/CS First Boston.
Mr. Kelly graduated from Providence College in 1990 with a B.S. in Business Administration, Marketing.
Relating to Mr. Kelly’s employment at Thomas Group Capital; on January 9, 2012, pursuant to Article VI, Section 3 of the Financial Industry Regulatory Authority (FINRA) bylaws, Mr. Kelly was suspended for failure to comply with an arbitration award or settlement.
Family Relationships
None
Involvement in Certain Legal Proceedings
Except for the disclosure in Mr. Funk’s and Mr. Kelly’s biographies, during the past ten years, none of our directors, executive officers, promoters, control persons, or nominees has:
-
been convicted in a criminal proceeding or been subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
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had any bankruptcy petition filed by or against the business or property of the person, or of any partnership, corporation or business association of which he was a general partner or executive officer, either at the time of the bankruptcy filing or within two years prior to that time;
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been subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction or federal or state authority, permanently or temporarily enjoining, barring, suspending or otherwise limiting, his involvement in any type of business, securities, futures, commodities, investment, banking, savings and loan, or insurance activities, or to be associated with persons engaged in any such activity;
-
been found by a court of competent jurisdiction in a civil action or by the SEC or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;
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been the subject of, or a party to, any federal or state judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated (not including any settlement of a civil proceeding among private litigants), relating to an alleged violation of any federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
-
been the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
Consultants
David Briones, Interim Financial Reporting Consultant
Mr. Briones performs outsourced CFO functions including, preparing annual and quarterly financial statements and accompanying notes in accordance with Generally Accepted Accounting Principles (GAAP) in coordination with our independent auditor and provides consultation in the accounting of complex financial transactions, such as the valuation, recognition, reporting and disclosure of all equity transactions, such as the valuation, recognition, reporting and disclosure of all equity transactions and complex financial instruments.
Mr. Briones is the managing member of Brio Financial Group, an outsourced financial reporting consulting firm. Mr. Briones served as the chief financial officer of Clear-Lite Holdings, Inc. from August 3, 2009 to March 21, 2011 and currently serves as Chief Financial Officer for NXT Nutritional Holdings, Inc., a publicly traded company on the Over the Counter Bulletin Board.
Mr. Briones has a Bachelor of Science in Accounting from Fairfield University, Fairfield, Connecticut.
William Kazmann, LaRoche Petroleum, Ltd.
The technical person primarily responsible for overseeing the preparation of reserves estimates herein is William M. Kazmann. Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has thirty seven years of engineering experience in the oil and gas industry. Mr. Kazmann earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin and has prepared reserves estimates for his employers and his own companies throughout his career. He has prepared and overseen preparation of reports for public filings for LaRoche Petroleum Consultants for the past fifteen years.
Samuel Epstein, Certified Petroleum Geologist
Mr. Epstein heads Geoval Consulting a petroleum geological consulting group. Mr. Epstein’s primary responsibilities will involve the analysis of geochemical, structural, stratigraphic, production maps with respect to existing and potential land holdings along with providing written analysis of the resulting data. Mr. Epstein is a certified petroleum geologist and has over 32 years of experience with integrated complex petroleum geochemical, sedimentological, and structural systems analysis.
Mr. Epstein holds a Bachelors of Science Degree from Brooklyn College, and a Master of Science from Rensselaer Polytechnic Institute. Mr. Epstein has over 25 publications in referenced scientific journals concerning petroleum exploration and production, and the effects of global warming on sea level changes.
Committees of the Board of Directors
The Company does not presently have a separately designated audit committee, compensation committee, nominating committee, executive committee or any other committees of its Board of Directors. As such, the sole director acts in those capacities.
Code of Ethics
The Company has not yet adopted a code of ethics as defined by applicable rules of the SEC.
Section 16(a) Beneficial Ownership Reporting Compliance
Although Section 16(a) of the Securities Exchange Act of 1934 requires directors and executive officers, and persons who own more than five percent of a Company’s securities, to file with the Securities and Exchange Commission initial reports of ownership and reports of changes of ownership of our common stock upon the Company becoming a fully reporting company under the Exchange Act by the Company filing a Form 8-A, we have not registered any class of securities under Section 12 of the Exchange Act and accordingly are not subject to such rules.
Item 11.
Item 11. Executive Compensation.
The following table sets forth information regarding each element of compensation that we paid or awarded to our named executive officers for fiscal years ended December 31, 2012 and 2011.
(1)
Related to the issuance of preferred stock plan during 2012.
(2)
Related to the vesting of options during 2012.
Director Compensation
We have provided no compensation to our employee directors for their services provided as directors.
Employment Agreements
Mr. Funk’s employment agreement is for a period of 5 years, after which the agreement is renewable for 1 year periods, unless the Company or Mr. Funk gives 6 months notice of the intention to terminate the agreement. Mr. Funk receives a salary of $250,000 per year with annual increases of 10% per year. Mr. Funk will also receive an annual cash bonus in an amount to be determined by the Board of Directors.
Mr. Funk has been granted options to acquire 3,000,000 shares of restricted stock of the Company, which shall be subject to, and vest over a period of three (3) years. Additionally, Mr. Funk was issued 50 shares of Stratex Preferred Stock. The shares of Preferred Stock have no liquidation or dividend preference and entitle Mr. Funk to fifty million (50,000,000) votes on all matters submitted to a vote of the shareholders of the Company.
The Company agrees to promptly reimburse Mr. Funk for all reasonable and necessary business expenses, including without limitation, telephone and facsimile charges incurred by him on behalf of the Company. In addition the Company agrees to provide Mr. Funk with a monthly automobile allowance of $750.
Mr. Kelly’s employment agreement is for a period of 5 years, after which the agreement is renewable for 1 year periods, unless the Company or Mr. Kelly gives 6 months notice of the intention to terminate the agreement. Mr. Kelly receives a salary of $250,000 per year with annual increases of 10% per year. Mr. Kelly will also receive an annual cash bonus in an amount to be determined by the Board of Directors.
Mr. Kelly has been granted options to acquire 3,000,000 shares of restricted stock of the Company, which shall be subject to, and vest over a period of three (3) years. Additionally, Mr. Kelly was issued 50 shares of Stratex Preferred Stock. The shares of Preferred Stock have no liquidation or dividend preference and entitle Mr. Kelly to fifty million (50,000,000) votes on all matters submitted to a vote of the shareholders of the Company.
The Company agrees to promptly reimburse Mr. Kelly for all reasonable and necessary business expenses, including without limitation, telephone and facsimile charges incurred by him on behalf of the Company. In addition the Company agrees to provide Mr. Kelly with a monthly automobile allowance of $750.
Outstanding Equity Awards at Fiscal Year End
The following table summarizes the equity awards issued and outstanding as of December 31, 2012.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following tables set forth certain information regarding the beneficial ownership of our Common Stock and Series A Preferred Stock as of April 4, 2013 by (i) each person who, to our knowledge, owns more than 5% of the Common Stock; (ii) each of our directors and executive officers; and (iii) all of our executive officers and directors as a group. Unless otherwise indicated in the footnotes to the following tables, each person named in the table has sole voting and investment power and that person’s address is c/o Stratex Holdings, Inc., 30 Echo Lake Road, Watertown, CT 06795. Shares of Common Stock subject to options or warrants currently exercisable or exercisable within 60 days of April 4, 2013 are deemed outstanding for computing the share ownership and percentage of the person holding such options and warrants, but are not deemed outstanding for computing the percentage of any other person.
(1)
Stephen Funk has voting and dispositive control of the common stock held by Rotary Partners LLC.
(2)
Based on 44,281,127 shares of common stock issued and outstanding
Our officers and directors beneficially own 100% of our outstanding shares of Series A Preferred Stock. Each share of Series A Preferred Stock has 1,000,000 times that number of votes on all matters submitted to stockholders that each share of common stock is entitled to vote at each meeting of stockholders. Collectively the Series A Preferred stock held by our officers and directors equate to 100,000,000 voting shares.
Therefore, Mr. Funk and Mr. Kelly control approximately 69.3% of the voting power of the Company’s share capital and are able to exert a significant degree of influence over our affairs and control over matters requiring shareholder approval, including the election of directors, any amendments to our articles or by-laws and significant corporate transactions. The interests of this concentration of ownership may not always coincide with the Company’s interests or the interests of other shareholders. For instance, officers, directors, and principal shareholders, acting together, could cause the Company to enter into transactions or agreements that it would not otherwise consider. Similarly, this concentration of ownership may have the effect of delaying or preventing a change in control of the Company otherwise favored by our other shareholders. This concentration of ownership could also depress our share price.
Changes in Control
We are not aware of any or a party to arrangements, including any pledge by any person of our securities, the operation of which may at a subsequent date result in a change of control.
Item 13.
Item 13. Certain Relationships and Related Transactions, Director Independence.
Our common stock was forward-split on a 3.5 for 1 basis, with a record date of May 15, 2012 and an effective date of May 31, 2012. As a result of this stock split, there were approximately 6,110,000 shares of the our common stock issued and outstanding before taking into account the issuance of shares of Common Stock in the merger and after giving pro forma effect to the Split-Off of our assets to our former sole officer and director.
Upon the closing of the merger, we transferred all of our operating assets and liabilities to a split off subsidiary which was split-off in consideration for the cancellation of a shareholder loan in the amount of $79,687 owed to our former sole officer and director.
Item 14.
Item 14. Principal Accounting Fees and Services.
The aggregate fees billed for the fiscal years ended December 31, 2012 and 2011 for professional services rendered by the principal accountant.
(1)
fees prior to reverse merger for the audit of the 2011 private company and reverse merger documents
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
The following documents are filed as part of this Annual Report:
1. Financial Statements - The following consolidated financial statements of the Company are contained in Item 8 of this Form 10-K:
●
Report of Independent Registered Public Accountant
●
Consolidated Balance Sheets as of December 31, 2012 and 2011
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Consolidated Statements of Operations for the year ended December 31, 2012 and the periods from January 25, 2011 (Date of Inception) through December 31, 2011 and 2012
●
Consolidated Statements of Stockholders’ Equity (Deficit) for the period from January 25, 2011 (Date of Inception) through December 31, 2012
●
Consolidated Statements of Cash Flows - for the year ended December 31, 2012 and the periods from January 25, 2011 (Date of Inception) through December 31, 2011 and 2012
●
Notes to the Consolidated Financial Statements
2. Financial Statement Schedules were omitted, as they are not required or are not applicable, or the required information is included in the Financial Statements.
3. Exhibits - The exhibits listed in the Exhibit Index immediately preceding the exhibits are filed as part of this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: April 5, 2013
By:
/s/ Tim Kelly
Name: Timothy Kelly
Title: President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated
Date: April 5, 2013
By:
/s/ Stephen Funk
Name: Stephen Funk
Title: Chairman & Chief Executive Officer
Date: April 5, 2013
By:
/s/ Tim Kelly
Name: Timothy Kelly
Title: Director, President and Chief Operating Officer
EXHIBIT INDEX