PART I
ITEM 1. DESCRIPTION OF
BUSINESS
Forward-Looking Statements
Certain
statements, other than purely historical information, including
estimates, projections, statements relating to our business plans,
objectives, and expected operating results, and the assumptions
upon which those statements are based, are “forward-looking
statements.” These forward-looking statements generally are
identified by the words “believes,”
“project,” “expects,”
“anticipates,” “estimates,”
“intends,” “strategy,” “plan,”
“may,” “will,” “would,”
“will be,” “will continue,” “will
likely result,” and similar expressions. Forward-looking
statements are based on current expectations and assumptions that
are subject to risks and uncertainties which may cause actual
results to differ materially from the forward-looking statements.
Our ability to predict results or the actual effect of future plans
or strategies is inherently uncertain. Factors which could have a
material adverse effect on our operations and future prospects
include, but are not limited to: changes in economic conditions,
legislative/regulatory changes, availability of capital, interest
rates, competition, and generally accepted accounting principles.
These risks and uncertainties should also be considered in
evaluating forward-looking statements and undue reliance should not
be placed on such statements.
Our Corporate History and Background
We were incorporated on December 11, 2006 under the laws of the
State of Nevada.
We were originally a company involved in the placing of strength
testing amusement gaming machines called Boxers in venues such as
bars, pubs and nightclubs in the Seattle area, in the State of
Washington. We acquired one Boxer that had been placed in Lynnwood,
Washington. However, the machine was de-commissioned as it needed
material repairs. We were not able to secure sufficient capital for
these repairs and our management decided to change our business
focus to on oil and gas and mineral exploration. On July 12,
2013, the stockholders approved an amendment to change the name of
the Company from Punchline Resources Ltd. to Northern Mineral &
Exploration Ltd. FINRA approved the name change on August 13,
2013.
Northern
Minerals & Exploration Ltd. (the “Company”) is an
emerging natural resource company operating in oil and gas
production in central Texas and exploration for gold and silver in
northern Nevada.
On
November 22, 2017, the Company created a wholly owned subsidiary,
Kathis Energy LLC (“Kathis”), a duly formed Limited
Liability Company formed in the State of Texas, for the purpose of
conducting oil and gas drilling programs in Texas.
On
December 14, 2017, Kathis Energy, LLC and other Limited Partners,
created Kathis Energy Fund 1, LP, a duly formed Limited Partnership
formed in the State of Texas, created for the purpose of raising
funds from investors for its drilling projects.
On May
7, 2018, the Company created a wholly owned subsidiary, ENMEX
Operations LLC (“ENMEX”), a duly formed Limited
Liability Company in the State of Quintana Roo, Mexico for the
purpose of conducting business in Mexico in prospective real estate
development projects. There has been no activity from inception to
date.
Current Business
ENMEX Operations LLC – Wholly owned Subsidiary - Pemer
Bacalar – Resort Development Project
On
September 22, 2017 the Company entered into a Letter of Intent
regarding the Bacalar Project in Mexico. This was followed up with
a Memorandum of Understanding on November 16, 2017. The Company has
a very strong desire to be a part of this large development in any
manner that is possible. On March 13, 2018 a payment of $20,266 was
paid toward the architectural drawings prepared by Callikson. On
April 13, 2019 the MOU was updated. On June 11, 2019 a new
agreement was entered into regarding this property. So far no
additional funds have been provided to this project since the
signing of the MOU on June 11, 2019.
As of
July 31, 2019 the total investment made by the Company toward this
project is $20,266. The Company still has a very strong desire to
continue to pursue to be a part of this large opportunity. As of
July 31, 2019, it is not clear as to what level the Company will be
participating as it is not clearly defined by Pemer Bacalar what is
required. Pemer Bacalar has several requirements on their side of
the June 11, 2019 agreement to accomplish including but not limited
to finalizing the acquisition of additional acreage and obtaining
permits as well as formalize a plan to conduct feasibility studies
etc.
No
demands have been made for funds by Pemer Bacalar since the date of
signing the June 11, 2019 agreement. At this time the Company is
waiting to hear the next step from Pemer Bacalar and then determine
our obligations thereto.
Coleman County, Texas – Three well rework/re-completion
project
On
October 14, 2014, we entered into an agreement to acquire the 206.5
acre J.E. Richey oil and gas lease. This lease area has six known
productive formations. The existing three wells on the lease are
fully equipped. Beginning in May 2015 we started conducting
operations on the three wells to place them back into production.
The rework/re-completion was completed on July 28, 2015 and
production of oil and gas was established. No additional
significant work was conducted on J. E. Richey lease during the
fiscal year ended July 31, 2019. See Item 2 Properties for
additional information.
Coleman County, Texas – J. E. Richey #2A -Proposed New
Well:
The Company has sold working interest in a 20 acre tract on the
J.E. Richey Lease to drill a new well near the ARCO Richey #2 well.
The Company has identified an industry partner to finalize the
funding of the drilling of the J. E. Richey 2A. Plans subsequent to
July 31, 2019 are to drill this well during the quarter ended
January 31, 2020. The Company is negotiating to receive a prospect
fee and a carried working interest in this well. See Item 2
Properties for additional information.
Kathis Energy LLC – Wholly owned Subsidiary:
The Company created a wholly owned subsidiary, Kathis Energy LLC
(“Kathis”), on November 22, 2017 for the purpose of
conducting oil and gas drilling programs in Texas. The Company
agreed to assign to Kathis the Olson and Guy Ranch leases in
exchange for $126,500. Kathis was seeking to raise drilling funds
to drill up to 8 wells. As of July 31, 2019, no wells have been
drilled. Kathis has raised $125,000 and discontinued seeking
funding for its drilling program. See Item 2 Properties for
additional information.
Jones County, Texas – Palo Pinto Reef project
During
the fiscal year ended July 31, 2016 the Company acquired the Olson
lease covering 160 acres in Jones County, Texas. This lease expired
on April 27, 2019. See Item 2 Properties for additional
information.
Riverside Prospects, Runnels County, Texas
On
October 20, 2017 the Company entered into an exclusive option
agreement with Murphree Oil Company to acquire drilling prospects
on four leases in Runnels County near the City of Ballinger, known
as the Riverside Prospects. During the quarter ended April 30,
2018, the Company, through its wholly owned subsidiary, Kathis
Energy LLC, (“Kathis”) paid the lease bonuses for
extending the oil and gas lease period on 548.76 acres covering the
Riverside Prospects. The extension on all four leases expired prior
to July 31, 2019. See Item 2 Properties for additional
information.
89 Guy #4 Well – Cased Hole:
On
April 16, 2018, Kathis Energy acquired the 89 Guy Well #4 located
on a 20-acre tract on the Guy Ranch property in Shackelford County,
Texas. The well is an abandoned cased well that was drilled in
October 2010 and completed in the Patio Sand at the interval of
3,144’ - 3,154’. The interval perforated (3,144 –
3,154’) is above the best productive part of the formation.
See Item 2 Properties for additional information.
McClure 2B Gas Well – Producing:
On
February 6, 2018 the Company acquired the McClure # 2B producing
gas well on a 40-acre oil & gas lease located in Palo Pinto
County near the Community of Graford, Texas. The McClure 2B well is
completed in the Strawn in the interval 2,882’ to
2,940’ and has produced in excess of 70 million cubic feet of
natural gas. On July 31, 2019 the Company entered into an agreement
to convey this lease to the operator of the lease to reduce its
work obligations. See Item 2 Properties for additional
information.
Carter & Foster Wells – Producing:
During
the fiscal year ended July 31, 2018 the Company acquired the Carter
and Foster wells located west of the Community of Atwell, Texas in
Callahan County. The Carter lease consists of 40 acres and has one
well. The Foster lease has 10 acres around each well of the three
wells, all of which are fully equipped with surface and subsurface
equipment. All four wells are completed in the Palo Pinto Limestone
formation at approximately 1,900 feet. On July 31, 2019 the Company
entered into an agreement to convey this lease and ownership rights
to the operator of the lease to reduce its work obligations. See
Item 2 Properties for additional information.
Reeves Lease – Acreage – Palo Pinto Reef
Prospect:
In
August 2018, subsequent to the end of the fiscal year ended July
31, 2018, the Company paid for the geological prospecting fees for
a Palo Pinto Reef prospect in Jones County. The Reeves lease covers
160 acres and is located near Noodle, Texas in Jones County. The
projected depth of the Palo Pinto Reef is 4,300’. The Company
is seeking to recover its geological fees as the lease was never
obtained. See Item 2 Properties for additional
information.
Winnemucca Mountain Property
On
September 14, 2012, our company entered into an option agreement
(as amended and restated on November 15, 2012, February 1, 2013 and
August 26, 2013) with AHL Holdings Ltd., a Nevada corporation, and
Golden Sands Exploration Inc., a company incorporated under the
laws of British Columbia, Canada, wherein we acquired an option to
purchase a revised 80% interest in and to certain mining claims
from AHL Holdings and Golden Sands, which claims form the
Winnemucca Mountain Property in Humboldt County, Nevada. This
Winnemucca Mountain property is currently comprised of 138
unpatented mining claims covering an area of approximately 2,700
acres.
On July
23, 2018, the Company entered into a New Option Agreement with AHL
Holding Ltd & Golden Sands Exploration Inc.
(“Optionors”). This agreement provided for the payment
of $25,000 and the issuance of 3,000,000 shares of the
Company’s common stock. The Company issued the shares and
made the payment of $25,000 per the agreement on July 31, 2018. The
second payment of $25,000 per the terms of the agreement was not
paid when it was due on August 31, 2018 causing the Company to
default on the terms of the July 23, 2018.
On
March 25, 2019 the Company entered into a New Option Agreement with
the Optionors. As stated in the New Option Agreement the Company
has agreed to certain terms and conditions to have the right to
earn an 80% interest in the Property, these terms include cash
payments, issuance of common shares of the Company and work
commitments. See Item 2
Properties for additional information.
Mining Sector
Competition
We are a mineral resource exploration company. We compete with
other mineral resource exploration companies for financing and for
the acquisition of new mineral properties. Many of the mineral
resource exploration companies with whom we compete have greater
financial and technical resources than those available to us.
Accordingly, these competitors may be able to spend greater amounts
on acquisitions of mineral properties of merit, on exploration of
their mineral properties and on development of their mineral
properties. In addition, they may be able to afford more geological
expertise in the targeting and exploration of mineral properties.
This competition could result in competitors having mineral
properties of greater quality and interest to prospective investors
who may finance additional exploration. This competition could
adversely impact on our ability to finance further exploration and
to achieve the financing necessary for us to develop our mineral
properties.
Compliance with Government Regulation
The operation of mines is governed by both federal and state laws.
The Empress Property and the Winnemucca Property are administered
by the United States Department of Interior, Bureau of Land
Management (“BLM”) in Nevada. In general, the federal
laws that govern mining claim location and maintenance and mining
operations on Federal Lands, including the Empress Property and
Winnemucca Property, are administered by the BLM. Additional
federal laws, such as those governing the purchase, transport or
storage of explosives, and those governing mine safety and health,
also apply.
The State of Nevada likewise requires various permits and approvals
before mining operations can begin, although the state and federal
regulatory agencies usually cooperate to minimize duplication of
permitting efforts. Among other things, a detailed reclamation plan
must be prepared and approved, with bonding in the amount of
projected reclamation costs. The bond is used to ensure that proper
reclamation takes place, and the bond will not be released until
that time. The Nevada Division of Environmental Protection (NDEP)
is the state agency that administers the reclamation permits, mine
permits and related closure plans on the project. Local
jurisdictions may also impose permitting requirements, such as
conditional use permits or zoning approvals.
Mining activities at the Properties are also subject to various
environmental laws, both federal and state, including but not
limited to the federal National Environmental Policy
Act, CERCLA (as defined below), the Resource Recovery and
Conservation Act, the
Clean Water
Act, the Clean Air Act
and the Endangered Species
Act, and certain Nevada state
laws governing the discharge of pollutants and the use and
discharge of water. Various permits from federal and state agencies
are required under many of these laws. Local laws and ordinances
may also apply to such activities as waste disposal, road use and
noise levels.
We are committed to fulfilling our requirements under applicable
environmental laws and regulations. These laws and regulations are
continually changing and, as a general matter, are becoming more
restrictive. Our policy is to conduct our business in a manner that
safeguards public health and mitigates the environmental effects of
our business activities. To comply with these laws and regulations,
we have made, and in the future may be required to make, capital
and operating expenditures.
The Comprehensive Environmental
Response, Compensation, and Liability Act of
1980, as amended (CERCLA),
imposes strict, joint, and several liability on parties associated
with releases or threats of releases of hazardous substances.
Liable parties include, among others, the current owners and
operators of facilities at which hazardous substances were disposed
or released into the environment and past owners and operators of
properties who owned such properties at the time of such disposal
or release. This liability could include response costs for
removing or remediating the release and damages to natural
resources. We are unaware of any reason why our properties would
currently give rise to any potential liability under CERCLA. We
cannot predict the likelihood of future liability under CERCLA with
respect to our properties or surrounding areas that have been
affected by historic mining operations.
Under the Resource Conservation and
Recovery Act (RCRA) and related
state laws, mining companies may incur costs for generating,
transporting, treating, storing, or disposing of hazardous or solid
wastes associated with certain mining-related activities. RCRA
costs may also include corrective action or clean up
costs.
Mining operations may produce air emissions, including fugitive
dust and other air pollutants, from stationary equipment, such as
crushers and storage facilities, and from mobile sources such as
trucks and heavy construction equipment. All of these sources are
subject to review, monitoring, permitting, and/or control
requirements under the federal Clean Air Act
and related state air quality laws.
Air quality permitting rules may impose limitations on our
production levels or create additional capital expenditures in
order to comply with the permitting conditions. Under the
federal Clean Water Act
and delegated state water-quality
programs, point-source discharges into “Waters of the
State” are regulated by the National Pollution Discharge
Elimination System (NPDES) program. Section 404 of the
Clean Water
Act regulates the discharge of
dredge and fill material into “Waters of the United
States,” including wetlands. Stormwater discharges also are
regulated and permitted under that statute. All of those programs
may impose permitting and other requirements on our
operations.
The National Environmental Policy
Act (NEPA) requires an
assessment of the environmental impacts of “major”
federal actions. The “federal action” requirement can
be satisfied if the project involves federal land or if the federal
government provides financing or permitting approvals. NEPA does
not establish any substantive standards. It merely requires the
analysis of any potential impact. The scope of the assessment
process depends on the size of the project. An “Environmental
Assessment” (EA) may be adequate for smaller projects. An
“Environmental Impact Statement” (EIS), which is much
more detailed and broader in scope than an EA, is required for
larger projects. NEPA compliance requirements for any of our
proposed projects could result in additional costs or
delays.
The Endangered Species Act
(ESA) is administered by the U.S. Fish
and Wildlife Service of the U.S. Department of Interior. The
purpose of the ESA is to conserve and recover listed endangered and
threatened species and their habitat. Under the ESA,
“endangered” means that a species is in danger of
extinction throughout all or a significant portion of its range.
The term “threatened” under such statute means that a
species is likely to become endangered within the foreseeable
future. Under the ESA, it is unlawful to “take” a
listed species, which can include harassing or harming members of
such species or significantly modifying their habitat. We currently
are unaware of any endangered species issues at our projects that
would have a material adverse effect on our operations. Future
identification of endangered species or habitat in our project
areas may delay or adversely affect our
operations.
U.S. federal and state reclamation requirements often mandate
concurrent reclamation and require permitting in addition to the
posting of reclamation bonds, letters of credit or other financial
assurance sufficient to guarantee the cost of reclamation. If
reclamation obligations are not met, the designated agency could
draw on these bonds or letters of credit to fund expenditures for
reclamation requirements. Reclamation requirements generally
include stabilizing, contouring and re-vegetating disturbed lands,
controlling drainage from portals and waste rock dumps, removing
roads and structures, neutralizing or removing process solutions,
monitoring groundwater at the mining site, and maintaining visual
aesthetics. We are committed to maintaining all of our financial
assurance and reclamation obligations.
We believe that we are currently in compliance with the statutory
and regulatory provisions governing our operations. We hold or will
hold all necessary permits and other authorizations to the extent
that our current or future claims and the associated operations
require them. During the initial phases of our exploration program
there will not be any significant disturbances to the land or
environment and hence, no government approval is
required.
However, we may do business and own properties in a number of
different geographical areas and are therefore subject to the
jurisdictions of a large number of different authorities at
different countries. We plan to comply with all statutory and
regulatory provisions governing our current and future operations.
However, these regulations may increase significant costs of
compliance to us, and regulatory authorities also could impose
administrative, civil and criminal penalties for non-compliance. At
this time, it is not possible to accurately estimate how laws or
regulations would impact our future business. We also can give no
assurance that we will be able to comply with future changes in the
statutes and regulations.
As we do not know the extent of the exploration program that we
will be undertaking, we cannot estimate the cost of the remediation
and reclamation that will be required. Hence, it is impossible at
this time to assess the impact of any capital expenditures on
earnings or our competitive position in the event that a
potentially economic deposit is discovered.
If we are successful in identifying a commercially viable ore body
and we are able to enter into commercial production, due to the
increased environmental impact, the cost of complying with permit
and environmental laws will be greater than in the previous
phases.
Environmental Regulations
We are not aware of any material violations of environmental
permits, licenses or approvals that have been issued with respect
to our operations. We expect to comply with all applicable laws,
rules and regulations relating to our business, and at this time,
we do not anticipate incurring any material capital expenditures to
comply with any environmental regulations or other
requirements.
While our intended projects and business activities do not
currently violate any laws, any regulatory changes that impose
additional restrictions or requirements on us or on our potential
customers could adversely affect us by increasing our operating
costs or decreasing demand for our products or services, which
could have a material adverse effect on our results of
operations.
Oil & Gas Sector
Competition
The petroleum industry is highly competitive. Many of the oil and
gas exploration companies with whom we compete have greater
financial and technical resources than we do. Accordingly, these
competitors may be able to spend greater amounts on acquisitions of
properties of merit and on exploration. In addition, they may be
able to afford greater geological expertise in the targeting and
exploration of resource properties. This competition could result
in our competitors having resource properties of greater quality
and interest to prospective investors who may finance additional
exploration, and to senior exploration companies that may purchase
resource properties or enter into joint venture agreements with
junior exploration companies. This competition could adversely
impact our ability to finance property acquisitions and further
exploration.
We compete with other exploration and early stage operating
companies for financing from a limited number of investors prepared
to make investments in junior companies exploring for conventional
and unconventional oil and gas resources. The presence of competing
oil and gas exploration companies, both major and independent, may
impact our ability to raise additional capital in order to fund our
exploration programs if investors are of the view that investments
in competitors are more attractive based on the merit of the
properties under investigation, and the price of the investment
offered to investors.
Governmental Regulation
Our business is affected by numerous laws and regulations,
including energy, environmental, conservation, tax and other laws
and regulations relating to the oil and natural gas industry. We
have developed internal procedures and policies to ensure that our
operations are conducted in full and substantial environmental
regulatory compliance.
Failure to comply with any laws and regulations may result in the
assessment of administrative, civil and/or criminal penalties, the
imposition of injunctive relief or both. Moreover, changes in any
of these laws and regulations could have a material adverse effect
on business. In view of the many uncertainties with respect to
current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of such
laws and regulations on our future operations.
We believe that our operations comply in all material respects with
applicable laws and regulations and that the existence and
enforcement of such laws and regulations have no more restrictive
an effect on our operations than on other similar companies in the
oil and natural gas industry.
Pricing and Marketing of Natural Gas
In the US, historically, the sale of natural gas in interstate
commerce has been regulated pursuant to the Natural Gas Act of
1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA,
and regulations promulgated thereunder by the Federal Energy
Regulatory Commission, or the FERC. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act, or the Decontrol Act. The
Decontrol Act removed all NGA and NGPA price and non-price controls
affecting wellhead sales of natural gas effective January 1, 1993
and sales by producers of natural gas are uncontrolled and can be
made at market prices. The natural gas industry historically has
been heavily regulated and from time to time proposals are
introduced by Congress and the FERC and judicial decisions are
rendered that impact the conduct of business in the natural gas
industry. We cannot assure you that the less stringent regulatory
approach recently pursued by the FERC and Congress will
continue.
Pricing and Marketing of Oil
In the US, sales of crude oil, condensate and natural gas liquids
are not regulated and are made at negotiated prices. Effective
January 1, 1995, the FERC implemented regulations establishing an
indexing system for transportation rates for oil that allowed for
an increase in the cost of transporting oil to the
purchaser.
Royalties and Incentives
The royalty regime is a significant factor in the profitability of
oil, natural gas and natural gas liquids production. In the US, all
royalties are determined by negotiations between the mineral owner
and the lessee.
Environmental
Like the oil and natural gas industry in general, our properties
are subject to extensive and changing federal, state and local laws
and regulations designed to protect and preserve natural resources
and the environment. The recent trend in environmental legislation
and regulation in the oil and natural gas industry is generally
toward stricter standards, and this trend is likely to continue.
These laws and regulations often require a permit or other
authorization before construction or drilling commences and for
certain other activities; limit or prohibit access, especially in
wilderness areas with endangered or threatened plant or animal
species; impose restrictions on construction, drilling and other
exploration and production activities; regulate air emissions,
wastewater and other production and waste streams from our
operations; impose substantial liabilities for pollution that may
result from our operations; and require the reclamation of certain
lands.
The permits required for many of our operations are subject to
revocation, modification and renewal by issuing authorities.
Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, compliance
orders, and other enforcement actions. We are not aware of any
material noncompliance with current applicable environmental laws
and regulations, and we have no material commitments for capital
expenditures to comply with existing environmental requirements,
however, given the complex regulatory requirements applicable to
our operations, and the rapidly changing nature of environmental
laws in our industry, we cannot predict our future exposure
concerning such matters, and our future costs to achieve
compliance, or remedy potential violations, could be significant.
Our operations require permits and are regulated under
environmental laws, and current or future noncompliance with such
laws, as well as changes to existing laws or interpretations
thereof, could have a significant impact on us, as well as the oil
and natural gas industry in general.
Waste Disposal and Contamination Issues
The federal Comprehensive Environmental Response, Compensation and
Liability Act and comparable state laws may impose strict and joint
and several liability on owners and operators of contaminated sites
and on persons who disposed of or arranged for the disposal of
hazardous substances found at such sites. Under these and other
laws, the government, neighboring landowners and other third
parties may recover the costs of responding to soil and groundwater
contamination and threatened releases of hazardous substances, and
seek recovery for related natural resources damages, personal
injury and property damage. Some of our properties have been used
for exploration and production activities for a number of years by
third parties, and such properties could result in unknown cleanup
liabilities for us.
The federal Resource Conservation and Recovery Act (the "RCRA") and
comparable state statutes govern the management, storage, treatment
and disposal of solid waste and hazardous waste and authorize
imposition of substantial fines and penalties for noncompliance.
Although RCRA classifies certain oil field wastes as
"non-hazardous" (for example, the waters produced from hydraulic
fracturing operations), such wastes could be reclassified as
hazardous wastes in the future, thereby making them subject to more
stringent handling and disposal requirements which could have a
material impact on us.
Water Regulation
The federal Clean Water Act (the "CWA"), the federal Safe Drinking
Water Act (the "SWDA") and analogous state laws restrict the
discharge of wastewater and other pollutants into surface waters or
underground wells and the construction of facilities in wetland
areas without a permit. Federal regulations also require certain
owners or operators of facilities that store or otherwise handle
oil, such as us, to prepare and implement spill prevention, control
countermeasure and response plans relating to the possible
discharge of oil into surface waters. In addition, the Oil
Pollution Act (the "OPA") contains numerous requirements relating
to the prevention of and response to oil spills into waters of the
United States. For onshore and offshore facilities that may affect
waters of the United States, the OPA requires an operator to
demonstrate financial responsibility. Regulations are currently
being developed or considered under federal and state laws
concerning oil pollution prevention and other matters that may
impose additional regulatory burdens on us.
These and similar state laws also govern the management and
disposal of produced waters from the extraction process. Currently,
wastewater associated with oil and natural gas production is
prohibited from being directly discharged to waterways and other
waters of the U.S. While some of the wastewater is reused or
re-injected, a significant amount still requires proper disposal.
As a result, some wastewater is transported to third-party
treatment plants. In October 2011, citing concerns that third-party
treatment plants may not be properly equipped to handle wastewater
from shale gas operations, the United States Environmental
Protection Agency (the "EPA") announced that it will consider
federal pre-treatment standards for these wastewaters. We cannot
predict the EPA's future actions in this regard, but future
regulation of our produced waters or other waste streams could have
a material impact on us.
Air Emissions and Climate Change
The federal Clean Air Act ("CAA") imposes permit requirements and
operational restrictions on certain sources of emissions used in
our operations. In July 2011, the EPA published proposed New Source
Performance Standards ("NSPS") and National Emissions Standards for
Hazardous Air Pollutants ("NESHAPs") that would, if adopted, amend
existing NSPS and NESHAP standards for oil and natural gas
facilities and create new NSPS standards for oil and natural gas
production, transmission and distribution facilities. Importantly,
these standards would include standards for hydraulically fractured
wells. The standards would apply to newly drilled and fractured
wells as well as existing wells that are refractured. A court has
directed the EPA to issue final rules by April 1, 2012. In a report
issued in late 2011, the Shale Gas Production Subcommittee of the
Department of Energy (the "DOE Shale Gas Subcommittee") called on
the EPA to complete the rulemaking quickly and recommended
expanding the shale gas emission sources to be covered by the new
rules. The DOE Shale Gas Subcommittee also encouraged states to
take similar action, and included several other recommendations for
studying and reducing air emissions from shale gas production
activities. Because the EPA's regulations have not yet been
finalized, we cannot at this time predict the impact they may have
on our financial condition or results of operation.
The issue of climate change has received increasing regulatory
attention in recent years. The EPA has issued regulations governing
carbon dioxide, methane and other greenhouse gas ("GHG") emissions
citing its authority under the CAA Several of these regulations
have been challenged in litigation that is currently pending before
the federal D.C. Circuit Court of Appeals. In December 2011, the
EPA issued amendments to a final rule issued in 2010 requiring
reporting of GHG emissions from the oil and natural gas industry.
Under this rule, we are obligated to report to the EPA certain GHG
emissions from our operations. We do not expect that the costs of
this new reporting will be material to us. In a late 2011 report,
the DOE Shale Gas Subcommittee recommended that the EPA expand
reporting requirements for GHG emissions from shale gas emission
sources and include methane in reporting requirements. More
generally, several proposals to regulate GHG emissions have been
proposed in the U.S. Congress, and various states have taken steps
to regulate GHG emissions. The adoption and implementation of
regulations or legislation imposing restrictions or other
regulatory obligations on emissions of GHGs from oil and natural
gas operations could require us to obtain permits or allowances for
our GHG emissions, install new pollution controls, increase our
operational costs, limit our operations or adversely affect demand
for the oil and natural gas produced from our lands.
Regulation of Hydraulic Fracturing
Our industry uses hydraulic fracturing to recover oil and natural
gas in deep shale and other previously inaccessible subsurface
geological formations. Hydraulic fracturing (or "fracking") is a
process to significantly increase production in drilled wells by
creating or expanding cracks, or fractures, in underground
formations by injecting water, sand and other additives into
formations at high pressures. Like others in our industry, we may
use this process as a means to increase the productivity of our
wells. Although hydraulic fracturing has been an accepted practice
in the oil and natural gas industry for many years, its use has
dramatically increased in the last decade, and concerns over its
potential environmental effects have received increasing attention
from regulators and the public.
Under the Safe Drinking Water Act ("SDWA"), the EPA is prohibited
from regulating the injection of fracking fluids through its
underground injection control program, except in limited
circumstances (for example, the EPA has asserted that it has
authority to regulate when diesel is a component of the fluids).
Waters produced from fracking operations must be disposed of in
accordance with federal and state regulations. As discussed above,
the EPA has announced an intention to propose pre-treatment
standards for produced waters that are to be disposed of at
third-party wastewater treatment plants. Separately, the EPA is
studying the effects of fracking on drinking water as a result of
Congressional and public concern over fracking's potential to
impact groundwater supplies, and the EPA has indicated that it
expects to issue its findings later this year.
In that regard, the EPA recently issued a study indicating that
contamination may have resulted from certain fracking operations in
Wyoming. The operator of the wells has challenged the EPA's
findings, contending that other activities may be to blame for
contaminated groundwater in the area, but the EPA's findings can be
expected to draw increased attention to potential groundwater
impacts from fracking. In late 2011, the DOE Shale Gas Subcommittee
recommended further study and coordination of federal, state and
local efforts to determine and monitor potential groundwater
impacts from fracking activities.
Other federal agencies, including the DOE, the Department of
Interior, and the US Congress, are also investigating the potential
impacts of fracking. In addition, bills have been introduced in the
US. Congress to amend the SWDA to allow the EPA to regulate the
injection of fracking fluids, which could require our and similar
operations to meet federal permitting and financial assurance
requirements, adhere to certain construction and testing
specifications, fulfill monitoring, reporting, and recordkeeping
obligations, and meet plugging and abandonment requirements. In
addition, the federal Bureau of Land Management is developing draft
regulations that would require companies drilling on federal land
to disclose details of chemical additives, test the integrity of
wells and report on water use and waste management. In November
2011, the EPA announced that it would solicit public input on
possible reporting requirements for chemicals used in fracking
under the authority of the federal Toxic Substances Control
Act.
States, which traditionally have been the primary regulators of
exploration and production wells, are also considering or have
recently adopted, or may in the future adopt, additional
regulations governing fracking activities. For example, North
Dakota recently adopted regulations, effective April 1, 2012, to
require disclosure of the chemical components of hydraulic
fracturing fluids. We believe that compliance with any new
reporting requirements will not have a material adverse impact on
us. Nonetheless, these disclosures could make it easier for third
parties who oppose fracking to initiate legal proceedings based on
allegations that chemicals used in fracking could contaminate
groundwater.
In addition, concerns have been raised about the potential for
fracking to cause earthquakes through the disposal of produced
waters into Class II underground injection control ("UIC"). The
EPA's current regulatory requirements for such wells do not require
the consideration of seismic impacts when issuing permits. Some
environmentalists have asked the EPA to consider reversing an
exemption that excludes such wastewaters from hazardous waste
rules, which would subject the wastes to more stringent management
and disposal requirements. We cannot predict the EPA's future
actions in this regard. Certain states, such as Ohio, where
earthquakes have been alleged to be linked to fracking activities,
have proposed regulations that would require mandatory reviews of
seismic data and related testing and monitoring as part of the
future permitting process for UIC wells. In addition, certain other
states, including New York, New Jersey and Vermont have sought to
place moratoria on fracking or subject it to more stringent
permitting and well construction and testing requirements.
Additionally, several cities in the State of Colorado voted in
November 2013 to ban or restrict fracking activities within their
city limits.
Research and Development Expenditures
We have not incurred any research and development expenditures over
the past two fiscal years.
Employees
As of July 31, 2019, we do not
have any employees. Our four officers, Ivan Webb, Noel Schaefer,
Victor Miranda and Robert Campbell act as consultants. Mr. Schaefer
was appointed as Chief Operating Officer on July 6, 2018. Mr.
Miranda was appointed as Chief Financial Officer on July 6, 2018.
Mr. Webb was appointed as Chief Executive Officer on July 6, 2018.
On October 17, 2018, Mr. Autrey resigned as the Company secretary
and Mr. Robert Campbell was appointed to fill the office as
Secretary of the Company. There were no disagreements between the
Company and Mr. Autrey at the time of his resignation.
We engage contractors from time to time to consult with us on
specific corporate affairs or to perform specific tasks in
connection with our exploration programs.
Subsidiaries
On
November 22, 2017, the Company created a wholly owned subsidiary,
Kathis Energy LLC (“Kathis”), a duly formed Limited
Liability Company formed in the State of Texas, for the purpose of
conducting oil and gas drilling programs in Texas.
On
December 14, 2017, Kathis Energy, LLC and other Limited Partners,
created Kathis Energy Fund 1, LP, a duly formed Limited Partnership
formed in the State of Texas, created for the purpose of raising
funds from investors for its drilling projects.
On May
7, 2018, the Company created a wholly owned subsidiary, ENMEX
Operations LLC (“ENMEX”), a duly formed Limited
Liability Company in the State of Quintana Roo, Mexico for the
purpose of conducting business in Mexico in prospective real estate
development projects.
Intellectual Property
We do not own, either legally or beneficially, any patent or
trademark.
Risks Related To Our Overall Business Operations
Effects of COVID-19 to our business.
On January 30, 2020, the World Health Organization declared the
coronavirus outbreak a "Public Health Emergency of International
Concern" and on March 10, 2020, declared it to be a pandemic.
Actions taken around the world to help mitigate the spread of the
coronavirus include restrictions on travel, and quarantines in
certain areas, and forced closures for certain types of public
places and businesses. The coronavirus and actions taken to
mitigate it have had and are expected to continue to have an
adverse impact on the economies and financial markets of many
countries, including the geographical area in which the Company
operates. While it is unknown how long these conditions will last
and what the complete financial effect will be to the company, to
date, the Company is experiencing declining revenues; difficulty
meeting debt covenants; significant changes in the fair value of
assets or liabilities. Our concentrations due to concentrated
revenues from particular oil & gas leases and fund-raising
events; make it reasonably possible that we are vulnerable to the
risk of a near-term severe impact.
Additionally, it is reasonably possible that estimates made in the
financial statements have been, or will be, materially and
adversely impacted in the near term as a result of these
conditions, including losses on investments; impairment losses and
other long-lived assets and contingent obligations.
We have a limited operating history with significant losses and
expect losses to continue for the foreseeable future.
We have yet to establish any history of profitable operations. As
at July 31, 2019,
we have an accumulated deficit of
$2,964,073 and total
stockholders’ deficit of $839,276. We began
generating revenues in October 2015. We expect that our revenues
will not be sufficient to sustain our operations for the foreseeable
future. Our profitability will require our investments in oil
and gas properties to become cash flow positive and/or the
successful commercialization of our mining properties. We may
not be able to successfully obtain a positive cash flow from our
oil and gas investments or through commercializing our mining
properties or ever become profitable.
There is doubt about our ability to continue as a going concern due
to recurring losses from operations, accumulated deficit and
insufficient cash resources to meet our business objectives, all of
which means that we may not be able to continue
operations.
Our independent auditors have added an explanatory paragraph to
their audit opinion issued in connection with the financial
statements for the years ended July 31, 2019 and 2018, respectively,
with respect to their doubt about our ability to continue as a
going concern. As discussed in Note 3 to our financial
statements for the year ended July 31, 2019, we have generated
operating losses since inception, and our cash resources are
insufficient to meet our planned business objectives, which
together raises doubt about our
ability to continue as a going concern.
We may not be able to conduct successful operations in the
future.
The
results of our operations will depend, among other things, upon our
ability to develop and market our properties. Furthermore, our
proposed operations may not generate income sufficient to meet
operating expenses or will generate income and capital
appreciation, if any, at rates lower than those anticipated or
necessary to sustain ourselves. Our operations may be affected by
many factors, some known by us, some unknown, and some which are
beyond our control. Any of these problems, or a combination
thereof, could have a materially adverse effect on our viability as
an entity and might cause the investment of our shareholders to be
impaired or lost.
To fully develop our business plan, we will need additional
financing.
For the
foreseeable future, we expect to rely principally upon external
financing, although we have raised limited private placement and
debt instrument funds during the past fiscal year and will be
required to do so in the future. We cannot guarantee the success of
this plan. We believe that from time to time, we may have to obtain
additional financing in order to conduct our business in a manner
consistent with our proposed operations. There can be no guaranty
that additional funds will be available when, and if, needed. If we
are unable to obtain financing, or if its terms are too costly, we
may be forced to curtail proposed expansion of operations until
such time as alternative financing may be arranged, which could
have a materially adverse impact on our operations and our
shareholders' investment.
We lack working capital.
We
currently lack the capital necessary to independently sustain our
operations. Management is actively negotiating financing through
accredited investors and other sources to meet its short term
working capital needs and is negotiating long term capital options.
There can be no guaranty that additional funds will be available.
If we are unable to obtain financing, or if its terms are too
costly, we may be forced to curtail proposed expansion of
operations until such time as alternative financing may be
arranged, which could have a materially adverse impact on our
operations and our shareholders' investment.
We have limited human resources necessary to expand
operations.
We have
a small staff of skilled developers and supplement our human
resource needs through sub-contracting. We are planning to acquire
additional resources internally thereby reducing the use of
sub-contractors and increasing direct control over our operations.
If we are unable to acquire additional resources internally we will
be forced to use sub-contractors that may or may not be available
to work when and where we need them thereby limiting our ability to
expand operations as we intend.
Our ultimate success will be dependent upon
management.
Our
success is dependent upon the decision making of certain key
directors and executive officers including Noel Schaefer, Victor
Miranda and Ivan Webb. These individuals intend to commit as much
time as necessary to our business. The loss of any or all of these
individuals could have an adverse impact on our operations. We
currently do not have not key man life insurance on the lives of
any of these officers and directors.
We may not be able to secure additional financing to meet our
future capital needs due to changes in general economic
conditions.
We anticipate needing significant capital to conduct further
exploration and development needed to bring our existing oil and
gas and mining properties into production and/or to continue to
seek out appropriate joint venture partners or buyers for certain
mining properties. We may use capital more rapidly than
currently anticipated and incur higher operating expenses than
currently expected, and we may be required to depend on external
financing to satisfy our operating and capital needs. We may
need new or additional financing in the future to conduct our
operations or expand our business. Any sustained weakness in
the general economic conditions and/or financial markets in the
United States or globally could adversely affect our ability to
raise capital on favorable terms or at all. From time to time
we have relied, and may also rely in the future, on access to
financial markets as a source of liquidity to satisfy working
capital requirements and for general corporate purposes. We
may be unable to secure debt or equity financing on terms
acceptable to us, or at all, at the time when we need such
funding. If we do raise funds by issuing additional equity or
convertible debt securities, the ownership percentages of existing
stockholders would be reduced, and the securities that we issue may
have rights, preferences or privileges senior to those of the
holders of our common stock or may be issued at a discount to the
market price of our common stock which would result in dilution to
our existing stockholders. If we raise additional funds by
issuing debt, we may be subject to debt covenants, which could
place limitations on our operations including our ability to
declare and pay dividends. Our inability to raise additional
funds on a timely basis would make it difficult for us to achieve
our business objectives and would have a negative impact on our
business, financial condition and results of
operations.
Our properties are in the exploration stage. There is no assurance
that we can establish the existence of any mineral resource on any
of our properties in commercially exploitable quantities. Until we
can do so, we can earn very little revenues from operations and if
we do not do so we will lose all of the funds that we expend on
exploration. If we do not discover any mineral resource in a
commercially exploitable quantity, our business could
fail.
Despite exploration work on our mineral properties, we have not
established that our properties have sufficient mineral reserve to
justify a mining operation, and there can be no assurance that we
will be able to do so. If we do not, our business could
fail.
A mineral reserve is defined by the Securities and Exchange
Commission in its Industry Guide 7 (which can be viewed over the
Internet at http://www.sec.gov/divisions/corpfin/forms/industry.htm#secguide7)
as that part of a mineral deposit which could be economically and
legally extracted or produced at the time of the reserve
determination. The probability of an individual prospect ever
having a "reserve" that meets the requirements of the Securities
and Exchange Commission's Industry Guide 7 is extremely remote; in
all probability our mineral resource properties do not contain any
'reserve' and any funds that we spend on exploration will probably
be lost.
Even if we do eventually discover a mineral reserve on any of our
properties, there can be no assurance that we will be able to
develop any of our properties into a producing mine and extract
those resources. Both mineral exploration and development involve a
high degree of risk and few properties which are explored are
ultimately developed into producing mines.
The commercial viability of an established mineral deposit will
depend on a number of factors including, by way of example, the
size, grade and other attributes of the mineral deposit, the
proximity of the resource to infrastructure such as a smelter,
roads and a point for shipping, government regulation and market
prices. Most of these factors will be beyond our control, and any
of them could increase costs and make extraction of any identified
mineral resource unprofitable.
Mineral operations are subject to applicable law and government
regulation. Even if we discover a mineral resource in a
commercially exploitable quantity, these laws and regulations could
restrict or prohibit the exploitation of that mineral resource. If
we cannot exploit any mineral resource that we might discover on
any of our properties, our business may fail.
Both mineral exploration and extraction require permits from
various foreign, federal, state, provincial and local governmental
authorities and are governed by laws and regulations, including
those with respect to prospecting, mine development, mineral
production, transport, export, taxation, labor standards,
occupational health, waste disposal, toxic substances, land use,
environmental protection, mine safety and other matters. There can
be no assurance that we will be able to obtain or maintain any of
the permits required for the continued exploration of our mineral
properties or for the construction and operation of a mine on our
properties at economically viable costs. If we cannot accomplish
these objectives, our business could fail.
We believe that we are in compliance with all material laws and
regulations that currently apply to our activities but there can be
no assurance that we can continue to remain in compliance. Current
laws and regulations could be amended and we might not be able to
comply with them, as amended. Further, there can be no assurance
that we will be able to obtain or maintain all permits necessary
for our future operations, or that we will be able to obtain them
on reasonable terms. To the extent such approvals are required and
are not obtained, we may be delayed or prohibited from proceeding
with planned exploration or development of our mineral
properties.
If we establish the existence of a mineral resource on any of our
properties in a commercially exploitable quantity, we will require
additional capital in order to develop the property into a
producing mine. If we cannot raise this additional capital, we will
not be able to exploit the resource, and our business could
fail.
If we do discover mineral resources in commercially exploitable
quantities on any of our properties, we will be required to expend
substantial sums of money to establish the extent of the resource,
develop processes to extract it and develop extraction and
processing facilities and infrastructure. Although we may derive
substantial benefits from the discovery of a major deposit, there
can be no assurance that any discovered resource will be large
enough to justify commercial operations, nor can there be any
assurance that we will be able to raise the funds required for
development on a timely basis. If we cannot raise the necessary
capital or complete the necessary facilities and infrastructure,
our business may fail.
Mineral exploration and development is subject to extraordinary
operating risks. We do not currently insure against these risks. In
the event of a cave-in or similar occurrence, our liability may
exceed our resources, which would have an adverse impact on our
company.
Mineral exploration, development and production involve many risks
which even a combination of experience, knowledge and careful
evaluation may not be able to overcome. Our operations will be
subject to all the hazards and risks inherent in the exploration
for mineral resources and, if we discover a mineral resource in
commercially exploitable quantity, our operations could be subject
to all of the hazards and risks inherent in the development and
production of resources, including liability for pollution,
cave-ins or similar hazards against which we cannot insure or
against which we may elect not to insure. Any such event could
result in work stoppages and damage to property, including damage
to the environment. We do not currently maintain any insurance
coverage against these operating hazards. The payment of any
liabilities that arise from any such occurrence would have a
material adverse impact on our company.
Mineral prices are subject to dramatic and unpredictable
fluctuations.
We expect to derive revenues, if any, either from the sale of our
mineral resource properties or from the extraction and sale of ore.
The price of those commodities has fluctuated widely in recent
years, and is affected by numerous factors beyond our control,
including international, economic and political trends,
expectations of inflation, currency exchange fluctuations, interest
rates, global or regional consumptive patterns, speculative
activities and increased production due to new extraction
developments and improved extraction and production methods. The
effect of these factors on the price of base and precious metals,
and therefore the economic viability of any of our exploration
properties and projects, cannot accurately be
predicted.
The mining industry is highly competitive and there is no assurance
that we will continue to be successful in acquiring mineral claims.
If we cannot continue to acquire properties to explore for mineral
resources, we may be required to reduce or cease
operations.
The mineral exploration, development, and production industry is
largely un-integrated. We compete with other exploration companies
looking for mineral resource properties. While we compete with
other exploration companies in the effort to locate and acquire
mineral resource properties, we will not compete with them for the
removal or sales of mineral products from our properties if we
should eventually discover the presence of them in quantities
sufficient to make production economically feasible. Readily
available markets exist worldwide for the sale of mineral products.
Therefore, we will likely be able to sell any mineral products that
we identify and produce.
In identifying and acquiring mineral resource properties, we
compete with many companies possessing greater financial resources
and technical facilities. This competition could adversely affect
our ability to acquire suitable prospects for exploration in the
future. Accordingly, there can be no assurance that we will acquire
any interest in additional mineral resource properties that might
yield reserves or result in commercial mining
operations.
Risks Associated With Our Mining Industry
The development and operation of our mining projects involve
numerous uncertainties.
Mine development projects, including our planned projects,
typically require a number of years and significant expenditures
during the development phase before production is
possible.
Development projects are subject to the completion of successful
feasibility studies, issuance of necessary governmental permits and
receipt of adequate financing. The economic feasibility of
development projects is based on many factors such as:
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estimation of reserves;
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anticipated metallurgical recoveries;
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future gold and silver prices; and
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anticipated capital and operating costs of such
projects.
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Our mine development projects may have limited relevant operating
history upon which to base estimates of future operating costs and
capital requirements. Estimates of proven and probable
reserves and operating costs determined in feasibility studies are
based on geologic and engineering analyses.
Any of the following events, among others, could affect the
profitability or economic feasibility of a project:
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unanticipated changes in grade and tonnage of material to be mined
and processed;
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unanticipated adverse geotechnical conditions;
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incorrect data on which engineering assumptions are
made;
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costs of constructing and operating a mine in a specific
environment;
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availability and cost of processing and refining
facilities;
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availability of economic sources of power;
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adequacy of water supply;
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adequate access to the site;
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unanticipated transportation costs;
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government regulations (including regulations relating to prices,
royalties, duties, taxes, restrictions on production, quotas on
exportation of minerals, as well as the costs of protection of the
environment and agricultural lands);
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fluctuations in metal prices; and
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accidents, labor actions and force majeure events.
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Any of the above referenced events may necessitate significant
capital outlays or delays, may materially and adversely affect the
economics of a given property, or may cause material changes or
delays in our intended exploration, development and production
activities. Any of these results could force us to curtail or
cease our business operations.
Mineral exploration is highly speculative, involves substantial
expenditures, and is frequently non-productive.
Mineral exploration involves a high degree of risk and exploration
projects are frequently unsuccessful. Few prospects that are
explored end up being ultimately developed into producing
mines. To the extent that we continue to be involved in
mineral exploration, the long-term success of our operations will
be related to the cost and success of our exploration programs. We
cannot assure you that our mineral exploration efforts will be
successful. The risks associated with mineral exploration
include:
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the identification of potential economic mineralization based on
superficial analysis;
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the quality of our management and our geological and technical
expertise; and
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the capital available for exploration and development.
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Substantial expenditures are required to determine if a project has
economically mineable mineralization. It may take several
years to establish proven and probable reserves and to develop and
construct mining and processing facilities. Because of these
uncertainties, our current and future exploration programs may not
result in the discovery of reserves, the expansion of our existing
reserves or the further development of our mines.
The price of gold and silver are highly volatile and a decrease in
the price of gold or silver would have a material adverse effect on
our business.
The profitability of mining operations is directly related to the
market prices of metals. The market prices of metals fluctuate
significantly and are affected by a number of factors beyond our
control, including, but not limited to, the rate of inflation, the
exchange rate of the dollar to other currencies, interest rates,
and global economic and political conditions. Price
fluctuations of metals from the time development of a mine is
undertaken to the time production can commence can significantly
affect the profitability of a mine. Accordingly, we may begin
to develop one or more of our mining properties at a time when the
price of metals makes such exploration economically feasible and,
subsequently, incur losses because the price of metals
decreases. Adverse fluctuations of the market prices of metals
may force us to curtail or cease our business
operations.
Mining risks and insurance could have an adverse effect on our
profitability.
Our operations are subject to all of the operating hazards and
risks normally incident to exploring for and developing mineral
properties, such as unusual or unexpected geological formations,
environmental pollution, personal injuries, flooding, cave-ins,
changes in technology or mining techniques, periodic interruptions
because of inclement weather and industrial
accidents. Although maintenance of insurance to ameliorate
some of these risks is part of our proposed exploration program
associated with those mining properties we have an interest in,
such insurance may not be available at economically feasible rates
or in the future be adequate to cover the risks and potential
liabilities associated with exploring, owning and operating our
properties. Either of these events could cause us to curtail
or cease our business operations.
We face significant competition in the mineral exploration
industry.
We compete with other mining and exploration companies possessing
greater financial resources and technical facilities than we do in
connection with the acquisition of exploration properties and
leases on prospects and properties and in connection with the
recruitment and retention of qualified personnel. Such
competition may result in our being unable to acquire interests in
economically viable gold and silver exploration properties or
qualified personnel.
Our applications for exploration permits may be delayed or may be
denied in the future.
Exploration activities usually require the granting of permits from
various governmental agencies. For exploration drilling on
unpatented mineral claims, a drilling plan must be filed with the
Bureau of Land Management or the United States Forest Service,
which may then take several months or more to grant the requested
permit. Depending on the size, location and scope of the
exploration program, additional permits may also be required before
exploration activities can be undertaken. Prehistoric or Indian
grave yards, threatened or endangered species, archeological sites
or the possibility thereof, difficult access, excessive dust and
important nearby water resources may all result in the need for
additional permits before exploration activities can
commence. With all permitting processes, there is the risk
that unexpected delays and excessive costs may be experienced in
obtaining required permits or the refusal to grant required permits
may not be granted at all, all of which may cause delays and
unanticipated costs in conducting planned exploration
activities. Any such delays or unexpected costs in the
permitting process could result in serious adverse consequences to
the price of our stock and to the value of your
investment.
Risks Associated With Our Oil & Gas Industry
A substantial or extended decline in oil and natural gas prices or
demand for oil and gas products may adversely affect our business,
financial condition, cash flow, liquidity or results of operations
and our ability to meet our capital expenditure obligations and
financial commitments and to implement our business
strategy.
The price we receive for our oil and natural gas production will
heavily influence our revenue, profitability, access to capital,
and future rate of growth. Recent extremely high prices have
affected the demand for oil and gas products, and that demand has
declined on a worldwide basis. If the decline in demand continues,
the ability to command higher prices for oil and gas products will
be endangered. Oil and natural gas are commodities, and, therefore,
their prices are subject to wide fluctuations in response to
relatively minor changes in supply and demand. Historically, the
markets for oil and natural gas have been volatile. These markets
will likely continue to be volatile in the future. The prices we
receive for our production, and the levels of our production, and
the revenue we will receive, depend on numerous factors beyond our
control. These factors include the following:
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changes in global supply and demand for oil and natural
gas;
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the actions of the Organization of Petroleum Exporting Countries
("OPEC") and other organizations and government
entities;
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the price and quantity of imports of foreign oil and natural
gas;
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political conditions and events worldwide, including rules
concerning production and environmental protection, and political
instability in countries with significant oil production such as
the Congo and Venezuela, all affecting oil-producing
activity;
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the level of global oil and natural gas exploration and production
activity;
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the short and long term levels of global oil and natural gas
inventories;
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technological advances affecting the exploitation for oil and gas,
and related advances for energy consumption; and
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the price and availability of alternative fuels.
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Lower oil and natural gas prices may not only decrease our revenues
but may also reduce the amount of oil and natural gas that we can
produce economically. A substantial or extended decline in oil or
natural gas prices is likely to materially and adversely affect our
future business, financial condition, results of operations,
liquidity or ability to finance planned capital
expenditures.
We plan to conduct exploration, exploitation and production
operations, which present additional unique operating
risks.
There are additional risks associated with oil and gas investment
which involve production and well operations and drilling. These
risks include, among others, substantial cost overruns and/or
unanticipated outcomes that may result in uneconomic projects or
wells. Cost overruns could materially reduce the funds available to
the Company, and cost overruns are common in the oil and gas
industry. Moreover, drilling expense and the risk of mechanical
failure can be significantly increased in wells drilled to greater
depths and where one is more likely to encounter adverse conditions
such as high temperature and pressure.
We may not be able to control operations of the wells we
acquire.
We may not be able to acquire the operations for properties that we
invest in. As a result, we may have limited ability to exercise
influence over the operations for these properties or their
associated costs. Our dependence on another operator and other
working interest owners for these projects and our limited ability
to influence operations and associated costs could prevent the
realization of our targeted returns on capital in drilling or
acquisition activities. The success and timing of development and
exploitation activities on properties operated by others depend
upon a number of factors that will be largely outside of our
control, including:
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the timing and amount of capital expenditures;
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the availability of suitable drilling rigs, drilling equipment,
production and transportation infrastructure and qualified
operating personnel;
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the operator's expertise and financial resources;
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approval of other participants in drilling wells; and
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selection of technology.
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We may not be successful in identifying or developing recoverable
reserves.
Our future success depends upon our ability to acquire and develop
oil and gas reserves that are economically recoverable. Proved
reserves will generally decline as reserves are depleted, except to
the extent that we can replace those reserves by exploration and
development activities or acquisition of properties contain
exploration, drilling and recompletion programs or other
replacement activities. Our current strategy includes increasing
our reserve base through development, exploitation, exploration and
acquisition. There can be no assurance that our planned development
and exploration projects or acquisition activities will result in
significant additional reserves or that we will have continuing
success drilling productive wells at economical values in terms of
their finding and development costs. Furthermore, while our
revenues may increase if oil and gas prices increase significantly,
finding costs for additional reserves have increased during the
last few years. It is possible that product prices will decline
while the Company is in the middle of executing its plans, while
costs of drilling remain high. There can be no assurance that we
will replace reserves or replace our reserves
economically.
Our future oil & gas activities may not be
successful.
Oil and gas activities are subject to many risks, including the
risk that no commercially productive reservoirs will be
encountered. There can be no assurance that new wells drilled by us
will be productive or that we will recover all or any portion of
our investment. Drilling for oil and gas 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. The cost of
drilling, completing and operating wells is often uncertain, and
the cost associated with these activities has risen significantly
during the past year. Our drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, many of which
are beyond our control, including economic conditions, mechanical
problems, title problems, weather conditions, governmental
requirements and shortages or delays in the delivery of equipment
and services. Our future oil and gas activities may not be
successful and, if unsuccessful, such failure may have a material
adverse effect on our future results of operations and financial
condition.
Our operations are subject to risks associated with drilling or
producing and transporting oil and gas.
Our operations are subject to hazards and risks inherent in
drilling or producing and transporting oil and gas, such as fires,
natural disasters, explosions, encountering formations with
abnormal pressures, blowouts, cratering, pipeline ruptures and
spills, any of which can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to
our properties.
The lack of availability or high cost of drilling rigs, fracture
stimulation crews, equipment, supplies, insurance, personnel and
oil field services could adversely affect our ability to execute
our exploration and development plans on a timely basis and within
our budget.
Our industry is cyclical and, from time to time, there is a
shortage of drilling rigs, fracture stimulation crews, equipment,
supplies, key infrastructure, insurance or qualified personnel.
During these periods, the costs and delivery times of rigs,
equipment and supplies are substantially greater. In addition, the
demand for, and wage rates of, qualified crews rise as the number
of active rigs and completion fleets in service increases. If
increasing levels of exploration and production result in response
to strong prices of oil and natural gas, the demand for oilfield
services will likely rise, and the costs of these services will
likely increase, while the quality of these services may suffer. If
the lack of availability or high cost of drilling rigs, equipment,
supplies, insurance or qualified personnel were particularly severe
in Texas, we could be materially and adversely affected because our
operations and properties are concentrated in Texas at the present
time.
Compliance with government regulations may require significant
expenditures.
Our business is subject to federal, state and local laws and
regulations relating to the exploration for, and the development,
production and transportation of oil and gas, as well as safety
matters. Although we will attempt to conduct due diligence
concerning standard compliance issues, there is a heightened risk
that our target properties are not in compliance because of lack of
funding. We may be required to make significant expenditures to
comply with governmental laws and regulations that may have a
material adverse effect on our financial condition and results of
operations. Even if the properties are in substantial compliance
with all applicable laws and regulations, the requirements imposed
by such laws and regulations are frequently changed and are subject
to interpretation, and we are unable to predict the ultimate cost
of compliance with these requirements or their effect on our
operations.
Environmental regulations and costs of remediation could have a
material adverse effect on our operations.
Our operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and
local government authorities. The implementation of new, or the
modification of existing, laws or regulations could have a material
adverse effect on our operations. The discharge of oil, gas or
other pollutants into the air, soil, or water may give rise to
significant liabilities on our part to the government and third
parties, and may require us to incur substantial costs of
remediation. We will be required to consider and negotiate the
responsibility of the Company for prior and ongoing environmental
liabilities. We may be required to post or assume bonds or other
financial guarantees with the parties from whom we purchase
properties or with governments to provide financial assurance that
we can meet potential remediation costs. There can be no assurance
that existing environmental laws or regulations, as currently
interpreted or reinterpreted in the future, or future laws or
regulations will not materially adversely affect our results of
operation and financial condition or that material indemnity claims
will not arise against us with respect to properties acquired by
us.
Certain United States federal income tax deductions currently
available with respect to oil and natural gas exploration and
production may be eliminated as a result of future
legislation.
Recently, there has been significant discussion among members of
Congress regarding potential legislation that, if enacted into law,
would eliminate certain key United States federal income tax
incentives currently available to oil and natural gas exploration
and production companies. These changes include, among other
proposals:
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the repeal of the limited percentage depletion allowance for oil
and natural gas production in the United States;
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the replacement of expensing intangible drilling and development
costs in the year incurred with an amortization of those costs over
several years;
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the elimination of the deduction for certain domestic production
activities; and
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an extension of the amortization period for certain geological and
geophysical expenditures.
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It is unclear whether these or similar changes will be enacted. The
passage of this legislation or any similar changes in federal
income tax laws could eliminate or postpone certain tax deductions
that are currently available with respect to U.S. oil and natural
gas exploration and development. Any such changes could have an
adverse effect on our financial position, results of operations and
cash flows.
We operate in a highly competitive environment.
We operate in the highly competitive areas of oil and gas
exploration, development, acquisition and production with other
companies. In seeking to acquire desirable producing properties or
new leases for future exploration, and in marketing our oil and gas
production, we face intense competition from both major and
independent oil and gas companies. If any of these competitors have
financial and other resources substantially in excess of those
available to us. Our inability to effectively compete in this
environment could materially and adversely affect our financial
condition and results of operations.
The producing life of oil and gas wells is uncertain, and
production will decline.
It is not possible to predict the life and production of any oil
and gas wells with accuracy. The actual life could differ
significantly from that anticipated. Sufficient oil or natural gas
may not be produced for investors to receive a profit or even to
recover their initial investments. In addition, production from the
Company's oil and natural gas wells, if any, will decline over
time, and current production does not necessarily indicate any
consistent level of future production. A production decline may be
rapid and irregular when compared to a well's initial
production.
Our lack of diversification will increase the risk of an investment
in us, as our financial condition may deteriorate if we fail to
diversify.
Larger companies have the ability to manage their risk by
diversification. However, we lack diversification, in terms of both
the nature and geographic scope of our business. As a result, we
will likely be impacted more acutely by factors affecting our
industry or the regions in which we operate than we would 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. The Company has a limited
number of potential revenue generating properties. These properties
historically had revenue derived from the sale of natural gas and
oil. Therefore, the price we receive for our oil and natural gas
production heavily influences our revenue, profitability, access to
capital and future rate of growth.
Our business may suffer if we do not attract and retain talented
personnel.
Our success will depend in large measure on the abilities,
expertise, judgment, discretion, integrity and good faith of our
management and other personnel in conducting our intended business.
We presently have a small management team which we intend to expand
in conjunction with our planned operations and growth. The loss of
a key individual, or our inability to attract suitably qualified
staff could materially adversely impact our business.
We may not be able to establish substantial oil operations or
manage our growth effectively, which may harm our
profitability.
Our strategy envisions establishing and expanding our oil business.
If we fail to effectively establish sufficient oil operations and
thereafter 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 development 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
you 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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incorporate effectively the components of any business that we may
acquire in our effort to achieve growth.
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If we are unable to manage our growth, our operations and our
financial results could be adversely affected by inefficiency,
which could diminish our profitability.
Relationships upon which we may rely are subject to change, which
may diminish our ability to conduct our operations.
To develop our business, it will be necessary for us to establish
business relationships, which may take the form of joint ventures
with private parties and contractual arrangements with other
unconventional oil companies, including those that supply equipment
and other resources that we expect to use in our business. We may
not be able to establish these 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 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.
An increase in royalties payable may make our operations
unprofitable.
Any development project of our resource assets will be directly
affected by the royalty regime applicable. The economic benefit of
future capital expenditures for the project is, in many cases,
dependent on a satisfactory royalty regime. There can be no
assurance that governments will not adopt a new royalty regime that
will make capital expenditures uneconomic or that the royalty
regime currently in place will remain unchanged.
Hydraulic fracturing, the process used for releasing oil and
natural gas from shale rock, has recently come under increased
scrutiny and could be the subject of further regulation that could
impact the timing and cost of development.
Recently there has been increasing public and regulatory attention
focused on the potential environmental impact of hydraulic
fracturing (or "fracking") operations. This process, which involves
the injection of water, sand and certain additives deep underground
to release natural gas, natural gas liquids and oil deposits, is
part of our proposed future operations and future regulation of
these activities could have a material adverse impact on our
business, financial condition and results of
operations.
Various government agencies, political representatives and public
interest groups have raised concerns about the potential for
fracking to lead to groundwater contamination, and various
regulatory and legislative measures have been proposed or adopted
at the federal, state and local level to study or monitor related
concerns, to regulate well operations and related production and
waste streams, or to ban fracking entirely. For example, various
states and federal regulatory authorities require or are
considering requiring public disclosure of the chemicals contained
in fracking fluids, and testing and monitoring obligations relating
to well integrity and operation. North Dakota, a state in which we
conduct operations, recently amended its current regulations to
require additional pollution control equipment at well sites and
enhanced emergency response procedures in addition to other
measures designed to reduce potential environmental impacts. In
2011, the EPA announced its intention to consider pre-treatment
standards for produced waters that are sent to third party
wastewater treatment plants.
In addition, bills have been proposed in the US. Congress to allow
the EPA to regulate the injection of fracking fluids under the
federal Safe Drinking Water Act, which could require hydraulic
fracturing operations to meet federal permitting and financial
assurance requirements, adhere to certain construction
specifications, fulfill monitoring, reporting, and record keeping
obligations, and meet plugging and abandonment requirements. The
proposed legislation also would require the reporting and public
disclosure of chemicals used in the fracturing process, which 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. In addition, in light of concerns about seismic
activity being triggered by the injection of produced waters into
underground wells, certain regulators are considering additional
requirements related to seismic safety. Other concerns have been
raised regarding water usage, air emissions (including greenhouse
gas emissions) and waste disposal, and certain jurisdictions have
imposed moratoria on fracking operations while the potential
impacts are studied. The EPA, Congress and other government
representatives continue to investigate the impacts of fracking,
and additional studies and regulatory or legislative initiatives
are possible.
Depending on the legislation that may ultimately be enacted or the
regulations that may be adopted at the federal, and/or state
levels, exploration and production activities that entail hydraulic
fracturing could be subject to additional regulation and permitting
requirements. Individually or collectively, such new legislation or
regulation could lead to operational delays or increased operating
costs and could result in additional burdens that could increase
the costs and delay or curtail the development of conventional and
unconventional oil and natural gas resources including development
of shale formations which are not commercial without the use of
hydraulic fracturing. This could have an adverse effect on our
business, financial condition and results of
operations.
Exploration for petroleum and gas products is inherently
speculative. There can be no assurance that we will ever establish
commercial discoveries.
Exploration for economic reserves of oil and gas is subject to a
number of risk factors. Few properties that are explored are
ultimately developed into producing oil or gas wells. Some of our
properties are in the exploration stage only and are without proven
reserves of oil and gas. We may not establish commercial
discoveries on any of our properties.
There are numerous uncertainties inherent in estimating quantities
of conventional and unconventional oil and gas resources, including
many factors beyond our control and no assurance can be given that
expected levels of resources or recovery of oil and gas will be
realized. In general, estimates of recoverable oil and gas
resources are based upon a number of factors and assumptions made
as of the date on which resource estimates are determined, such as
geological and engineering estimates which have inherent
uncertainties and the assumed effects of regulation by governmental
agencies and estimates of future commodity prices and operating
costs, all of which may vary considerably from actual results. All
such estimates are, to some degree, uncertain, and classifications
of resources are only attempts to define the degree of uncertainty
involved. For these reasons, estimates of the recoverable
unconventional oil, the classification of such resources based on
risk of recovery, prepared by different engineers or by the same
engineers at different times, may vary substantially.
Prices and markets for oil and gas are unpredictable and tend to
fluctuate significantly, which could reduce profitability, growth
and the value of our proposed business.
Our revenues and earnings, if any, will be highly sensitive to the
price of oil and gas. Prices for oil and gas are subject to large
fluctuations in response to relatively minor changes in the supply
of and demand for oil and gas, market uncertainty, and a variety of
additional factors beyond our control. These factors include,
without limitation, weather conditions, the condition of the
Canadian, US. and global economies, the actions of the Organization
of Petroleum Exporting Countries, governmental regulations,
political stability in the Middle East and elsewhere, war, or the
threat of war, in oil producing regions, the foreign supply of oil,
the price of foreign imports, and the availability of alternate
fuel sources. Significant changes in long-term price outlooks for
crude oil and natural gas could have a material adverse effect on
us. For example, market fluctuations of oil prices may render
uneconomic the extraction of oil and gas.
All of these factors are beyond our control and can result in a
high degree of price volatility not only in crude oil and natural
gas prices, but also fluctuating price differentials between heavy
and light grades of crude oil, which can impact prices for our
crude oil. Oil and natural gas prices have fluctuated widely in
recent years, and we expect continued volatility and uncertainty in
crude oil and natural gas prices. A prolonged period of low crude
oil and natural gas prices could affect the value of our crude oil
and gas properties and the level of spending on growth projects,
and could result in curtailment of production on some properties.
Accordingly, low crude oil prices in particular could have an
adverse impact on our financial condition and liquidity and results
of operations.
Existing environmental regulations impose substantial operating
costs which could adversely affect our business.
Environmental regulation affects nearly all aspects of our
operations. These regulatory regimes are laws of general
application that apply to us in the same manner as they apply to
other companies and enterprises in the energy industry.
Conventional and unconventional oil extraction operations present
environmental risks and hazards and are subject to environmental
regulation pursuant to a variety of federal, state and county 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 oil operations. The
legislation also requires that 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.
We expect future changes to environmental legislation, including
anticipated legislation for air pollution and greenhouse gases that
will impose further requirements on companies operating in the
energy industry. Changes in environmental regulation could have an
adverse effect on us from the standpoint of product demand, product
reformulation and quality, methods of production and distribution
and costs, and financial results. For example, requirements for
cleaner-burning fuels could cause additional costs to be incurred,
which may or may not be recoverable in the marketplace. The
complexity and breadth of these issues make it extremely difficult
to predict their future impact on us. Management anticipates
capital expenditures and operating expenses could increase in the
future as a result of the implementation of new and increasingly
stringent environmental regulations.
Abandonment and reclamation costs are unknown and may be
substantial.
Certain environmental regulations govern the abandonment of project
properties and reclamation of lands at the end of their economic
life, the costs of which may be substantial. A breach of such
regulations may result in the issuance of remedial orders, the
suspension of approvals, or the imposition of fines and penalties,
including an order for cessation of operations at the site until
satisfactory remedies are made. It is not possible to estimate with
certainty abandonment and reclamation costs since they will be a
function of regulatory requirements at the time.
Changes in the granting of governmental approvals could raise our
costs and adversely affect our business.
Permits, leases, licenses, and approvals are required from a
variety of regulatory authorities at various stages of exploration
and development. There can be no assurance that the various
government permits, leases, licenses and approvals sought will be
granted in respect of our activities or, if granted, will not be
cancelled or will be renewed upon expiration. There is no assurance
that such permits, leases, licenses, and approvals will not contain
terms and provisions which may adversely affect our exploration and
development activities.
Amendments to current laws and regulations governing our proposed
operations could have a material adverse impact on our proposed
business.
Our business will be subject to substantial regulation under state
and federal laws relating to the exploration for, and the
development, upgrading, marketing, pricing, taxation, and
transportation of unconventional oil and related products and other
matters. Amendments to current laws and regulations governing
operations and activities of conventional and unconventional oil
extraction operations could have a material adverse impact on our
proposed business. In addition, there can be no assurance that
income tax laws, royalty regulations and government incentive
programs related to the unconventional oil industry generally will
not be changed in a manner which may adversely affect us and cause
delays, inability to complete or abandonment of
properties.
Risks Related To The Market For Our Stock
Trading of our stock may be restricted by the SEC's "Penny Stock"
regulations, which may limit a stockholder's ability to buy and
sell our stock.
The U.S. Securities and Exchange Commission has adopted regulations
which generally define "penny stock" to be any equity security that
has a market price (as defined) less than $5.00 per share or an
exercise price of less than $5.00 per share, subject to certain
exceptions. Our securities are covered by the penny stock rules,
which impose additional sales practice requirements on
broker-dealers who sell to persons other than established customers
and "accredited investors." The term "accredited investor" refers
generally to institutions with assets in excess of $5,000,000 or
individuals with a net worth in excess of $1,000,000 or annual
income exceeding $200,000 or $300,000 jointly with their spouse.
The penny stock rules require a broker-dealer, prior to a
transaction in a penny stock not otherwise exempt from the rules,
to deliver a standardized risk disclosure document in a form
prepared by the SEC, which provides information about penny stocks
and the nature and level of risks in the penny stock market. The
broker-dealer also must provide the customer with current bid and
offer quotations for the penny stock, the compensation of the
broker-dealer and its salesperson in the transaction and monthly
account statements showing the market value of each penny stock
held in the customer's account. The bid and offer quotations, and
the broker-dealer and salesperson compensation information, must be
given to the customer orally or in writing prior to effecting the
transaction and must be given to the customer in writing before or
with the customer's confirmation. In addition, the penny stock
rules require that prior to a transaction in a penny stock not
otherwise exempt from these rules, the broker-dealer must make a
special written determination that the penny stock is a suitable
investment for the purchaser and receive the purchaser's written
agreement to the transaction. These disclosure requirements may
have the effect of reducing the level of trading activity in the
secondary market for the stock that is subject to these penny stock
rules. Consequently, these penny stock rules may affect the ability
of broker-dealers to trade our securities. We believe that the
penny stock rules discourage investor interest in and limit the
marketability of, our common stock.
The Financial Industry Regulatory Authority, or FINRA, has adopted
sales practice requirements which may also limit a stockholder's
ability to buy and sell our stock.
In addition to the "penny stock" rules described above, FINRA has
adopted rules that require that in recommending an investment to a
customer, a broker-dealer must have reasonable grounds for
believing that the investment is suitable for that customer. Prior
to recommending speculative low priced securities to their
non-institutional customers, broker-dealers must make reasonable
efforts to obtain information about the customer's financial
status, tax status, investment objectives and other information.
Under interpretations of these rules, FINRA believes that there is
a high probability that speculative low priced securities will not
be suitable for at least some customers FINRA requirements make it
more difficult for broker-dealers to recommend that their customers
buy our common stock, which may limit our ability to buy and sell
our stock and have an adverse effect on the market for our
shares.
Trading in our common shares on the OTC is limited and sporadic
making it difficult for our shareholders to sell their shares or
liquidate their investments.
Our common shares are currently listed for public trading on the
OTC under the stock symbol “NMEX”. The trading price of
our common shares has been subject to wide fluctuations. Trading
prices of our common shares may fluctuate in response to a number
of factors, many of which will be beyond our control. The stock
market has generally experienced extreme price and volume
fluctuations that have often been unrelated or disproportionate to
the operating performance of companies with no current business
operation. There can be no assurance that trading prices and price
earnings ratios previously experienced by our common shares will be
matched or maintained. These broad market and industry factors may
adversely affect the market price of our common shares, regardless
of our operating performance.
In the past, following periods of volatility in the market price of
a company's securities, securities class-action litigation has
often been instituted. Such litigation, if instituted, could result
in substantial costs for us and a diversion of management's
attention and resources.
We are not likely to pay cash dividends in the foreseeable
future.
We intend to retain any future earnings for use in the operation
and expansion of our business. We do not expect to pay any
cash dividends in the foreseeable future but will review this
policy as circumstances dictate. Should we decide in the future to
do so, as a holding company, our ability to pay dividends and meet
other obligations depends upon the receipt of dividends or other
payments from our operating subsidiaries. In addition, our
operating subsidiaries, from time to time, may be subject to
restrictions on their ability to make distributions to us,
including restrictions on the conversion of local currency into
U.S. dollars or other hard currency and other regulatory
restrictions.
Our stock price may be volatile, and you may not be able to resell
your shares at or above your initial purchase price.
There
has been, and continues to be, a limited public market for our
common stock. Although our common stock trades on the NASD Bulletin
Board, an active trading market for our shares has not developed
and may never develop or be sustained. If you purchase shares of
common stock, you may not be able to resell those shares at or
above the initial price you paid. The market price of our common
stock may fluctuate significantly in response to numerous factors,
some of which are beyond our control.
Most of
our common stock is currently restricted. As restrictions on resale
end, the market price of our stock could drop significantly if the
holders of restricted shares sell them or are perceived by the
market as intending to sell them. This could cause the market price
of our common stock to drop significantly, even if our business is
doing well.
Our common stock has a limited public trading market.
While
our common stock currently trades in the Over-the-Counter Bulletin
Board market, our market is limited and sporadic. We cannot assure
that such a market will improve in the future. We cannot assure
that an investor will be able to liquidate the investor’s
investment without considerable delay, if at all. If a more active
market does develop, the price may be highly volatile. The factors
which we have discussed in this document may have a significant
impact on the market price of the common stock. The relatively low
price of our common stock may keep many brokerage firms from
engaging in transactions in our common stock.
The Over-The-Counter Market for our stock has had extreme price and
volume fluctuations.
The
securities of companies such as ours have historically experienced
extreme price and volume fluctuations during certain periods. These
broad market fluctuations and other factors, such as new product
developments and trends in the industry and in the investment
markets generally, as well as economic conditions and annual
variations in our operational results, may have a negative effect
on the market price of our common stock.
Risk Related to Real Estate & Resort Development
We have no history of Development of Real Estate
Property.
Because
we are a company with a limited history, our operations are subject
to numerous risks similar to that of a start-up company. We expect
the real estate development business to be highly competitive
because many developers have access to the same market.
Substantially all of them have greater financial resources and
longer operating histories than we have and can be expected to
compete within the business in which we engage and intend to
engage. We cannot assure that we will have the necessary resources
to be competitive.
We may not be able to conduct successful operation in the
future.
The
results of our operations will depend, among other things, upon our
ability to develop and market our properties. Furthermore, our
proposed operations may not generate income sufficient to meet
operating expenses or will generate income and capital
appreciation, if any, at rates lower than those anticipated or
necessary to sustain ourselves. Our operations may be affected by
many factors, some known by us, some unknown, and some which are
beyond our control. Any of these problems, or a combination
thereof, could have a materially adverse effect on our viability as
an entity and might cause the investment of our shareholders to be
impaired or lost.
To fully develop our business plan, we will need additional
financing.
For the
foreseeable future, we expect to rely principally upon external
financing, although we have raised limited private placement and
debt instrument funds during the past fiscal year and will be
required to do so in the future. We cannot guarantee the success of
this plan. We believe that from time to time, we may have to obtain
additional financing in order to conduct our business in a manner
consistent with our proposed operations. There can be no guaranty
that additional funds will be available when, and if, needed. If we
are unable to obtain financing, or if its terms are too costly, we
may be forced to curtail proposed expansion of operations until
such time as alternative financing may be arranged, which could
have a materially adverse impact on our operations and our
shareholders' investment.
We have limited human resources necessary to expand
operations.
We have
a small staff of skilled developers and supplement our human
resource needs through sub-contracting. We are planning to acquire
additional resources internally thereby reducing the use of
sub-contractors and increasing direct control over our operations.
If we are unable to acquire additional resources internally we will
be forced to use sub-contractors that may or may not be available
to work when and where we need them thereby limiting our ability to
expand operations as we intend.
Our ultimate success will be dependent upon
management.
Our
success is dependent upon the decision making of three of our
directors and executive officers, who are Noel Schaefer, Victor
Miranda and Ivan Webb. These individuals intend to commit as much
time as necessary to our business. The loss of any or all of these
individuals could have a materially adverse impact on our
operations. We currently do not have not key man life insurance on
the lives of any of these officers and directors.
We are subject to real estate development risks.
Our
development projects are subject to significant risks relating to
our ability to complete our projects on time and on budget. Factors
that may result in a development project exceeding budget or being
prevented from completion include:
an inability to obtain zoning, occupancy and other required
governmental permits and authorizations;
an increase in commodity costs;
construction delays or cost overruns, either of which may increase
project development costs.
If any
of these occur, we may not achieve our projected returns on
properties under development and we could lose some or all of our
investments in those properties.
We are vulnerable to concentration risks because our operations are
currently almost exclusive to the Yucatan Peninsula, Mexico area
market.
Our
real estate activities are currently entirely focused in the
Bacalar area on the Yucatan Peninsula of Mexico. Because of our
geographic concentration and limited number of projects, our
operations are more vulnerable to local economic downturns and
adverse project-specific risks than those of larger, more
diversified companies. The performance tourism of the Mexico
economy specifically as it relates to the Yucatan Peninsula could
greatly affect our sales and, consequently the underlying values of
our properties.
Our operations are subject to an intensive regulatory approval
process.
Before we can develop a property, we must obtain a variety of
approvals from local and state governments with respect to such
matters as zoning, density, parking, sub-division, site planning
and environmental issues. Certain of these approvals are
discretionary by nature. Because certain government agencies and
special interest groups are involved there is a high degree of
uncertainty in obtaining these approvals.
Currency exchange rate fluctuations and higher inflation may
adversely impact the Company’s future operating results and
financial condition.
The exchange rate between the Mexican Peso and the U.S. dollar has
changed substantially in the last two decades and could fluctuate
substantially in the future. The Company’s market valuation
could be materially adversely affected by any devaluation of the
Mexican Peso if U.S. investors analyze the Company’s value
and performance based on the U.S. dollar equivalent of the
Company’s financial condition and operating results. The
Company expects that a substantial portion of its expenses,
including personnel costs, may be denominated in Mexican Pesos. As
such, any appreciation of the Mexican Peso against the U.S. dollar
would reduce the cost advantage derived from the Company’s
Mexican Peso-denominated expenses and would likely adversely affect
the Company’s financial condition and results of operations.
In addition, an increase in inflation would adversely affect world
economies generally, which would adversely affect the
Company’s business.
Item 1B. UNRESOLVED STAFF
COMMENTS
We are
a smaller reporting company as defined by Rule 12b-2 of the
Securities Exchange Act of 1934 and are not required to provide the
information under this item.
Our principal executive offices are located at 10 West Broadway,
Suite 700, Salt Lake City 84101.
As of
July 31, 2019, we owned or had a lease on the following
properties:
Coleman County, Texas – J. E. Richey Lease – Three Well
Project
History & Background:
On
October 14, 2014, the Company entered into an agreement to acquire
the J. E. Richey lease located west of the Community of Novice in
Coleman County, Texas. This lease area has six known productive
formations. The existing three wells on the lease are fully
equipped. There is spacing available for new drilling of two or
more wells. In September 2014 the Company began selling working
interest to raise working capital to rework two wells and
re-complete one well on the J. E. Richey 206.5 acre lease. The
Company sold 76% of the working interest to fund the
rework/re-completion operations.
In May
2015 the Company started conducting operations on reworking the J.
E. Richey #1 by conducting a xylene and acid wash to clean the
perforations and well bore. The well responded by increasing the
casing pressure from 25 pounds to 210 pounds with a strong oil
flow. The same procedure was conducted on the J. E. Richey #3 well
with the same results. Within a month the #1 well began to make
less total fluid with very little oil and the #3 well had plenty of
fluid but only a trace of oil. Both the #1 and #3 wells on the J.
E. Richey lease were shut-in awaiting further
evaluation.
In June
the re-completion process began on the Concho Richey #1 also
located on the J. E. Richey lease. The re-completion was to open
the Gray formation in this well as it had never been tested in this
well. Other formations had been tried with nominal success. The
first stage of the re-completion process was to squeeze off the
Tannehill formation at 1700’ before attempting to perforate
the Gray. The squeeze was a success and the Gray formation was
perforated yielding 3 barrels of oil on a swab naturally without
any stimulation. This was followed by a 300 gallon 7.5% acid job
that more than doubled the oil production to 6 barrels with no
water. A 50 sack frac was performed yielding 65 barrels of oil and
100 MCF of natural gas per day. The rework/re-completion was
completed on all three wells on July 28, 2015 and production of oil
and gas was established.
In June
2016 a hole came in the casing on the Concho Richey #1 well.
Production ceased until October 2016 when the hole in the casing
was repaired. Production resumed at the rate of 8 barrels of oil
and 40 MCF of natural gas per day. As of the date of this report
the Concho Richey #1 well is averaging 4.5 barrels of oil and 34
MCF of natural gas per day with little to no formation
water.
Two
attempts were made to rework the J. E. Richey #1 well subsequent to
the effort made in May 2015. During March and April of 2017 an
effort to re-perforate the Gray formation with a TriStem
Perforating Gun, a specialized tool, that perforate three holes in
a wedge or pie shape in an effort to increase exposure to the well
bore the flow into the well bore. After several attempts the
TriStem tool would not go below 1100 feet deep. The area to be
perforate is 3900 feet in the Gray. A temperature survey was ran
and determined the well had a hole in the casing. This procedure
was followed by conducting a multiple interval pressure pumping
test from the top of the perforations in the Gray to the surface.
The casing held pressure until we came up the hole to 970 feet and
continued not to hold pressure in each pressure test to the
surface. No further work was conducted until August 2017 providing
time to meet with engineers to determine what procedure or method
could be performed to salvage the well. After numerous meetings and
discussions with local operators, petroleum engineers and service
companies it was determined that the chances of success to save the
well was very poor. A decision was made to plug the well. On
January 3, 2018 the J. E. Richey #1 well was plugged.
Plans
are to rework the J. E. Richey #3 well by placing a bridge plug
over the Gray and produce the Morris for 60 – 90 days to see
the daily average of total production of gas, oil and formation
water. Depending on the amount of formation water a sand frac will
be designed to stimulate the Morris in an effort to increase oil
and gas production. The J. E. Richey #3 well was originally
perforated in the Morris with an initial rate of 2,075 MCF per day
and has produced more than 250 million cubic feet of natural gas. A
previous operator attempted to produce the Gray by perforating it
and letting it produce naturally. The xylene/acid wash conducted on
this well in May 2015 is likely to have opened up the Gray and
allowed it to produce most of the formation water as the Morris was
not noted for making much formation water when it was produced
independently. No date has been set for to conduct this rework
procedure on the J. E. Richey #3 well.
The
Company acquired a 206.5 acre lease (J. E. Richey) located in the
northern part of Coleman County, Texas with four existing wells in
September 2014. Three of the four wells were fully equipped with
down hole pumps, rods, tubing, pump jacks, well head and surface
equipment including tank battery, meter run and gas gathering
pipelines.
The
Concho Richey #1 became the primary producer on this lease
following the re-completion in the Gray Formation
(“Gray”). The Concho Richey #1 is located due west
660’ from the Olympia Hale #1 well that has produced more
than 71,000 BBLS and over 190 MMCFG from the Gray since 1986
(approximately 30 years). In July 2015 the Company re-completed
this well in the Gray Sand. The Gray Sand formation (3,860’)
is a clean sand with section having 34% porosity with good
permeability. The Concho Richey #1 well came in with an initial
production rate of 65 barrels of oil and 100 MCF of gas per day. It
was averaging about 14 barrels of oil and 75 MCF of gas per day
with about 10 barrels of saltwater before a hole came in the casing
in June 2016. During the fiscal year we were able to successfully
conduct a cement squeeze to seal off the casing leak. The well was
brought back into production and is averaging 7 barrels of oil, 40
MCF of gas and ½ barrel of saltwater per day.
During
March 2017 the Company attempted to bring the J.E. Richey #1 back
into production. A hole was discovered in the casing around 600
feet. Additional work was performed on the well in August 2018.
Pressure testing proved the casing from 900 feet to the surface was
not repairable and was plugged on January 3, 2018.
Additional
work is planned to be conducted on the J.E. Richey # 3 well with a
view to produce the Morris for 60 – 90 days to determine if
an additional stimulation is warranted to improve its production.
No dates have been set at the time of this report to conduct this
work program on the J.E. Richey #3 well.
Location and Access
The location of the 206.5 acre J.E Richey Lease is approximately
3.5 miles west of the community of Novice, Texas located in the
central part of Coleman County which is south approximately 45
miles of the city of Abilene, Texas. Access to the lease is
excellent with good access to county roads and lease roads. The
terrain is rolling hills with no abnormal location or access
problems.
Ownership Interest
The
Company owns 24% of the working interest before payout and 36.5%
working interest after payout in these two wells covering 40 acres
and 87.5% working interest in rest of lease covering 166.5
acres.
History of Operations and Geology
The
lease is located in a multiple pay area originally discovered by
ARCO in the early 1980’s. This lease area has six known
productive formations.
The
following is a summary of each of the three wells originally
drilled by ARCO and the fourth well drilled by J.V. Rhyne, a local
operator in the Abilene, Texas area:
J.E.
Richey #1 Well – was completed in the Gray Sand in 1981 and
came in with an initial production rate of 167 barrels and 118 MCF
per day with no saltwater from the Gray Sand formation. The well is
only open in the Gray and has the Upper Capps formation up the hole
for future testing. As stated above the casing was not repairable
and this well was plugged due to casing problems in the well on
January 3, 2018.
J.E. Richey #2 Well – initially was completed in the Lower
Ellenburger in 1982 coming in at 19 barrels per day. Following
depletion of the Lower Ellenburger the well was re-completed in the
Upper Ellenburger with an initial production rate of 2,535 MCF per
day. Subsequently the well was re-completed in the Gray Sand, which
came in at 45 barrels per day on a light acid job. The well only
produced for a limited amount of time from the Gray Sand when a
hole came in the casing above the cement at 1100 feet caused by a
corrosive formation known as the Coleman Junction and the well was
shut in. This well
was plugged due to casing problems in the well on December 28,
2017.
J.E. Richey #3 Well – was completed in the Morris in 1982,
which had an initial production rate of 2,075 MCF per day. This
well has been shut in since 2010. The well is only open in the
Morris with potential to open up the Gray Sand. The Upper Capps
formation is also present up the hole to test. This well is currently shut in awaiting additional
work to be performed.
Concho Richey #1 Well – was initially completed in the
Ellenburger coming in at 1,200 MCF per day in 2005. The Ellenburger
came in strong but quickly began to produce saltwater within a few
months of production. In 2006 a re-completion attempt was made up
the hole in the Tannehill formation (1700 Feet), where an oil show
was recorded in the mud logs, in hopes of making a field discovery.
Due to a poor cement bond the re-completion was not successful in
the Tannehill. The well was shut in awaiting further reworking
and/or re-completion in 2006. During the fiscal year ended July 31, 2015 the
Company re-completed this well in the Gray formation and made a
commercial producing well.
Coleman County, Texas – J. E. Richey #2A -Proposed New
Well:
The
Company has sold working interest in a 20 acre tract on the J.E.
Richey Lease to drill a new well near the ARCO Richey #2 well. This
well initially was completed in the Lower Ellenburger in 1982
coming in at 19 barrels per day. Following depletion of the Lower
Ellenburger the well was re-completed in the Upper Ellenburger with
an initial production rate of 2,535 MCF per day. Subsequently the
well was re-completed in the Gray Sand, which came in at 45 barrels
per day on a light acid job and no sand frac was conducted. The
well only produced for a limited amount of time from the Gray Sand
when a hole came in the casing above the cement at 1100 feet caused
by a corrosive formation known as the Coleman Junction and the well
was shut in. This well was plugged due to casing problems in the
well on December 28, 2017.
A
drilling location has been staked west of the J. E. Richey #2 well.
Drilling funds have been received toward the drilling of the new
proposed location for the J. E. Richey #2A well. At the time of
this report no definitive schedule for drilling has been set.
Additional drilling funds will be required to be able to drill this
well to a projected total depth of 4,500’. Subsequent to July
31, 2019 the Company has been in negotiations with industry
partners to fund the balance of the drilling funds required to
drill this well in consideration of a prospect fee and carried
working interest. All potential formations will be evaluated with
particular attention being focused on the following
formations:
|
|
Ellenburger
|
4,200’
|
Jennings
|
3,600’
|
|
|
|
Gray
|
3,850’
|
Upper
Capps
|
3,450’
|
|
|
|
Gardner
|
3,700’
|
Morris
|
3,400’
|
|
Jones County, Texas – Palo Pinto Reef Project:
Location & Access:
The 160 acre lease known as the Olson is located approximately 6
miles southeast of the city of Stamford, Texas that basically sits
on the county line of Jones and Haskell counties, on the north side
of Jones County, Texas. Of particular importance is the location of
the Olson Lease lies approximately 1.5 miles southeast of the
Strand Oil Field, a Palo Pinto Reef Oil Field. Access to the lease
is excellent with good access to county roads and lease roads. The
terrain is rolling hills with no abnormal location or access
problems.
The Olson Lease is in an area geographically known as the Eastern
Shelf of the Permian Basin. It is influenced by the Bend Arch to
the East and the South as it approaches the Llano Uplift. This area
is best known for the several producing formations that are
stratigraphically and structurally used as trapping oil and
gas.
The principal target formation for the Olson Lease is the Palo
Pinto Reef. The Palo Pinto Reef is a known productive formation
with a high yield of cumulative oil production. The Strand Oil
Field is a Palo Pinto Reef Oil Field, discovered in 1940, that
consists of only 8 wells that has produced a total of 1,700,000
barrels of oil, an average of 212,500 barrels of oil per oil
well.
Ownership Interest
During the fiscal year the Company acquired 100% of the working
interest in the oil and gas lease known as the Olson covering
approximately 160 acres for $30,000 including legal, landman, lease
bonus, geological mapping etc. The Company has agreed to
convey the Olson lease to Kathis, its wholly owned subsidiary, for
its drilling program for $60,000. The term of the Olson lease
expired on April 27, 2019 resulting in a loss of investment in this
oil lease.
Shackelford County, Texas – Guy Ranch Project:
History & Background:
During
the fiscal year ended July 31, 2016 the Company acquired a 100%
working interest in a 692-acre Guy Ranch Lease divided into two
tracts. Tract 1 covers 480 acres and Tract 2 covers 212 acres. The
Ranch has 32 wind turbines on it representing it is at a
structurally higher elevation. The principal targets for this
drilling prospect is the Patio (aka Palo Pinto Sand) and Morris
Sands the area is also know to be productive from three other
formations on the Guy Ranch acreage.
The
first project on the Guy Ranch was to re-complete a cased well in
the Morris formation that was reportedly untested. The structure of
the deal was for a third party to pay 100% of the costs re-complete
the cased well in the Morris formation allocating 20 acres out of
the 450 acres in order to earn a 75% working interest in the cased
well. All records filed with the Texas Railroad Commission
supported that no attempt to produce from the Morris had been
performed. However, it was subsequently found out that in fact an
attempt was made to re-complete in Morris formation and such
attempt was unsuccessful due to an over stimulation of the Morris
with a large frac at high pumping rate. The well produced mostly
water. The 20 acres around the well was not assumed by the Company
or its third-party investors. The unused funds provided by the
third party will be allocated to a new well on the Guy Ranch Lease
with the third party being responsible for providing the balance of
the funds to drill and complete a new well in order to earn 75% of
the working interest.
During
the fiscal year ended July 31, 2018 the Company agreed to convey
approximately 650 acres out of the Guy Ranch lease to Kathis Energy
LLC, its wholly owned subsidiary, for its drilling program for the
consideration of $66,500.
In
March 2018 Kathis Energy staked two drilling locations on the Guy
Ranch and prepared one drilling location. This drilling location is
a direct offset to a Patio Sand well that came in at 140 barrels
per day. The Patio Sand is one of the main producing formations in
the area generally averages between 25,000 and 75,000 barrels oil
per well. The Morris Sand a notable gas producer is known to
produce up to 1.4 BCF gas from one well and the Gardner is noted in
this area to produce between 50,000 and 110,000 barrels per well.
The Net Revenue Interest for the Guy Ranch lease is 75%. This lease
expired on December 16, 2018 and has not been extended, resulting
in a loss of investment in this oil lease.
Runnels County, Texas – Riverside Prospects – Multiple
Pay Project
History & Background:
On
October 20, 2017 the Company entered into an exclusive option
agreement with Murphree Oil Company to acquire drilling prospects
on four leases in Runnels County near the City of Ballinger, known
as the Riverside Prospects. During the quarter ended April 30,
2018, the Company, through its wholly owned subsidiary, Kathis
Energy LLC, (“Kathis”) paid the lease bonuses for
extending the oil and gas lease period on 548.76 acres covering the
Riverside Prospects. This acreage consists of 4 leases in a well
established area where oil and gas production was discovered during
1978 – 1983.
Location & Access:
The
location of the leases covering the Riverside Prospects is
approximately 2 miles west of the City of Ballinger, Texas in
Runnels County.
Ownership Interest:
Kathis
had an option to acquire these leases in stages with the first
stage to have proof of drilling funds to drill one well by December
31, 2018. The Net Revenue Interest on all of these leases is 75%
and the expiration of these leases varies from April thru June
2019. The lease terms of these four leases was not extended as of
July 31, 2019 resulting in a loss of investment in these oil
leases.
89 Guy #4 Well – Cased Hole:
History & Background:
The 89
Guy Well #4 is located on the Guy Ranch property in Shackelford
County. The well is an abandoned cased well that was drilled in
October 2010 and completed in the Patio Sand at the interval of
3,144’ - 3,154’. This interval produced 2 barrels of
oil and 20 thousand cubic feet of natural gas from a 100 sac gel
frac. The interval perforated (3,144 – 3,154’) is above
the best productive part of the formation. The cased well was
purchased from the mineral owner through an independent geologist
followed by an application to the Texas Railroad Commission to
assume liability of the case well.
Ownership Interest:
Kathis
Energy owns 100% of the working interest with a 75% net revenue
interest in the 20 acre lease with the cased well. On April 16,
2018, Kathis Energy acquired the 89 Guy Well #4 located on a
20-acre tract on the Guy Ranch property in Shackelford County,
Texas. Kathis paid $22,500 for the cased well. There was a
completion attempt during the fiscal year ended July 31, 2019 to
re-complete in the 3,144’-3,154’ interval recovered
nominal oil production. No further work has been conducted and is
being evaluated to place into production or plug the well and
salvage equipment.
Location & Access:
The
20-acre tract on the Guy Ranch Lease is located approximately 15
miles northeast of the city of Abilene, Texas. Access to the 89 Guy
Well #4 is excellent with paved county roads and gravel lease roads
to the well. The lease has access to gas lines and electric
power.
History of Operations & Geology:
The Guy
Ranch lease is in an area geographically known as the Eastern Shelf
of the Permian Basin. It is influenced by the Bend Arch to the East
and the South as it approaches the Llano Uplift. This area is best
known for the several producing formations that are
stratigraphically and structurally used as trapping oil and
gas.
The Guy
Ranch comprises a total of 5,120 acres of which the Company’s
20 acre tract is included. The Guy Ranch has had many wells drilled
on it throughout the years. The Ranch has 32 wind turbines on it
representing it is at a structurally higher elevation. Because of
all the earlier drilled wells it is easy to see that most of the
production is located on the many surface structural noses that
occur on the ranch.
Patio Sand: The Patio Sand (also known as the Palo Pinto
Sand) is at approximately 3100 feet. The Patio Sand is the main
producer to the west (next section) and generally averages between
25,000 and 75,000 barrels oil per well. The A T & H Oil Company
#2 Davis well (north offset) was perforated in the Patio Sand
(3158-61') and flowed 140 BOPD. This well produced 27,371 barrels
oil and 60 MMCF gas before the Railroad Commission of Texas had it
plugged for having to many violations. This well was still
producing 12 barrels oil per day when plugged.
McClure 2B Gas Well – Producing:
History & Background:
On
February 6, 2018 the Company acquired the McClure # 2B producing
gas well on a 40 -acre oil & gas lease located in Palo Pinto
County near the Community of Graford, Texas. The McClure 2B well
was drilled in 2006 to a total depth of 4,739’ and was
re-completed in the Strawn formation in January 2011. The McClure
2B gas well is among a large number of gas wells that are producing
in the area from the Strawn formation.
Location & Access:
The
location of the McClure 2B gas well is 1 mile southwest of the
Community of Graford, Texas in Palo Pinto County on a 40 acre
tract. The lease is off a main county road and the lease road can
have washouts depending on the amount of rain as the McClure 2B gas
well is on top of a hill. There are two natural gas lines 1) high
pressure and the 2) is low pressure.
Ownership Interest
The
Company paid $25,000 for this gas well. The net revenue interest
for the McClure lease is 75% and the lease is held by existing
production. On December 31, 2018 the Company entered into an
agreement with a third party whereby the Company received $85,900
to rework the McClure 2B gas well. In consideration for the $85,900
the Company issued 859,000 shares of its common stock and agreed to
convey 100% of the revenues from the sale of natural gas until the
investment capital was recovered then revert to a 60/40 split in
favor of the third party. On July 31, 2019 the Company entered into
an agreement with the operator of the lease to assume the
obligations of the agreement entered into with a third party to
perform certain work in exchange for shares of the Company’s
common stock.
Carter & Foster Wells – Producing:
History and Background:
The
wells on the Carter and Foster leases were drilled in1992-93. Most
of the wells were treated with 5,000 gallons of 21% acid and
yielded initial rates of production of 40 barrels of oil per day
then gradually declined to 3 barrels per day by the end of the
first year. The wells now are 25 plus years old and are producing
90% or better oil cut in the fluid being produced. the production
is very nominal at the present time however no secondary acid
stimulation has been conducted since they were originally brought
into production in the early 1990’s. All four wells on the
Carter and Foster leases are fully equipped and have their own
production facilities and have electricity to each of the wells. On
December 30, 2018 the Company entered into an agreement with a
third party whereby the Company received $60,000 to rework the
Carter and Foster wells. In consideration for the $60,000 the
Company issued 600,000 shares of its common stock and agreed to
convey 100% of the revenues from the sale of crude oil until the
investment capital was recovered, then revert to a 60/40 split in
favor of the third party. On July 31, 2019 we entered into an
agreement with the operator of the lease to assume the obligations
of the agreement entered into with a third party.
Reeves Lease – Acreage – Palo Pinto Reef
Prospect:
In
August 2018 the Company paid for the geological prospecting fees
for a Palo Pinto Reef prospect in Jones County. The Reeves lease
covers 160 acres and is located near Noodle, Texas in Jones County.
The projected depth of the Palo Pinto Reef is 4,300’.
Excellent well control by 6 Strawn wells provides evidence of a
Palo Pinto Reef showing a structure 48’ high to other wells.
The nearest Palo Pinto Reef well to the Reeves Lease made more than
150,000 barrels from one well.
The
lease bonus money of $28,000 was provided by a third party for a
two-year lease and the Company paid the geological prospect fee of
$10,000. It was verbally understood between the Company and third
party to promote this drilling prospect seeking to retain a carried
interest plus recoup the lease and prospect monies. The oil and gas
lease was not delivered and the
Company is seeking to recover its $10,000 geological fee as the
lease was never obtained. The $10,000 has been disclosed on the
balance sheet and is expected to be collected.
Index of Oil & Gas Abbreviations
INDEX
|
ABBREVIATION
|
|
DEFINITION
|
|
BBL
|
|
Barrel of oil, 42 US standard gallons
|
|
MCF
|
|
Thousand Cubic Feet of natural Gas
|
|
MMCF
|
|
Million Cubic Feet of natural gas
|
|
RRC
|
|
Railroad Commission of Texas, regulatory authority for governing
the operations of oil and gas activities
|
Winnemucca Mountain Property:
As
previously announced, on September 14, 2012, we entered into an
option agreement (as last amended on February 11, 2016) with AHL
Holdings Ltd., and Golden Sands Exploration Inc., wherein we
acquired an option to purchase an 80% interest in and to certain
mining claims, which claims form the Winnemucca Mountain Property
in Humboldt County, Nevada (“Property”). This
Winnemucca Mountain property currently is comprised of 138
unpatented mining claims covering approximately 2,700
acres.
On July
23, 2018, the Company entered into a New Option Agreement with AHL
Holding Ltd & Golden Sands Exploration Inc.
(“Optionors”). This agreement provided for the payment
of $25,000 and the issuance of 3,000,000 shares of the
Company’s common stock and work commitments. The Company
issued the shares and made the initial payment of $25,000 per the
terms of the July 31, 2018 agreement. The second payment of $25,000
per the terms of the agreement was not paid when it became due on
August 31, 2018 causing the Company to default on the terms of the
July 23, 2018 agreement.
On
March 25, 2019 the Company entered into a New Option Agreement with
the Optionors. As stated in the New Option Agreement the Company
has agreed to certain terms and conditions to have the right to
earn an 80% interest in the Property, these terms include cash
payments, issuance of common shares of the Company and work
commitments.
Location and Access
The Winnemucca Mountain Property is located in north-western
Nevada, approximately 4 miles northwest of the municipality of
Winnemucca. The property is within the Winnemucca Mountain Mining
District of Humboldt County. The claims are situated on the west
flank of Winnemucca Mountain. A map showing the location of and
access to the Winnemucca Mountain Property is attached
below.
The Winnemucca Mountain Property is accessible from State Route 49,
a graded gravel road from Winnemucca to Jungo. The claims that
comprise the Winnemucca Mountain Property lie in an irregular,
northerly trending block along the western flanks of Winnemucca
Mountain. The mountain slopes are generally moderate along the west
side of the claims, steepening on the east and in drainages.
Pediment and alluvium cover is extensive, particularly in the
western, or lower, part of the property where a classic bajada is
developed. Within the claims, elevations range from approximately
4,700 feet in the southwest corner to nearly 6,600 feet in the
east. The area is devoid of trees, and vegetation consists of
sagebrush and sparse grass. The climate in southern Humboldt County
is arid with annual rainfall averaging 8 inches and snowfall of 16
inches. The area is characterized by hot summers and short, cold
winters.
History of Operations
The discovery of the Comstock Lode in western Nevada in 1859
spurred mineral exploration throughout Nevada. Gold and silver were
first discovered in the Winnemucca Mining District in 1863 and,
during the 1860’s, several smelters were constructed along
the Humboldt River. The early productive lodes consisted of quartz
veins containing small amounts of variably oxidized copper and
lead.
The first significant gold discovery in Humboldt County was the
Getchell gold deposit in 1933. The Getchell Mine began production
in 1938 and has operated intermittently since. The current owners
are Barrick and Newmont. The mine was reopened in 2002 with a
resource of 7 million ounces of gold. Since discovery of the
Getchell Deposit, Humboldt County has been the site of numerous
other significant gold discoveries. Major gold deposits in the area
include the Lone Tree, Marigold, Preble, Pinson, Turquoise Ridge,
and Twin Creeks, all located east and northeast of Winnemucca, and
the Hycroft (Crowfoot-Lewis), Sandman, Rosebud, and Sleeper
deposits to the northwest.
On Winnemucca Mountain itself, the Adamson mine, located in the
northeast portion of section 11, reported gold production from
“rich ore” in 1911-1912 totaling $13,711 (approximately
20 kg of gold equivalent; Willden, 1964). The Pride of the Mountain
mine, which reported gold and silver production during 1915, is
situated just east of the Golden West claims in the northwestern
portion of section 23. Both mines exploited gold-bearing quartz
veins cutting metasedimentary rocks. Topographic maps indicate six
‘prospects’ and one old ‘mine’ within the
boundaries of the Golden West 8 and 10 claims. These may be mercury
workings referred to by Schnell & Hodges.
The upper slopes of Winnemucca Mountain contain dozens of prospects
and several old mines. One of these, the Shively Mine on the north
side of Winnemucca Mountain, exploited a west-northwest striking,
moderate to steeply dipping quartz-calcite vein. In 1982, St. Joe
conducted a drilling program directed at this structure. Results of
their drilling included 90 feet of 0.34 g/t Au in DH1 and 30 feet
of 0.69 g/t Au in DH2.
The earliest available record of exploration within the present
Winnemucca Mountain property claim area is an undated map by St.
Joe American Corporation that describes rock sampling over much of
the claim block and soil sampling across the Golden West 6 to 13
claim area. This work was most likely done in conjunction with work
in the Shively Mine area during 1982. The same map indicates that
Cordilleran Exploration (Cordex) drilled seven drill holes, also on
the Golden West 6 to 13 claims. However, an undated compilation map
by Santa Fe places these Cordex drill holes (holes WV1 – 7,
WV11 and WV16 – 18) over 4,900 feet to the east of the Golden
West claims. The true location of these holes is therefore
uncertain and should not be relied upon. Metzler reports that the
Cordex holes were drilled in 1972; in addition, 700 feet of
trenching was completed and over 3,300 feet of existing underground
workings were mapped and sampled and the construction of drill
access roads were completed. A map dated October 1982 indicates
that induced polarization, magnetic, and VLF electromagnetic
surveys were performed on the property. Details of work done by St.
Joe and Cordex are not available.
The next record of exploration is by Arctic Precious Metals Inc. in
1985. Work over the next few years included rock sampling by Arctic
and Tenneco Minerals in 1986, with geological mapping by Arctic in
1986 in the northern claim area. During 1987, Arctic drilled 1,916
feet in 5 reverse circulation drill holes. Results were encouraging
with hole WM 5 intersecting a 5 feet interval of 1,050 ppb gold.
The next year, Arctic conducted detailed rock sampling and VLF-EM
and magnetic surveys over a breccia pipe target area, followed by 7
diamond drill holes for a total of 2,100 feet. Drill hole WM 7
intersected up to 1,950 ppb gold over 5 feet and WM 13 cut two
large intervals (145 feet and 181 feet) of elevated gold in a
breccia (164 ppb and 147 ppb respectively; SFPM data).
In late 1988, Santa Fe Pacific Mining, Inc. (now Newmont) entered
into a joint venture with Arctic after recognizing the significance
of anomalous gold in the breccia pipe identified by the Arctic
drilling. Santa Fe became operator and, between 1988 and 1990,
conducted geological mapping, rock sampling, trenching, CSAMT and
induced polarization geophysical surveys, collected 286 auger hole
bedrock samples, and completed a total of 52,470.8 feet in 73
reverse circulation drill holes. Three of these drill holes were
re-entered with a diamond drill. The total diamond drill footage is
uncertain but is in excess of 477 feet. Not all of Santa Fe’s
drilling was within the boundaries of the current claim block.
Santa Fe’s work outlined the Swordfish occurrence that
extends approximately 2,200 feet along the western flank of
Winnemucca Mountain within the current claim block.
In 1994, Anvil Resources of Vancouver, B.C., acquired the property
and became the project operator. Anvil did a great deal of internal
compilation work, prepared a topographic base map and collected
surface samples to confirm previous gold tenors. They performed
test assaying to determine optimum analytical procedures for coarse
gold samples and milling tests on bulk samples to maximize gold
liberation. An induced polarization (IP) survey conducted in 1996
confirmed that resistivity highs correlated well with known
mineralized areas and delineated two new target zones.
In 2006-2007 Meridian Minerals Corp. acquired an option on the
property from Evolving Gold Corp. Meridian conducted two separate
drilling programs on the property. Twelve angled holes were
drilled, totaling 7473 feet. In 2007 four additional angled holes
were subsequently drilled totaling 2,659 feet. This drilling,
targeted northwest and northeast striking veins to the northeast of
the Swordfish Zone, and a further 3 holes targeted a vein system in
the very north of the Property This drilling intersected lower
grade mineralization than the moderate to high grade intercepts in
the Swordfish Zone.
Santa Fe Pacific Gold Corp. utilized a computer program called
Geostat to calculate a cross-sectional resource estimate for the
Swordfish zone area. Santa Fe estimated that the Swordfish zone
contained 4.15 million metric tons grading 0.82 g/t gold (4.58
million short tons grading 0.028 opt gold) at a 0.29 g/t cutoff
(0.01 opt cutoff). All resource calculations were based on
arithmetic averages. This estimated resource occurs in an area
2,200 feet long and 700 feet deep.
In March 2013 the Company contracted consultants to study the
mineralization and known resources on the Winnemucca Mountain
Property. Company consultants completed mapping and geochemical
sampling of the 3000 feet long Swordfish zone on the Property.
Using this surface work along with historical drill results, 3D
modeling of the gold/silver mineralization was completed. Based on
the results of the initial work, Company consultants have
recommended further exploration on the property including
geophysics, core and reverse circulation (RC)
drilling.
Geology
Regional Geology – Nevada
lies within the Basin and Range geological province. The geologic
structure of this province is the result of repeated interactions
between the North American Plate and oceanic plates to the west
which are expressed as folds, thrust faults, strike slip faults,
normal faults, igneous intrusions, volcanism, metamorphism and
sedimentary basins. Every mountain range in the Basin and Range
province is bounded on at least one side by a normal fault, many of
which are still active. The area’s highly complex and active
tectonic history has created a diversity of depositional
environments, deep-seated structures, hydrothermal centers and
numerous mineral deposits.
Humboldt County is underlain by rocks ranging in age from probable
early Cambrian to late Miocene or early Pliocene. In general, the
oldest rocks are in the southeastern portion of the county with
younger rocks to the north and west, however, late Tertiary
volcanic and sedimentary rocks are randomly distributed throughout
the county. Five orogenic episodes have been recognized but
structural and lithologic elements are not continuous between
mountain ranges. The most important of the orogenic episodes in
Nevada is the Antler Orogeny, the late Devonian collision of an arc
terrane complex with the western margin of North America. The arc
material (allochthon) was thrust over cratonic carbonates along the
Roberts Mountain thrust fault. Mountain building accompanied the
Antler Orogeny, resulting in a high mountain range to the west. In
addition to the folding and low-angle faulting associated with
orogenic compression and mountain building, high-angle reverse and
strike-slip faulting were widespread, forming important wrench
fault systems. These high-angle faults were crucial in localizing
the fluid flow responsible for gold deposition.
Mineral deposits have been found in all rock units exposed in the
county. At least three periods of epigenetic ore mineral deposition
have been recognized. The oldest are the iron deposits in the
Jackson Mountains. Contact metamorphic tungsten and vein deposits
belong to the second period, developed in conjunction with the
emplacement of Cretaceous and Tertiary intrusive rocks. The third,
late Tertiary, depositional episode includes mercury, uranium and
gold-silver deposits, including the Getchell and Sleeper gold
deposits. Most Tertiary mineral deposits in northern Nevada are
distributed linearly as a result of deep crustal controls including
the Carlin and Battle Mountain trends.
Current gold producers in Humboldt County include the Getchell,
Hycroft, Marigold, Lone Tree, and Twin Creeks mines.
Property Geology- The general
geology of Winnemucca Mountain is shown on two publicly available
maps. The oldest unit exposed on Winnemucca Mountain is the Upper
Triassic Winnemucca Formation that underlies the upper elevations.
These rocks are gray to brown calcareous shale; buff and gray,
thin-bedded to massive carbonate rocks, buff to light brownish-gray
calcareous sandstone, gray and brown shale and slate and some light
brown feldspathic quartzite.
A younger, unnamed quartzite-mudstone formation is faulted against
the Winnemucca Formation on the northwest side of Winnemucca
Mountain by a normal fault of uncertain displacement. This unit
consists of light brown or buff, thin to thick bedded,
fine-grained, feldspathic quartzite which usually weathers dark
brown; buff to light brown, medium bedded mudstone; and small
amounts of light brown phyllitic shale.
The sedimentary rocks are cut by several small intrusive bodies.
The largest is a Jurassic-Cretaceous stock which intrudes
Winnemucca Formation rocks on the southern side of Winnemucca
Mountain, measuring approximately 6,600 by 9,075 feet. The
intrusive contains no quartz but, in general, contains more
plagioclase than mafic minerals so is compositionally a diorite. A
small body of Tertiary volcanic rocks has been identified on the
west side of Winnemucca Mountain.
Tertiary basalt and andesite unconformably overlie the older units
on the north side of the mountain. These also include more silicic
volcanic and sedimentary rocks.
An east-northeast trending breccia body measuring 1,320 by 5,000
feet in Triassic sedimentary rocks was mapped on the west side of
Winnemucca Mountain. The diatreme, containing gold mineralization
now known as the Swordfish zone, is described by Metzler (1994) as
an ellipsoid plug of brecciated, silicic dacite and rhyolite with
sharp contacts. The breccia contains angular clasts of the older
siltstone and granodiorite and is considered to be a Tertiary
diatreme.
Three directions of major faulting are apparent, each of which
appear confined to a particular area of Winnemucca Mountain. In the
northern portion of the mountain are three parallel northeast
trending faults, situated approximately 2,800 feet apart. Movement
on these faults is primarily dip-slip although some minor
strike-slip movement was also noted. On the southern flank of the
mountain are two parallel north-northeast trending faults 5,000
feet apart. Northerly and northeasterly oriented faults dominate
the central part of Winnemucca Mountain. Santa Fe geologists
believed that the topography of Winnemucca Mountain was in part
controlled by extensional range-front faults and the dominant
structural trend, especially with respect to mineralizing events,
is northeast.
Present Conditions and Plan of Exploration
Though there is a significant amount of historical exploration on
the Winnemucca Mountain Property, none of the previous owners have
established any substantial operations on the property. Further,
the data set from past exploration is not complete. In March 2013
the Company contracted consultants to study the mineralization and
known resources on the Winnemucca Mountain Property. Company
consultants completed mapping and geochemical sampling of the 3,000
feet long Swordfish zone on the Property. Using this surface work
along with available historical drill results data, 3D modeling of
the gold/silver mineralization was completed. Based on the results
of the initial work, Company consultants have recommended further
exploration on the property including geophysics, core and reverse
circulation (RC) drilling. Subject to available funds the Company
plans further exploration of the property as recommended by the
company consultants.
|
TERM
|
|
DEFINITION
|
|
Aplite
|
|
a light-colored fine-grained igneous rock
|
|
Basalt
|
|
basalt is a dark gray to black, dense to finely grained igneous
rock that is the result of lava eruptions. Basalt flows
are noneruptive, voluminous, and characterized by relatively low
viscosity.
|
|
Breccias
|
|
a coarse-grained sedimentary rock made of sharp fragments of rock
and stone cemented together by finer material. Breccia is produced
by volcanic activity or erosion, including frost
shattering.
|
|
Biotite
|
|
a black, dark brown, or green silicate mineral of the mica
group.
|
|
Equigranular
|
|
a material composed chiefly of crystals of similar orders of
magnitude to one another.
|
|
Hornfels
|
|
(a) a
fine-grained metamorphic rock composed of silicate minerals and
formed through the action of heat and pressure on
shale.
|
|
Igneous
|
|
(b) describes
rock formed under conditions of intense heat or produced by the
solidification of volcanic magma on or below the Earth's
surface.
|
|
Lithologic
|
|
(c) the
gross physical character of a rock or rock
formation.
|
|
Monzonite
|
|
a visibly crystalline, granular igneous rock composed chiefly of
equal amounts of two feldspar minerals, plagioclase and orthoclase,
and small amounts of a variety of colored minerals.
|
|
Plutonic
|
|
a mass of intrusive igneous rock that has solidified underground by
the crystallization of magma.
|
|
Quartz
|
|
a common, hard, usually colorless, transparent crystalline mineral
with colored varieties. Use: electronics, gems.
|
|
Silica
|
|
silicon dioxide found naturally in various crystalline and
amorphous forms, e.g. quartz, opal, sand, flint, and agate. Use:
manufacture of glass, abrasives, concrete.
|
Inactive Projects:
Coleman County, Texas – J. E. Richey #2A -Proposed New
Well:
The
Company has sold working interest in a 20 acre tract on the J.E.
Richey Lease to drill a new well near the ARCO Richey #2 well. This
well initially was completed in the Lower Ellenburger in 1982
coming in at 19 barrels per day. Following depletion of the Lower
Ellenburger the well was re-completed in the Upper Ellenburger with
an initial production rate of 2,535 MCF per day. Subsequently the
well was re-completed in the Gray Sand, which came in at 45 barrels
per day on a light acid job and no sand frac was conducted. The
well only produced for a limited amount of time from the Gray Sand
when a hole came in the casing above the cement at 1100 feet caused
by a corrosive formation known as the Coleman Junction and the well
was shut in. This well was plugged due to casing problems in the
well on December 28, 2017.
A
drilling location has been staked west of the J. E. Richey #2 well.
Drilling funds have been received toward the drilling of the new
proposed location for the J. E. Richey #2A well. At the time of
this report no definitive schedule for drilling has been set.
Additional drilling funds is required to be able to drill this well
to a projected total depth of 4,500’. Subsequent to July 31,
2019 the Company has been in negotiations with potential industry
partners to fund the balance of the drilling funds required to
drill this well. The Company will seek to receive a prospect fee
and retain carried working interest.
Guy Ranch Lease, Shackleford County, Texas
During
the fiscal year ended July 31, 2016 the Company acquired a 100%
working interest in a 692-acre Guy Ranch Lease divided into two
tracts. Tract 1 covers 480 acres and Tract 2 covers 212 acres. The
Ranch has 32 wind turbines on it representing it is at a
structurally higher elevation. The principal targets for this
drilling prospect is the Patio (aka Palo Pinto Sand) and Morris
Sands the area is also known to be productive from three other
formations on the Guy Ranch acreage.
The
first project on the Guy Ranch was to re-complete a cased well in
the Morris formation that was reportedly untested. The structure of
the deal was for a third pary to pay 100% of the costs re-complete
the cased well in the Morris formation allocating 20 acres out of
the 450 acres in order to earn a 75% working interest in the cased
well. All records filed with the Texas Railroad Commission
supported that no attempt to produce from the Morris had been
performed. However, it was subsequently found out that in fact an
attempt was made to re-complete in Morris formation and such
attempt was unsuccessful due to an over stimulation of the Morris
with a large frac at high pumping rate. The well produced mostly
water. The 20 acres around the well was not assumed by the Company
or its third-party investors. The unused funds provided by the
third party will be allocated to a new well on the Guy Ranch Lease
with the third party being responsible for providing the balance of
the funds to drill and complete a new well in order to earn 75% of
the working interest.
During
the fiscal year ended July 31, 2018 the Company agreed to convey
approximately 650 acres out of the Guy Ranch lease to Kathis Energy
LLC, its wholly owned subsidiary, for its drilling program for the
consideration of $66,500.
In
March 2018 Kathis Energy LLC, our wholly owned subsidiary, staked
two drilling locations on the Guy Ranch and prepared one drilling
location. This drilling location is a direct offset to a Patio Sand
well that came in at 140 barrels per day. The Patio Sand is one of
the main producing formations in the area generally averages
between 25,000 and 75,000 barrels oil per well. The Morris Sand a
notable gas producer is known to produce up to 1.4 BCF gas from one
well and the Gardner is noted in this area to produce between
50,000 and 110,000 barrels per well. The Net Revenue Interest for
the Guy Ranch lease is 75%. Lease expired on December 16, 2018 and
no extension was made to extend the lease terms and thereby
expired. As of July 31, 2019, the Company deemed its investment to
be fully impaired, recognizing a loss on disposal of
$22,750.
Reeves Lease – Palo Pinto Reef – Jones County,
Texas
In
August 2018, the Company paid for the geological prospecting fees
for a Palo Pinto Reef prospect in Jones County. The Reeves lease
covers 160 acres and is located near Noodle, Texas in Jones County.
The projected depth of the Palo Pinto Reef is 4,300’.
Excellent well control by 6 Strawn wells provides evidence of a
Palo Pinto Reef showing a structure 48’ high to other wells.
The nearest Palo Pinto Reef well to the Reeves Lease made more than
150,000 barrels from one well.
The
Company paid the geological prospect fee of $10,000. It was
verbally understood between the Company and third party to promote
this drilling prospect seeking to retain a carried interest plus
recoup the lease and prospect monies. The oil and gas lease was not
obtained and the Company is seeking to
recover its $10,000 geological fee as the lease was never obtained.
The $10,000 has been disclosed on the balance sheet and is expected
to be collected.
Riverside Leases – Multiple Formations– Runnels County,
Texas
On
October 20, 2017 the Company entered into an exclusive option
agreement with Murphree Oil Company to acquire drilling prospects
on four leases in Runnels County near the City of Ballinger, known
as the Riverside Prospects. During the quarter ended April 30,
2018, the Company, through its wholly owned subsidiary, Kathis
Energy LLC, (“Kathis”) paid the lease bonuses for
extending the oil and gas lease period on 548.76 acres covering the
Riverside Prospects. This acreage consists of 4 leases in a well
established area where oil and gas production was discovered during
1978 – 1983.
The
location of the leases covering the Riverside Prospects is
approximately 2 miles west of the City of Ballinger, Texas in
Runnels County.
Kathis
had an option to acquire these leases in stages with the first
stage to have proof of drilling funds to drill one well by December
31, 2018. The Net Revenue Interest on all of these leases is 75%
and the expiration of these leases varies from April thru June
2019. The lease terms of these four leases were not extended as of
July 31, 2019 resulting in a loss of its investment in these oil
leases. All expenditures on this property had been expensed prior
to its expiration.
ITEM 3. LEGAL PROCEEDINGS
We know of no material, existing or pending legal proceedings
against us, nor are we involved as a plaintiff in any material
proceeding or pending litigation. There are no proceedings in which
any of our directors, officers or affiliates, or any registered or
beneficial shareholder, is an adverse party or has a material
interest adverse to our company.
The Company has been named as a third-party in pending litigation
for which the Company denies any wrongdoing. The Company entered
into a joint venture agreement with an accredited unrelated party
where funds were invested in two of the Company’s projects.
The unrelated party is a knowledgeable oil and gas investor and has
experience with investing in oil and gas projects. The Company is
named as a third party to the legal action solely due to its
association with the unrelated party and the funds he used for
making the investment with the Company. On April 27, 2020, a Motion to Dismiss was filed
in the District Court of Dallas, Texas dismissing all
claims.
ITEM 4. MINE SAFETY
DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Market Information
Our
common stock is quoted under the symbol “NMEX” on the
OTCBB operated by the Financial Industry Regulatory Authority, Inc.
(“FINRA”) and the OTCQB operated by OTC Markets Group,
Inc. Few market makers continue to participate in the OTCBB
system because of high fees charged by FINRA. The criteria
for listing on either the OTCBB or OTCQB are similar and include
that we remain current in our SEC reporting.
Our
shares are subject to Section 15(g) and Rule 15g-9 of the
Securities and Exchange Act, commonly referred to as the
“penny stock” rule. The rule defines penny stock
to be any equity security that has a market price less than $5.00
per share, subject to certain exceptions. These rules may restrict
the ability of broker-dealers to trade or maintain a market in our
common stock and may affect the ability of shareholders to sell
their shares. Broker-dealers who sell penny stocks to persons
other than established customers and accredited investors must make
a special suitability determination for the purchase of the
security. Accredited investors, in general, include individuals
with assets in excess of $1,000,000 (not including their personal
residence) or annual income exceeding $200,000 or $300,000 together
with their spouse, and certain institutional investors. The rules
require the broker-dealer to receive the purchaser’s written
consent to the transaction prior to the purchase and require the
broker-dealer to deliver a risk disclosure document relating to the
penny stock prior to the first transaction. A broker-dealer also
must disclose the commissions payable to both the broker-dealer and
the registered representative, and current quotations for the
security. Finally, monthly statements must be sent to
customers disclosing recent price information for the penny
stocks.
At
January 17, 2020 there were approximately 70 holders of record of
our common stock, although there may be other persons who are
beneficial owners of our common stock held in street name. The
transfer agent and registrar for our common stock is Issuer Direct
Corporation, 1981 Murray Holiday Road, #100, Salt Lake City, UT
84117.
Dividend Policy
We have
never paid any cash dividends and intend, for the foreseeable
future, to retain any future earnings for the development of our
business. Our Board of Directors will determine our future dividend
policy on the basis of various factors, including our results of
operations, financial condition, capital requirements and
investment opportunities.
RECENT ISSUANCES OF UNREGISTERED SECURITIES
On July 18, 2019, the Company sold 833,334 shares of common stock
for total cash proceeds of $25,000.
On July 18, 2019, the Company granted 75,000 shares of common stock
for services. The shares were valued at $0.051, the closing stock
price on the date of grant for total non-cash expense of $3,825. As
of July 1, 2019, the shares have not yet been issued by the
transfer agent and have been credited to stock
payable.
On July 31, 2019, the Company granted 1,000,000 shares of common
stock for services. The shares were valued at $0.041, the closing
stock price on the date of grant for total non-cash expense of
$41,100.
Other
than as disclosed above, we did not sell any equity securities
which were not registered under the Securities Act during the year
ended July 31, 2019 that were not otherwise disclosed on our
quarterly reports on Form 10-Q or our current reports on Form 8-K
filed during the year ended July 31, 2019.
ISSUER REPURCHASES OF EQUITY SECURITIES
None
ITEM 6. SELECTED FINANCIAL
DATA
We are
a smaller reporting company as defined by Rule 12b-2 of the
Securities Exchange Act of 1934 and are not required to provide the
information under this item.
ITEM 7. MANAGEMENT’S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Results of Operations for the Years Ended July 31, 2019 and
2018
The following summary of our results of operations should be read
in conjunction with our financial statements for the year
ended July 31, 2019, which are
included herein.
|
|
For the Years
EndedJuly 31,
|
|
|
|
|
|
Revenue,
net
|
$14,273
|
$(946)
|
|
|
|
|
|
Officer
compensation
|
16,000
|
56,500
|
|
Consulting
– related party
|
57,500
|
26,500
|
|
Consulting
|
11,325
|
91,000
|
|
Professional
fees
|
37,984
|
57,050
|
|
Advertising
and promotion
|
38,485
|
123,352
|
|
Development
property expenditures
|
-
|
20,266
|
|
Mineral
property expenditures
|
355,442
|
269,703
|
|
General
and administrative expenses
|
50,102
|
105,415
|
|
Total operating
expenses
|
566,838
|
749,786
|
|
|
|
|
|
Other income
(expense):
|
|
|
|
Interest
expense
|
(17,980)
|
(17,164)
|
|
Loss
on disposal of mineral rights
|
(100,772)
|
-
|
|
Loss
on conversion of debt
|
-
|
(6,000)
|
|
Gain
on forgiveness of debt
|
99,740
|
4,120
|
|
Total other income
(expense)
|
(19,012)
|
(19,044)
|
|
|
|
|
|
Net
Loss
|
$(571,577)
|
$(769,776)
|
Revenue
Revenues
of oil and gas for the years ended July 31, 2019 and 2018 were
$14,273 and negative $946, respectively, an increase of $15,219.
Revenues are earned primarily from the J.E. Richey Lease from the
sale of oil and gas and are recorded net of any distributions paid.
The
increase in revenue is due to lower production as well as lower oil
and gas prices. Distributions
are paid or accrued in the quarter in which the revenue for those
distributions is earned. Distributions are paid to the joint
venture partners in the J.E. Richey Lease. In the prior year we
paid additional distributions that were due which resulted in our
negative revenue.
Officer compensation
Officer
compensation was $16,000 and $56,500 for the years ended July 31,
2019 and 2018, respectively, a decrease of $40,500, or 72%. The
decrease is due to no longer paying salary to the CEO after October
31, 2018.
Consulting – related party
Consulting
– related party services were $57,500 and $26,500 for the
years ended July 31, 2019 and 2018, respectively, an increase of
$31,000, or 117%. Fees are paid to Noel Schaefer, Director, but are
billed as consulting fees. During the current year
this fee was increased to $5,000 per month as Mr. Schaefer, has
increased his time spent on the Company over the past several
months.
Consulting expense
Consulting fees were $11,325 and $91,000 for the years ended
July 31, 2019 and 2018, respectively, a decrease of $79,675, or
88%. When
needed the Company hires experts in the mining, oil and gas
industries to assist with its current projects. The decrease in
consulting fees in the current year can be attributed to a decrease
in expenditures while the Company pursues additional
funding.
Professional fees
Professional
fees were $37,984 and $57,050 for the years ended July 31, 2019 and
2018, respectively, a decrease of $19,066, or 33%. Professional
fees generally consist of legal, audit and accounting expense.
The
decrease can be attributed to a decrease in accounting fees billed
during the year.
Advertising and promotion
Advertising
and promotion expense were $38,485 and $123,352 for the years ended
July 31, 2019 and 2018, respectively, a decrease of $84,867, or
69%. We
have temporarily decreased our spending in this area to conserve
our available cash.
Development property expenditures
Development
property expenditures were $0 and $20,266 for the years ended July
31, 2019 and 2018, respectively. We did not pursue this development
property in the current year.
Mineral property expenditures
Mineral
property expenditures were $355,442 and $269,703 for the years
ended July 31, 2019 and 2018, respectively, an increase of $85,739,
or 31.7%. Expenditures include lease payments for the working
interest in the mineral properties and rework expense. The increase
in mainly due to the funds used towards the development of the
Winnemucca property.
General and administrative
General
and administrative expense was $50,102 and $105,415 for the year
ended July 31, 2019 and 2018, respectively, a decrease of $55,313,
or 52%. The
decrease can be largely attributed to a decrease in Bureau Land
Management (“BLM”) annual rentals and associated fees
as well as to a decrease in travel expense and public relation
expenditures.
Other expense
During
the year ended July 31, 2019 we had total other expense of $19,012
compared to $19,044 in the prior year. During the current year we
incurred interest expense of $17,980, and a loss on disposal of
mineral rights of $100,772, offset with a gain on forgiveness of
debt of $99,740. During the year ended July 31, 2018 we had total
other expense of $19,044. During the prior year we incurred
interest expense of $17,164, and a loss on conversion of debt
$6,000, offset with a gain on forgiveness of debt of
$4,120.
Net Loss
For the
year ended July 31, 2019, we had a net loss of $571,577 as compared
to a net loss of $769,776 for year ended July 31, 2018. Our net
loss was lower in the current period primarily due to our decrease
in operating expenses.
Liquidity and Financial Condition
Operating Activities
Cash
used by operating activities was $284,035 for the year ended July
31, 2019. Cash used for operating activities was $323,875 for the
year ended July 31, 2018.
Investing Activities
We used
$20,000 for investing activities for the year ended July 31, 2019
compared to net cash used of $45,250 used in year ended July 31,
2018.
Financing Activities
Net cash provided by financing activities was $233,210 for
year ended July 31, 2019 compared to
$420,975 year ended July 31, 2018. During the year ended July 31, 2019, we
received $220,000 from the sale of common stock, $69,180 from
related party loans, $55,970 of which was repaid and received
$9,000 from loans payable, of which we repaid $9,000. During the year ended July 31, 2018, we
received $355,975 from the sale of common stock and $65,000 in
other advances.
We had the following loans outstanding as of July 31,
2019:
On August 22, 2013 the Company entered into a $50,000 Convertible
Loan Agreement with an un-related party. The Loan and interest are
convertible into Units at $0.08 per Unit with each Unit consisting
of one common share of the Company and ½ warrant with each
full warrant exercisable for one year to purchase one common share
at $0.30 per share. On July 10, 2014, a further $35,000 was
received from the same unrelated party under the same terms. On
July 31, 2018, this Note was amended whereby the principal and
interest are now convertible into Units at $0.04 per Unit with each
Unit consisting of one common share of the Company and ½
warrant with each full warrant exercisable for one year to purchase
one common share at $0.08 per share. The Loan shall bear interest
at the rate of Eight Percent (8%) per annum and matures on March
26, 2020. As of July 31, 2019, there is $85,000 and $43,182
of principal and accrued interest, respectively, due on this
loan.
On April 16, 2017, the Company executed a promissory note for
$15,000 with a third party. The note matures in two years and
interest is set at $3,000 for the full two years. As of July
31, 2019, there is $15,000 and $1,875 of principal and accrued
interest, respectively, due on this loan. This loan is currently in
default.
On October 20, 2017, the Company executed a convertible promissory
note for $25,000 with a third party. The note accrues interest at
6%, matures in two years and is convertible into shares of common
stock at maturity, at a minimum of $0.10 per share, at the option
of the holder. As of July 31, 2019, there is $25,000 and $2,367 of
principal and accrued interest due on this loan, respectively. This
loan is due on October 20, 2019. No shares have been issued for
conversion of this loan.
On July 31, 2018, the wife the CEO, loaned the Company $25,000 for
general operating expenses. This loan was repaid on August 2, 2018
with an additional $5,000 for interest and a loan fee. On August 3,
2018, Mrs. Webb loaned the Company $30,000 which was repaid on
August 21, 2018. On September 25, 2018, the Company executed a loan
agreement with Mrs. Webb for $6,800. The loan is to be repaid by
December 15, 2018, with an additional $680 to cover interest and
fees. On October 10, 2018, the Company executed a loan agreement
with Mrs. Webb for $15,000. The loan was to be repaid by December
15, 2018, with an additional $1,500 to cover interest and fees. As
of July 31, 2019, the Company owes Mrs. Webb $20,930 and $2,180 of
principal and interest, respectively. Amounts due on these loans
are currently in default.
We will require additional funds to fund our budgeted expenses over
the next twelve months. These funds may be raised through equity
financing, debt financing, or other sources, which may result in
further dilution in the equity ownership of our shares. There is
still no assurance that we will be able to maintain operations at a
level sufficient for an investor to obtain a return on his
investment in our common stock. Further, we may continue to be
unprofitable. We need to raise additional funds in the immediate
future in order to proceed with our budgeted expenses.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are
reasonably likely to have a current or future effect on our
financial condition, changes in financial condition, revenues or
expenses, results of operations, liquidity, capital expenditures or
capital resources that is material to stockholders.
Critical Accounting Policies
Refer to Note 2 of our financial statements contained elsewhere in
this Form 10-K for a summary of our critical accounting policies
and recently adopting and issued accounting standards.
Recently Issued accounting pronouncements
In February 2016, the FASB issued ASU 2016-02, Leases
(Topic 842). ASU 2016-02
requires lessees to recognize lease assets and lease liabilities on
the balance sheet and requires expanded disclosures about leasing
arrangements. The new standard supersedes the present
U.S. GAAP standard on leases and requires substantially all
leases to be reported on the balance sheet as right-of-use assets
and lease obligations. ASU 2016-02 is effective for fiscal years
beginning after December 15, 2018 and interim periods in fiscal
years beginning after December 15, 2018, with early adoption
permitted. The Company has evaluated the impact of this accounting
standard update and noted that it has had no material
impact.
Topic 606, Revenue from Contracts with
Customers, of the Financial
Accounting Standards Board’s (FASB) Accounting Standards
Codification (ASC). The guidance in ASC 606 was originally issued
by the FASB in May 2014 in Accounting Standards Update (ASU)
2014-09, Revenue from Contracts with
Customers (Topic 606). Since
then, the FASB has issued several ASUs that have revised or
clarified the guidance in ASC 606. The Company has evaluated the
impact of this accounting standard update and noted that it has had
no material impact.
In January 2017, the Financial Accounting Standards Board
(“FASB”) issued an Accounting Standards Update
(“ASU”) 2017-01, Business Combinations
(Topic 805) Clarifying the Definition of a
Business. The amendments in
this update clarify the definition of a business with the objective
of adding guidance to assist entities with evaluating whether
transactions should be accounted for as acquisitions or disposals
of assets or businesses. The definition of a business affects many
areas of accounting including acquisitions, disposals, goodwill,
and consolidation. The guidance is effective for interim and annual
periods beginning after December 15, 2017 and should be
applied prospectively on or after the effective date. The Company
is in the process of evaluating the impact of this accounting
standard update.
On June 20, 2018, the Financial Accounting Standards Board (FASB)
issued Accounting Standards Update (ASU)
2018-07, Compensation—Stock
Compensation (Topic 718): Improvements to Nonemployee Share-Based
Payment Accounting. ASU 2018-07
is intended to reduce cost and complexity and to improve financial
reporting for share-based payments to nonemployees (for example,
service providers, external legal counsel, suppliers, etc.). Under
the new standard, companies will no longer be required to value
non-employee awards differently from employee awards. Meaning that
companies will value all equity classified awards at their
grant-date under ASC718 and forgo revaluing the award after this
date. The Company has chosen to early adopt this
standard.
The
Company has implemented all new accounting pronouncements that are
in effect. These pronouncements did not have any material impact on
the financial statements unless otherwise disclosed, and the
Company does not believe that there are any other new accounting
pronouncements that have been issued that might have a material
impact on its financial position or results of
operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
We are
a smaller reporting company as defined by Rule 12b-2 of the
Securities Exchange Act of 1934 and are not required to provide the
information under this item.
ITEM 8. CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
NORTHERN MINERALS & EXPLORATION LTD.
CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
To the
Board of Directors and
Stockholders of
Northern Minerals & Exploration, Ltd
Opinion
on the Financial Statements
We have audited the
accompanying consolidated balance sheets of Northern Minerals &
Exploration, Ltd. (the Company) as of July 31, 2019, and the
related consolidated statements of operations, stockholders’
deficit, and cash flows for the year ended July 31, 2019, and the
related notes (collectively referred to as the financial
statements). In our opinion, the consolidated financial statements
present fairly, in all material respects, the financial position of
the Company as of July 31, 2019, and the result of its operations
and its cash flows for the year ended July 31, 2019, in conformity
with accounting principles generally accepted in the United States
of America.
Consideration
of the Company’s Ability to Continue as a Going
Concern
The accompanying
consolidated financial statements have been prepared assuming that
the Company will continue as a going concern. As shown in the
accompanying consolidated financial statements, the Company has
significant net losses, cash flow deficiencies, negative working
capital and an accumulated deficit. Those conditions raise
substantial doubt about the Company’s ability to continue as
a going concern. Management’s plans regarding those matters
are described in Note 3. The consolidated financial statements do
not include any adjustments that might result from the outcome of
this uncertainty.
Basis
for Opinion
These financial
statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the
Company’s financial statements based on our audit. We are a
public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required
to be independent with respect to the Company in accordance with
the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our
audit in accordance with the standards of the PCAOB. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement, whether due to error or fraud. The
Company is not required to have, nor were we engaged to perform, an
audit of its internal control over financial reporting. As part of
our audit, we are required to obtain an understanding of internal
control over financial reporting, 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.
Our audit included
performing procedures to assess the risks of material misstatement
of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures
included examining, on a test basis, evidence regarding the amounts
and disclosures in the financial statements. Our audit also
included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audit
provides a reasonable basis for our opinion.
Haynie
& Company
Salt
Lake City, Utah
June 3,
2020
We have
served as the company’s auditor since 2020
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of Northern Minerals &
Exploration Ltd.
Opinion on the Financial Statements
We have
audited the accompanying consolidated balance sheet of Northern
Minerals & Exploration Ltd. (“the Company”) as of
July 31, 2018, and the related consolidated statements of
operations, changes in stockholders’ equity, and cash flows
for the year then ended, and the related notes (collectively
referred to as the financial statements). In our opinion, the
financial statements present fairly, in all material respects, the
financial position of the Company as of July 31, 2018, and the
results of its operations and its cash flows for year then ended,
in conformity with accounting principles generally accepted in the
United States of America.
Consideration of the Company’s Ability to Continue as a Going
Concern
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 an accumulated
deficit and intends to fund operations through equity financing
which may be insufficient to fund its capital expenditures. These
factors raise substantial doubt about the Company’s ability
to continue as a going concern. Management’s plans in regard
to these matters are also described in Note 3. The financial
statements do not include any adjustments that might result from
the outcome of this uncertainty.
Basis for Opinion
These
financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the
Company’s financial statements based on our audit. We are a
public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required
to be independent with respect to the Company in accordance with
the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the
PCAOB.
We
conducted our audit in accordance with the standards of the PCAOB.
Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements
are free of material misstatement, whether due to error or fraud.
The Company is not required to have, nor were we engaged to
perform, an audit of its internal control over financial reporting.
As part of our audit, we are required to obtain an understanding of
internal control over financial reporting, 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.
Our
audit included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to
error or fraud, and performing procedures that respond to those
risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial
statements. Our audit also included evaluating the accounting
principles used and significant estimates made by management, as
well as evaluating the overall presentation of the financial
statements. We believe that our audit provides a reasonable basis
for our opinion.
|
Fruci
& Associates II, PLLC
We have
served as the Company’s auditor from 2016 to February 14,
2020.
Spokane,
Washington
|
|
November
13, 2018
|
|
NORTHERN MINERALS & EXPLORATION LTD.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
Current
Assets:
|
|
|
|
Cash
|
$21,847
|
$52,672
|
|
Prepaid
expenses
|
5,000
|
3,500
|
|
Accounts
receivable
|
-
|
3,229
|
|
Other
receivable
|
10,000
|
-
|
|
Stock subscription
receivable
|
-
|
20,000
|
|
|
|
|
|
Total Current
Assets
|
36,847
|
79,401
|
|
Other
Assets:
|
|
|
|
Mineral rights and
properties
|
-
|
30,065
|
|
Oil and gas
properties
|
28,800
|
141,250
|
|
Total Other
Assets
|
28,800
|
171,315
|
|
|
|
|
|
TOTAL
ASSETS
|
$65,647
|
$250,716
|
|
|
|
|
|
LIABILITIES & STOCKHOLDERS’ DEFICIT
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
Accounts
payable
|
$63,959
|
$85,146
|
|
Accounts payable
– related party
|
50,000
|
43,374
|
|
Accrued
liabilities
|
637,754
|
327,580
|
|
Current portion of
property option payable
|
-
|
116,000
|
|
Convertible
debt
|
110,000
|
25,000
|
|
Loans
payable
|
20,000
|
125,990
|
|
Loans payable
– related party
|
23,210
|
-
|
|
Total Current
Liabilities
|
904,923
|
723,090
|
|
|
|
|
|
Convertible debt
– long term
|
-
|
85,000
|
|
|
|
|
|
TOTAL
LIABILITIES
|
904,923
|
808,090
|
|
|
|
|
|
Commitments and
Contingencies (Note 11)
|
-
|
-
|
|
|
|
|
|
Stockholders’
Deficit:
|
|
|
|
Common stock,
$0.001 par value, 75,000,000 shares authorized; 55,836,819 and
48,286,818 shares issued and outstanding, respectively
|
55,837
|
48,287
|
|
Common stock to be
issued
|
44,925
|
50,000
|
|
Additional
paid-in-capital
|
2,024,035
|
1,736,835
|
|
Accumulated
deficit
|
(2,964,073)
|
(2,392,496)
|
|
|
|
|
|
Total
Stockholders’ Deficit
|
(839,276)
|
(557,374)
|
|
|
|
|
|
TOTAL LIABILITIES
& STOCKHOLDERS’ DEFICIT
|
$65,647
|
$250,716
|
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN MINERALS & EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
For the Years
EndedJuly 31,
|
|
|
|
|
|
|
|
|
|
Revenue,
net
|
$14,273
|
$(946)
|
|
|
|
|
|
Operating
expenses:
|
|
|
|
Officer
compensation
|
16,000
|
56,500
|
|
Consulting
– related party
|
57,500
|
26,500
|
|
Consulting
|
11,325
|
91,000
|
|
Professional
fees
|
37,984
|
57,050
|
|
Advertising
and promotion
|
38,485
|
123,352
|
|
Development
property expenditures
|
-
|
20,266
|
|
Mineral
property expenditures
|
355,442
|
269,703
|
|
General
and administrative expenses
|
50,102
|
105,415
|
|
Total operating
expenses
|
566,838
|
749,786
|
|
Loss from
operations
|
(552,565)
|
(750,732)
|
|
|
|
|
|
Other income
(expense):
|
|
|
|
Interest
expense
|
(17,980)
|
(17,164)
|
|
Loss
on disposal of mineral rights
|
(100,772)
|
-
|
|
Loss
on conversion of debt
|
-
|
(6,000)
|
|
Gain
on forgiveness of debt
|
99,740
|
4,120
|
|
Total other
expense
|
(19,012)
|
(19,044)
|
|
|
|
|
|
Loss before
provision for income taxes
|
(571,577)
|
(769,776)
|
|
Provision for
income taxes
|
-
|
-
|
|
Net
Loss
|
$(571,577)
|
$(769,776)
|
|
|
|
|
|
Net loss per share
from operations, basic and diluted
|
$(0.01)
|
(0.02)
|
|
|
|
|
|
Weighted average
number of common shares outstanding, basic and diluted
|
51,155,037
|
40,396,771
|
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN
MINERALS & EXPLORATION LTD.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ DEFICIT
FOR THE YEARS ENDED JULY 31, 2019 AND 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31,
2017
|
26,797,818
|
$26,798
|
$1,239,349
|
$-
|
$(1,622,720)
|
$(356,573)
|
|
Common stock issued
for services
|
3,000,000
|
3,000
|
180,000
|
-
|
-
|
183,000
|
|
Common stock issued
for cash
|
18,289,000
|
18,289
|
307,686
|
50,000
|
-
|
375,975
|
|
Common stock issued
for conversion of debt
|
200,000
|
200
|
9,800
|
-
|
-
|
10,000
|
|
Net loss for the
year ended July 31, 2018
|
-
|
-
|
-
|
-
|
(769,776)
|
(769,776)
|
|
Balance, July 31,
2018
|
48,286,818
|
48,287
|
1,736,835
|
50,000
|
(2,392,496)
|
(557,374)
|
|
Common stock issued
for services
|
150,000
|
150
|
9,600
|
3,825
|
-
|
13,575
|
|
Common stock issued
for cash
|
7,400,001
|
7,400
|
262,600
|
(50,000)
|
-
|
220,000
|
|
Common stock issued
for accrued liabilities
|
-
|
-
|
-
|
41,100
|
-
|
41,100
|
|
Contributed
capital
|
-
|
-
|
15,000
|
-
|
-
|
15,000
|
|
Net loss for the
year ended July 31, 2019
|
-
|
-
|
-
|
-
|
(571,577)
|
(571,577)
|
|
Balance, July 31,
2019
|
55,836,819
|
$55,837
|
$2,024,035
|
$44,925
|
$(2,964,073)
|
$(839,276)
|
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN MINERALS & EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF CASH
FLOWS
|
|
For the Years
Ended
July
31,
|
|
|
|
|
|
Cash Flows from
Operating Activities:
|
|
|
|
Net
loss
|
$(571,577)
|
$(769,776)
|
|
|
|
|
|
Adjustments to
reconcile net loss to net cash used in Operating
activities:
|
|
|
|
Gain on forgiveness
of debt
|
(99,740)
|
(4,120)
|
|
Loss on disposal of
mineral rights
|
100,772
|
-
|
|
Loss on conversion
of debt
|
-
|
6,000
|
|
Amortization of
capitalized costs
|
10,000
|
-
|
|
Stock compensation
expense
|
13,575
|
183,000
|
|
Changes in
Operating Assets and Liabilities:
|
|
|
|
Prepaid
expenses
|
(1,500)
|
(3,500)
|
|
Accounts
receivable
|
3,229
|
1,184
|
|
Other
receivables
|
48,318
|
-
|
|
Accounts payables
and accrued liabilities
|
231,269
|
70,759
|
|
Accounts payable
– related party
|
6,626
|
17,500
|
|
Accrued
interest
|
9,800
|
10,864
|
|
Advances for well
work
|
5,193
|
164,214
|
|
Net cash used in
operating activities
|
(244,035)
|
(323,875)
|
|
|
|
|
|
Cash Flows used in
Investing Activities:
|
|
|
|
Cash paid for oil
and gas properties
|
(20,000)
|
(45,250)
|
|
Net cash used in
investing activities
|
(20,000)
|
(45,250)
|
|
|
|
|
|
Cash Flows from
Financing Activities:
|
|
|
|
Proceeds from loan
payable
|
9,000
|
-
|
|
Repayment of loan
payable
|
(9,000)
|
-
|
|
Proceeds from loans
payable – related party
|
69,180
|
-
|
|
Payments on loans
payable – related party
|
(55,970)
|
-
|
|
Proceeds from the
sale of common stock
|
220,000
|
355,975
|
|
Other
advances
|
-
|
65,000
|
|
Net cash provided
by financing activities
|
233,210
|
420,975
|
|
|
|
|
|
Net (decrease)
increase in cash
|
(30,825)
|
51,850
|
|
|
|
|
|
Cash at beginning
of the year
|
52,672
|
822
|
|
Cash at end of the
year
|
$21,847
|
$52,672
|
|
|
|
|
|
Cash paid during
the period for:
|
|
|
|
Interest
|
$-
|
$1,500
|
|
Taxes
|
$-
|
$-
|
|
|
|
|
|
Supplemental
disclosure of non-cash activity:
|
|
|
|
Common stock issued
for accrued liabilities
|
$41,100
|
$-
|
The accompanying notes are an integral part of these consolidated
financial statements.
Northern Minerals & Exploration Ltd.
Notes to Consolidated Financial
Statements
July 31, 2019
NOTE 1 - ORGANIZATION AND BUSINESS OPERATIONS
Northern
Minerals & Exploration Ltd. (the “Company”) is an
emerging natural resource company operating in oil and gas
production in central Texas and exploration for gold and silver in
northern Nevada.
The
Company was incorporated in Nevada on December 11, 2006 under the
name Punchline Entertainment, Inc. On August 22, 2012, the
Company’s board of directors approved an agreement and plan
of merger to effect a name change of the Company from Punchline
Entertainment, Inc. to Punchline Resources Ltd. On July 12, 2013,
the stockholders approved an amendment to change the name of the
Company from Punchline Resources Ltd. to Northern Mineral &
Exploration Ltd. FINRA approved the name change on August 13,
2013.
On
November 22, 2017, the Company created a wholly owned subsidiary,
Kathis Energy LLC (“Kathis”) for the purpose of
conducting oil and gas drilling programs in Texas. The Company
agreed to assign to Kathis the Olson and Guy Ranch leases in
exchange for $126,500.
On
December 14, 2017, Kathis Energy, LLC and other Limited Partners,
created Kathis Energy Fund 1, LP, a limited partnership created for
raising investor funds.
On May
7, 2018, the Company created ENMEX LLC, a wholly owned subsidiary
in Mexico, for the purposes of managing and operating its
investments in Mexico including but not limited to the Joint
Venture opportunity being negotiated with Pemer Bacalar on the 61
acres on the Bacalar Lagoon on the Yucatan Peninsula. There was no
activity from inception to date.
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
The
accounting and reporting policies of the Company conform to U.S.
generally accepted accounting principles (US GAAP).
Use of estimates
The
preparation of financial statements in conformity with generally
accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results may differ from those
estimates.
Cash and Cash Equivalents
The Company considers all cash accounts, which are not subject to
withdrawal restrictions or penalties, and all highly liquid debt
instruments purchased with a maturity of three months or less as
cash and cash equivalents. The carrying amount of financial
instruments included in cash and cash equivalents approximates fair
value because of the short maturities for the instruments
held. The Company had no cash equivalents as of July 31, 2019
and 2018.
Principles of Consolidation
The
accompanying consolidated financial statements include the accounts
of the Company and its wholly-owned subsidiaries, Kathis Energy
LLC, Kathis Energy Fund 1, LLP and Enmex Operations LLC. All
financial information has been prepared in conformity with
accounting principles generally accepted in the United States of
America. All significant intercompany transactions and balances
have been eliminated.
Reclassifications
Certain
reclassifications have been made to the prior year financial
information to conform to the presentation used in the financial
statements for the year ended July 31, 2019. Specifically, the
Company has changed its presentation of revenue from revenue and
distributions to only presenting net revenue. There was no effect
on net loss or earnings per share.
Revenue Recognition
Revenue
is recognized when a customer obtains control of promised goods or
services and is recognized in an amount that reflects the
consideration that an entity expects to receive in exchange for
those goods or services. In addition, the standard requires
disclosure of the nature, amount, timing, and uncertainty of
revenue and cash flows arising from contracts with customers. The
amount of revenue that is recorded reflects the consideration that
the Company expects to receive in exchange for those goods. The
Company applies the following five-step model in order to determine
this amount: (i) identification of the promised goods in the
contract; (ii) determination of whether the promised goods are
performance obligations, including whether they are distinct in the
context of the contract; (iii) measurement of the transaction
price, including the constraint on variable consideration; (iv)
allocation of the transaction price to the performance obligations;
and (v) recognition of revenue when (or as) the Company satisfies
each performance obligation.
The Company only applies the five-step model to contracts
when it is probable that the entity will collect the consideration
it is entitled to in exchange for the goods or services it
transfers to the customer. Once a contract is determined to be
within the scope of ASC 606 at contract inception, the Company
reviews the contract to determine which performance obligations the
Company must deliver and which of these performance obligations are
distinct. The Company recognizes as revenues the amount of the
transaction price that is allocated to the respective performance
obligation when the performance obligation is satisfied or as it is
satisfied. Generally, the Company’s performance obligations
are transferred to customers at a point in time, typically upon
delivery.
The Company receives a majority of its revenue from oil and gas
sales from the J. E Richey lease located in Coleman County, Texas.
Revenue is recognized upon delivery.
For the
year ended July 31, 2019, we recognized 62.4% of revenue, from
crude oil sales on our Richey Lease. For the year ended July 31,
2018, we had negative net revenue due to having to payout excess
distribution, however, crude oil sales were 93.2% of revenue
recognized during the year.
Accounts Receivable
Revenues that have been recognized but not yet received are
recorded as accounts receivable. Losses on receivables will be
recognized when it is more likely than not that a receivable will
not be collected. An allowance for estimated uncollectible amounts
will be recognized to reduce the amount of receivables to its net
realizable value. The allowance for uncollectible amounts is
evaluated quarterly.
Long Lived Assets
Property
consists of mineral rights purchases as stipulated by underlying
agreements and payments made for oil and gas exploration rights.
Our company assesses the impairment of long-lived assets whenever
events or changes in circumstances indicate that the carrying value
may not be recoverable. When we determine that the carrying value
of long-lived assets may not be recoverable based upon the
existence of one or more indicators of impairment and the carrying
value of the asset cannot be recovered from projected undiscounted
cash flows, we record an impairment charge. Our company measures
any impairment based on a projected discounted cash flow method
using a discount rate determined by management to be commensurate
with the risk inherent in the current business model. Significant
management judgment is required in determining whether an indicator
of impairment exists and in projecting cash flows.
Mineral Property Acquisition and Exploration Costs
Mineral
property acquisition and exploration costs are expensed as incurred
until such time as economic reserves are quantified. Cost of lease,
exploration, carrying and retaining unproven mineral lease
properties are expensed as incurred. We have chosen to expense all
mineral exploration costs as incurred given that it is still in the
exploration stage. Once our company has identified proven and
probable reserves in its investigation of its properties and upon
development of a plan for operating a mine, it would enter the
development stage and capitalize future costs until production is
established. When a property reaches the production stage, the
related capitalized costs will be amortized over the estimated life
of the probable-proven reserves. When our company has capitalized
mineral properties, these properties will be periodically assessed
for impairment of value and any diminution in value.
Oil and Gas Properties
The
Company follows the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all
property acquisition costs and costs of exploratory and development
wells are capitalized when incurred, pending determination of
whether the well found proved reserves. If an exploratory well does
not find proved reserves, the costs of drilling the well are
charged to expense. The costs of development wells are capitalized
whether those wells are successful or unsuccessful. Other
exploration costs, including certain geological and geophysical
expenses and delay rentals for oil and gas leases, are charged to
expense as incurred. Maintenance and repairs are charged to
expense, and renewals and betterments are capitalized to the
appropriate property and equipment accounts. Depletion and
amortization of oil and gas properties are computed on a
well-by-well basis using the units-of-production method. Although
the Company has recognized minimal levels of production and
revenue, none of its property have proved reserves. Therefore, the
Company’s properties are designated as unproved
properties.
Unproved
property costs are not subject to amortization and consist
primarily of leasehold costs related to unproved areas. Unproved
property costs are transferred to proved properties if the
properties are subsequently determined to be productive and are
assigned proved reserves. Proceeds from sales of partial interest
in unproved leases are accounted for as a recovery of cost without
recognizing any gain until all cost is recovered. Unproved
properties are assessed periodically for impairment based on
remaining lease terms, drilling results, reservoir performance,
commodity price outlooks or future plans to develop acreage. The
Company had total impairment charges on its oil and gas properties
of $100,772 for the year ended July 31, 2019.
Asset Retirement Obligation
Accounting
Standards Codification (“ASC”) Topic 410, Asset
Retirement and Environmental Obligations (“ASC 410”)
requires an entity to recognize the fair value of a liability for
an asset retirement obligation in the period in which it is
incurred. The net estimated costs are discounted to present values
using credit-adjusted, risk-free rate over the estimated economic
life of the oil and gas properties. Such costs are capitalized as
part of the related asset. The asset is depleted on the equivalent
unit-of-production method based upon estimates of proved oil and
natural gas reserves. The liability is periodically adjusted to
reflect (1) new liabilities incurred, (2) liabilities settled
during the period, (3) accretion expense and (4) revisions to
estimated future cash flow requirements. To date, the Company has
very few operating wells. In 2019, the Company on had one working
well. Because there is only one active well on the Ritchie Lease,
the Company estimates the asset retirement obligation to be trivial
and has not recorded an ARO liability.
Basic and Diluted Earnings Per Share
Net
income (loss) per common share is computed pursuant to ASC
260-10-45, Earnings per
Share—Overall—Other Presentation Matters. Basic
net income (loss) per common share is computed by dividing net
income (loss) by the weighted average number of shares of common
stock outstanding during the period. Diluted net income (loss) per
common share is computed by dividing net income (loss) by the
weighted average number of shares of common stock and potentially
outstanding shares of common stock during the period. The weighted
average number of common shares outstanding and potentially
outstanding common shares assumes that we incorporated as of the
beginning of the first period presented.
As of
July 31, 2019 and 2018, the Company had 4,768,408 and 6,566,815
potentially dilutive shares; however, the diluted loss per share is
the same as the basic loss per share for the years ended July 31,
2019 and 2018, as the inclusion of any potential shares would have
had an antidilutive effect due to our loss from
operations.
Recently issued accounting pronouncements
In February 2016, the FASB issued ASU
2016-02, Leases (Topic
842). The ASU requires that a
lessee recognize the assets and liabilities that arise from
operating leases. A lessee should recognize in the statement of
financial position a liability to make lease payments (the lease
liability) and a right-of-use asset representing its right to use
the underlying asset for the lease term. For leases with a term of
12 months or less, a lessee is permitted to make an accounting
policy election by class of underlying asset not to recognize lease
assets and lease liabilities. This new guidance will be effective
for annual reporting periods beginning after December 15, 2018,
including interim periods within those annual reporting periods,
and early adoption is permitted. In transition, lessees and lessors
are required to recognize and measure leases at the beginning of
the earliest period presented using a modified retrospective
approach. The Company adopted this ASU and it did not have an
impact on the Company’s consolidated financial
statements.
In May 2014, the Financial Accounting Standards Board (FASB) issued
ASU 2014-09, Revenue from Contracts with Customers, to establish
ASC Topic 606, (ASC 606). ASU 2014-09 supersedes the revenue
recognition requirements in ASC Topic 605, Revenue Recognition and
most industry-specific guidance throughout the Industry Topics of
the Codification. The core principle of the guidance is that an
entity should recognize revenue to depict the transfer of promised
goods or services to customers in an amount that reflects the
consideration to which the entity expects to be entitled in
exchange for those goods or services. The guidance includes a
five-step framework that requires an entity to: (i) identify
the contract(s) with a customer, (ii) identify the performance
obligations in the contract, (iii) determine the transaction
price, (iv) allocate the transaction price to the performance
obligations in the contract, and (v) recognize revenue when
the entity satisfies a performance obligation. In addition,
the standard requires disclosure of the nature, amount, timing, and
uncertainty of revenue and cash flows arising from contracts with
customers.
In August 2015, the FASB issued ASU 2015-14, Deferral of the
Effective Date, which amended the effective date for nonpublic
entities to annual reporting periods beginning after December 15,
2018. In March 2016, the FASB issued an update (ASU
2016-08) to ASC 606, Principal versus Agent Considerations
(Reporting Revenue Gross versus Net), which clarifies the guidance
on principal versus agent considerations. In April 2016, the FASB
issued an update (ASU 2016-10) to ASC 606, Identifying Performance
Obligations and Licensing, which provides clarification related to
identifying performance obligations and licensing implementation
guidance under ASU 2014-09. In May 2016, the FASB issued an update
(ASU 2016-12) to ASC 606, Narrow-Scope Improvements and Practical
Expedients, which amends guidance on transition, collectability,
noncash consideration and the presentation of sales and other
similar taxes. In December 2016, the FASB issued an update (ASU
2016-20) to ASC 606, Technical Corrections and Improvements, which
outlines technical corrections to certain aspects of the new
revenue recognition standard such as provisions for losses on
construction type contracts and disclosure of remaining performance
obligations, among other aspects. The effective date and transition
requirements are the same as those in ASU 2014-09 for all
subsequent clarifying guidance discussed herein.
The guidance permits two methods of adoption: retrospectively to
each prior reporting period presented (full retrospective method),
or retrospectively with the cumulative effect of initially applying
the guidance recognized at the date of initial application
(modified retrospective method). The Company has elected to apply
the modified retrospective method. Accordingly, the new revenue
standard will be applied prospectively in the Company’s
financial statements from January 1, 2019 forward and reported
financial information for historical comparable periods will not be
revised and will continue to be reported under the accounting
standards in effect during those historical periods.
NOTE 3 - GOING CONCERN
The
accompanying financial statements are prepared and presented on a
going concern basis, which contemplates the realization of assets
and the satisfaction of liabilities in the normal course of
business. Accordingly, they do not include any adjustments relating
to the realization of the carrying value of assets or the amounts
and classification of liabilities that might be necessary should
the Company be unable to continue as a going concern. Since
inception to July 31, 2019, the Company has an accumulated deficit
of $2,964,073. The Company intends to fund operations through
equity financing arrangements, which may be insufficient to fund
its capital expenditures, working capital and other cash
requirements for the next twelve months. These factors, among
others, raise substantial doubt about the Company’s ability
to continue as a going concern. The accompanying financial
statements do not include any adjustments that might result from
the outcome of this uncertainty.
NOTE 4 - OIL AND GAS PROPERTIES
Active Projects:
J.E. Richey Lease - Coleman County – Three well
rework/re-completion project
We hold
a 24% working interest in one producing well (“Concho Richey
#1”) on the lease and a 100% working interest in the
remainder of the 206-acre J. E Richey Lease. The Concho Richey #1
well is currently producing 2.8 barrels of oil and 16 MCF of gas
per day.
The
Richey #1 well was plugged on January 3, 2018. As of July 31, 2019, management determined that
the $50,000 asset carried on the balance sheet was impaired
resulting in a loss on impairment of $21,200 lowering the value of
the investment in the Richey lease to $28,800.
Further
work is planned during the next fiscal year on the J. E. Richey
lease on well #3 in an effort to improve its production of oil and
natural gas.
Olson Lease, Jones County, Texas:
We have
a 100% interest in the 160-acre oil and gas Olsen lease located in
the north central part of Jones County, Texas. The principal target
formation is the Palo Pinto Reef. The Palo Pinto Reef is a known
productive formation in the area with a high yield of cumulative
oil production. An example in the area is the Strand Oil Field
which is a Palo Pinto Reef Oil Field. The field discovered in 1940,
consists of only 8 wells on approximately 160 acres produced a
total of 1,700,000 barrels of oil, an average of 212,500 barrels of
oil per oil well. The 160 Olson Lease lies approximately 1.5 miles
southeast of the Strand Palo Pinto Reef Oil Field. We held 100% of
the working interest in this lease until it expiration date of
April 27, 2019. No extension of its existing oil and gas lease was
obtained and therefore the Olson lease expired prior to the
Company's fiscal year ended July 31, 2019. All expenditures on this
property had been expensed prior to its expiration.
89 Guy #4 Well – Cased Well
The 89
Guy Well #4 is located on the Guy Ranch property in Shackelford
County. The well is an abandoned cased well that was drilled in
October 2010 and completed in the Patio Sand at the interval of
3,144’ - 3,154’. This interval produced 2 barrels of
oil and 20 thousand cubic feet of natural gas from a 100 sac gel
frac. The interval perforated (3,144 – 3,154’) is above
the best productive part of the formation. The cased well was
purchased from the mineral owner through an independent geologist
followed by an application to the Texas Railroad Commission to
assume liability of the case well.
Kathis
Energy owns 100% of the working interest with a 75% net revenue
interest in the 20 acre lease with the cased well. On April 16,
2018, Kathis Energy acquired the 89 Guy Well #4 located on a
20-acre tract on the Guy Ranch property in Shackelford County,
Texas. Kathis paid $22,500 for the cased well. A completion attempt
during the fiscal year ended July 31, 2019 to re-complete in the
3,144’-3,154’ interval recovered very nominal oil
production. No further work has been conducted subsequent to July
31, 2019 and is currently being evaluated to place into production
or plug the well and salvage equipment. All expenditures on this
property have been expensed.
McClure 2B – Gas Well – Palo Pinto County,
Texas
On
February 6, 2018 the Company acquired the McClure # 2B producing
gas well on a 40 -acre oil & gas lease located in Palo Pinto
County near the Community of Graford, Texas. The McClure 2B well
was drilled in 2006 to a total depth of 4,739’ and was
re-completed in the Strawn formation in January 2011. The McClure
2B gas well is among a large number of gas wells that are producing
in the area from the Strawn formation.
The
location of the McClure 2B gas well is 1 mile southwest of the
Community of Graford, Texas in Palo Pinto County on a 40 acre
tract. The lease is off a main county road and the lease road can
have washouts depending on the amount of rain as the McClure 2B gas
well is on top of a hill. There are two natural gas lines 1) high
pressure and the 2) is low pressure.
On
December 31, 2018 the Company entered into an agreement with a
third party whereby the Company received $85,900 to rework the
McClure 2B gas well. In consideration for the $85,900 the Company
issued 859,000 shares of its common stock and agreed to convey 100%
of the revenues from the sale of natural gas until the investment
capital was recovered then revert to a 60/40 split in favor of the
third party. On July 31, 2019 the Company entered into an agreement
with the operator of the lease to assume the obligations of the
December 31, 2018 agreement entered into with a third party to
perform certain work in exchange for share of the Company’s
common stock. As a result of this transaction the Company
recognized a $25,250 loss on the property.
Carter & Foster Wells – Producing
During
the fiscal year ended July 31, 2018 the Company acquired the Carter
and Foster wells located west of the Community of Atwell, Texas in
Callahan County. The Carter lease consists of 40 acres and has one
well. The Foster lease has 10 acres around each well of the three
wells, all of which are fully equipped with surface and subsurface
equipment. All four wells are completed in the Palo Pinto Limestone
formation at approximately 1,900 feet.
The
wells on the Carter and Foster leases were drilled in 1992-93. Most
of the wells were treated with 5,000 gallons of 21% acid and
yielded initial rates of production of 40 barrels of oil per day
then gradually declined to 3 barrels per day by the end of the
first year. The wells now are 25 plus years old and are producing
90% or better oil cut in the fluid being produced. The production
is very nominal at the present time however no secondary acid
stimulation has been conducted since they were originally brought
into production in the early 1990’s. All four wells on the
Carter and Foster leases are fully equipped and have their own
production facilities and have electricity to each of the wells. On
December 30, 2018 the Company entered into an agreement with a
third party whereby the Company received $60,000 to rework the
Carter and Foster wells. In consideration for the $60,000 the
Company issued 600,000 shares of its common stock and agreed to
convey 100% of the revenues from the sale of crude oil sales until
the investment capital was recovered then revert to a 60/40 split
in favor of the third party. On July 31, 2019 the Company entered
into an agreement with the operator of the lease to assume the
obligations of the agreement entered into with a third party to
perform certain work in exchange for shares of the Company’s
common stock.
NOTE 5 – MINERAL RIGHTS AND PROPERTIES
ENMEX Operations LLC – Wholly owned Subsidiary - Pemer
Bacalar – Resort Development Project
On
September 22, 2017 the Company entered into a Letter of Intent
regarding the Bacalar Project in Mexico. This was followed up with
a Memorandum of Understanding on November 16, 2017. The Company has
a very strong desire to be a part of this large development in any
manner that is possible. On March 13, 2018 a payment of $20,266 was
paid toward the architectural drawings prepared by Callikson. On
April 13, 2019 a MOU was updated. On June 11, 2019 a new agreement
was entered into regarding this property. No additional funds have
been provided to this project since the signing of the MOU on June
11, 2019.
As of
July 31, 2019, the total investment made by the Company toward this
project is $20,266. The Company still has a very strong desire to
continue to pursue to be a part of this large opportunity. As of
July 31, 2019, it is not clear as to what level the Company will be
participating as it is not clearly defined by Pemer Bacalar what is
required. Pemer Bacalar has several requirements on their side of
the June 11, 2019 agreement to accomplish including but not limited
to finalizing the acquisition of additional acreage and obtaining
permits as well as formalize a plan to conduct feasibility studies
etc.
No
demands have been made for funds by Pemer Bacalar since the date of
signing the June 11, 2019 agreement. At this time the Company is
waiting to hear from Pemer Bacalar of what the next step will be
and then it will determine our obligations thereto.
NOTE 6 – WINNEMUCCA MOUNTAIN PROPERTY
As
previously announced, on September 14, 2012, we entered into an
option agreement (as last amended on February 11, 2016) with AHL
Holdings Ltd., and Golden Sands Exploration Inc., wherein we
acquired an option to purchase an 80% interest in and to certain
mining claims, which claims form the Winnemucca Mountain Property
in Humboldt County, Nevada (“Property”). This
Winnemucca Mountain property currently is comprised of 138
unpatented mining claims covering approximately 2,700
acres.
On July
23, 2018, the Company entered into a New Option Agreement with AHL
Holding Ltd & Golden Sands Exploration Inc.
(“Optionors”). This agreement provided for the payment
of $25,000 and the issuance of 3,000,000 shares of the
Company’s common stock and work commitments. The Company
issued the shares and made the initial payment of $25,000 per the
terms of the July 31, 2018 agreement. The second payment of $25,000
per the terms of the agreement was not paid when it became due on
August 31, 2018 causing the Company to default on the terms of the
July 23, 2018 agreement.
On
March 25, 2019 the Company entered into a New Option Agreement with
the Optionors. As stated in the New Option Agreement the Company
has agreed to certain terms and conditions to have the right to
earn an 80% interest in the Property, these terms include cash
payments, issuance of common shares of the Company and work
commitments.
The Company’s firm commitments per the March 25, 2019 option
agreement totaling $381,770 of which cash
payments total
$181,770 and a firm work commitment of $200,000. These cash
payments include payments for rentals payable to BLM and also for
the staking of new claims adjoining the existing claims. The work
commitment is to be conducted prior to December 31, 2020. The
Company has accounted for the $381,770 in its accrued liabilities
(Note 6).
NOTE 7 - ACCRUED LIABILITIES
The
Company has partnered with others whereby they provide all or a
portion of the working capital for either well work to be completed
on existing properties or towards the acquisition of new
properties. As of July 31, 2019 and 2018, the Company has unused
funds it has received of $65,879 and $170,518,
respectively.
Accrued
liabilities as of July 31:
|
|
|
|
|
General
accrual
|
$1,887
|
$1,715
|
|
Interest
|
$47,802
|
$38,002
|
|
Distributions and
royalty
|
$15,416
|
$22,345
|
|
Advances for well
work
|
$65,879
|
$170,518
|
|
Winnemucca
Property
|
$381,770
|
$-
|
|
Investment funds to
be used for the development of future properties
|
$125,000
|
$95,000
|
|
|
$637,754
|
$327,580
|
NOTE 8 - CONVERTIBLE DEBT
On
August 22, 2013 the Company entered into a $50,000 Convertible Loan
Agreement with an un-related party. The Loan and interest are
convertible into Units at $0.08 per Unit with each Unit consisting
of one common share of the Company and ½ warrant with each
full warrant exercisable for one year to purchase one common share
at $0.30 per share. On July 10, 2014, a further $35,000 was
received from the same unrelated party under the same terms. On
July 31, 2018, this Note was amended whereby the principal and
interest are now convertible into Units at $0.04 per Unit with each
Unit consisting of one common share of the Company and ½
warrant with each full warrant exercisable for one year to purchase
one common share at $0.08 per share. The Loan shall bear interest
at the rate of Eight Percent (8%) per annum and matures on March
26, 2020. As of July 31, 2019, there is $85,000 and $43,182 of
principal and accrued interest, respectively, due on this loan. As
of July 31, 2018, there was $85,000 and $36,382 of principal and
accrued interest, respectively, due on this loan. This note is
currently in default.
On
October 20, 2017, the Company executed a convertible promissory
note for $25,000 with a third party. The note accrues interest at
6%, matures in two years and is convertible into shares of common
stock at maturity, at a minimum of $0.10 per share, at the option
of the holder. As of July 31, 2019 and 2018, there is $2,367 and
$1,245, respectively, of accrued interest due on this loan. This
note is currently in default.
NOTE 9 – LOANS PAYABLE
On
April 16, 2017, the Company executed a promissory note for $15,000
with a third party. The note matures in two years and interest is
set at $3,000 for the full two years. As of July 31, 2019, there is
$15,000 and $1,875 of principal and accrued interest, respectively,
due on this loan. This loan is currently in default.
As of
July 31, 2019, the Company owed $5,000 to a third party. The loan
is unsecured, non-interest bearing and due on demand.
During
the year ended July 31, 2019, the Company extinguished $99,740 of
aged debt for which collection would be statute barred and as such
are eligible to be written off. The $99,740 was recognized as a
gain on the settlement of debt.
NOTE 10 - COMMON STOCK
During the year ended July 31, 2018, the Company sold 16,559,000
shares of common stock for total cash proceeds of $219,475; $20,000
of which had not yet been received as of July 31, 2018. The $20,000
was received in the quarter ended October 31, 2018. In addition,
1,000,000 shares of those sold were not issued as of July 31, 2018
and were therefore been credited to common stock to be issued. The
1,000,000 shares were issued in February
2019.
During the year ended July 31, 2018, the Company sold 2,730,000
Units of its common stock for total cash proceeds of $136,500. Each
Unit consists of one common share and one-half share purchase
warrant exercisable for 1 years. Each whole share purchase warrant
has an exercise price of $0.15 per common share.
During the year ended July 31, 2018, the Company issued 200,000
shares of common stock for conversion of a $4,000 loan payable. The
shares were valued at $0.05, the closing stock price on the date of
conversion for a loss on conversion of $6,000.
During the year ended July 31, 2018, the Company issued 3,000,000
shares of common stock for services. The shares were valued at
$0.061, the closing stock price on the date of grant for total
non-cash expense of $183.000.
During the year ended July 31, 2019, the Company issued 150,000
shares of common stock to two individuals as consideration for
their support with the Richey #2A project. The shares were valued
at $0.065 per share, the closing price on the date of grant, for
total non-cash expense of $9,750. As of July 31, 2019, 75,000
shares have not yet been issued by the transfer agent; therefore.
$3,825 has been credited to common stock to be issued. The shares
were issued on August 16, 2019.
During the year ended July 31, 2019, the Company sold 1,000,000
Units of its common stock for total cash proceeds of $50,000. Each
Unit consists of one common share and one-half share purchase
warrant exercisable for 2 years. Each whole share purchase warrant
has an exercise price of $0.15 per common share. The Company
determined the fair value of the warrants to be $25,205 using the Black
Scholes pricing model. The 1,000,000 shares were issued in February
2019.
During the year ended July 31, 2019, the Company sold 6,400,001
shares of common stock for total cash proceeds of
$220,000.
On July 31, 2019, the Company entered into an agreement with
J.V. Rhyne whereby advance for work to
be conducted on several wells in the net amount of $61,850 were
transferred to J.V. Rhyne for consideration of 1,000,000 shares of
common stock. The shares were valued at $0.041, the closing stock
price on the date of the agreement, for total value of $41,100. The
transaction resulted in a gain on the write off of debt of $20,750.
As of July 31, 2019, the shares have not yet been issued by the
transfer agent and have been credited to common stock to be
issued.
NOTE 11 - WARRANTS
Warrants have been issued in conjunction with common stock
issuances. During the year ended July 31, 2018, the Company sold
3,730,000 Units, which included 3,730,000 shares of common stock
and 1,865,000 warrants, for total cash proceeds of $136,500. During
the year ended July 31, 2019, the Company sold 1,000,000 Units for
total cash proceeds of $50,000. Each Unit consists of one common
share and one-half share purchase warrant exercisable for 2 years.
Each whole share purchase warrant has an exercise price of $0.15
per common share. The warrants were evaluated for purposes of
classification between liability and equity. The warrants do not
contain features that would require a liability classification and
are therefore considered equity. The Black Scholes pricing model
was used to estimate the fair value of the Warrants issued with the
following inputs:
|
Warrants
|
500,000
|
|
|
3,730,000
|
|
|
Exercise
Price
|
$
|
0.15
|
|
$
|
0.15
|
|
|
Term
|
|
2
years
|
|
|
1-2
years
|
|
|
Volatility
|
|
323%
|
|
|
275.95%
- 361.50%
|
|
|
Risk
Free Interest Rate
|
|
2.61%
|
|
|
1.67% -
2.67%
|
|
|
Fair
Value
|
$
|
25,205
|
|
$
|
70,858
|
|
Using
the fair value calculation, the relative fair value for the years
ended July 31, 2019 and 2018, between the common stock and the
warrants was calculated to determine the warrants recorded equity
amount of $25,205 and $70,858, respectively, which has been
accounted for in additional paid in capital.
Activity
for the year ended July 31, 2019 and 2018 is as
follows:
|
|
|
Weighted Average
Exercise Price
|
Weighted Average
Remaining Contract Term
|
|
Outstanding at July
31, 2017
|
150,000
|
$0.10
|
1.50
|
|
Granted
|
1,865,000
|
0.15
|
1.47
|
|
Expired
|
-
|
-
|
-
|
|
Exercised
|
-
|
-
|
-
|
|
Exercisable at July
31, 2018
|
2,015,000
|
$0.15
|
1.47
|
|
Granted
|
500,000
|
0.15
|
1.28
|
|
Expired
|
(150,000)
|
0.15
|
-
|
|
Exercised
|
-
|
-
|
-
|
|
Exercisable at July
31, 2019
|
2,365,000
|
$0.15
|
.65
|
NOTE 12 - RELATED PARTY TRANSACTIONS
For the years ended July 31, 2019 and 2018, total payments of
$8,500 and $56,500, respectively, were made to Ivan Webb, CEO for
consulting services. As of July 31, 2019, there is $22,500 credited
to accounts payable.
For the years ended July 31, 2019 and 2018, total payments of
$52,500 and $26,500, respectively, were made to Noel Schaefer, a
Director of the Company, for consulting services. As of July 31,
2019, there is $27,500 credited to accounts payable.
For the years ended July 31,
2019 and 2018, total payments of $0 and $4,000, respectively were
made to Howard Siegel, a Director of the Company, for consulting
services
On July 31, 2018, the wife of the CEO, loaned the Company $25,000
for general operating expenses. This loan was repaid on August 2,
2018 with an additional $5,000 for interest and a loan fee. On
August 3, 2018, Mrs. Webb loaned the Company $30,000 which was
repaid on August 21, 2018. On September 25, 2018, the Company
executed a loan agreement with Mrs. Webb for $6,800. The loan is to
be repaid by December 15, 2018, with an additional $680 to cover
interest and fees. On October 10, 2018, the Company executed a loan
agreement with Mrs. Webb for $15,000. The loan was to be repaid by
December 15, 2018, with an additional $1,500 to cover interest and
fees. As of July 31, 2019, the Company owes Mrs. Webb $20,930 and
$2,180 of principal and interest, respectively. Amounts due on
these loans are currently in default.
During
the fiscal year ended July 31, 2018 the Company acquired from Ivan
Webb, CEO of the Company, the oil and gas rights to two oil and gas
leases located in Callahan County, Texas known as the Carter and
Foster leases for total consideration of $1.00.
On July 31, 2019, Ivan Webb, CEO, agreed to assume a $15,000
liability due to Renaissance Oil & Gas Inc. that had been paid
for the reworking of the S O Curry #1 well. The assumption of the
liability was credited to additional paid in capital.
Victor Miranda, the former Chief Financial Officer and Director of
the Company is also President and owner of Labrador Capital SAPI DE
CV (“Labrador”), a major shareholder of the Company
owning 8.8% of its issued and outstanding shares. The Company has
entered into a Memorandum of Understanding with Labrador to jointly
pursue developing real estate projects in Mexico. As of the
date of this report no projects have been identified to jointly
pursue. In the event of a decision to go forward with
Labrador, Victor Miranda will abstain from voting to avoid any
conflict of interest.
NOTE 13 - INCOME TAX
Deferred
taxes are provided on a liability method whereby deferred tax
assets are recognized for deductible temporary differences and
operating loss and tax credit carry forwards and deferred tax
liabilities are recognized for taxable temporary differences.
Temporary differences are the differences between the reported
amounts of assets and liabilities and their tax bases. Deferred tax
assets are reduced by a valuation allowance when, in the opinion of
management, it is more likely than not that some portion or all of
the deferred tax assets will not be realized. Deferred tax assets
and liabilities are adjusted for the effects of changes in tax laws
and rates on the date of enactment. The U.S. federal income tax
rate of 21% is being used for 2017 due to the new tax law recently
enacted.
The
provision for Federal income tax consists of the following July
31:
|
|
|
|
|
Federal income tax
benefit attributable to:
|
|
|
|
Current
Operations
|
$261,400
|
$162,000
|
|
Less: valuation
allowance
|
(261,400)
|
(162,000)
|
|
Net provision for
Federal income taxes
|
$-
|
$-
|
The
cumulative tax effect at the expected rate of 21% of significant
items comprising our net deferred tax amount is as
follows:
|
|
|
|
|
Deferred tax asset
attributable to:
|
|
|
|
Net operating loss
carryover
|
$955,000
|
$502,000
|
|
Less: valuation
allowance
|
(955,000)
|
(502,000)
|
|
Net deferred tax
asset
|
$-
|
$-
|
At July
31, 2019, the Company had net operating loss carry forwards of
approximately $966,000 that maybe offset against future taxable
income. No tax benefit has been reported in the July 31,
2019 or 2018 financial statements since the potential tax benefit
is offset by a valuation allowance of the same
amount.
On
December 22, 2017, the U.S. government enacted comprehensive tax
legislation commonly referred to as the Tax Cut and Jobs Act (the
“Tax Act”). The Tax Act establishes new tax laws that
affects 2018 and future years, including a reduction in the U.S.
federal corporate income tax rate to 21% effective January 1, 2018.
For certain deferred tax assets and deferred tax
liabilities.
Due to
the change in ownership provisions of the Tax Reform Act of 1986,
net operating loss carry forwards for Federal income tax reporting
purposes are subject to annual limitations. Should a change in
ownership occur, net operating loss carry forwards may be limited
as to use in future years.
ASC
Topic 740 provides guidance on the accounting for uncertainty in
income taxes recognized in a company’s financial statements.
Topic 740 requires a company to determine whether it is more likely
than not that a tax position will be sustained upon examination
based upon the technical merits of the position. If the
more-likely-than-not threshold is met, a company must measure the
tax position to determine the amount to recognize in the financial
statements.
The
Company includes interest and penalties arising from the
underpayment of income taxes in the statements of operations in the
provision for income taxes. As of July 31, 2019, the Company had no
accrued interest or penalties related to uncertain tax
positions.
NOTE 14 – COMMITMENTS AND CONTINGENCIES
The Company has been named as a third-party in pending litigation
for which the Company denies any wrongdoing. The Company entered
into a joint venture agreement with an accredited unrelated party
where funds were invested in two of the Company’s projects.
The unrelated party is a knowledgeable oil and gas investor and has
experience with investing in oil and gas projects. The Company is
named as a third party to the legal action solely due to its
association with the unrelated party and the funds he used for
making the investment with the Company. On April 27, 2020, a Motion
to Dismiss was filed in the District Court of Dallas, Texas
dismissing all claims.
NOTE 15 - SUBSEQUENT EVENTS
Management
has evaluated subsequent events pursuant to the requirements of ASC
Topic 855, from the balance sheet date through the date the
financial statements were available to be issued, and has
determined that no material subsequent events exist other than the
following.
Subsequent
to July 31, 2019, the Company sold 666,600 shares of common stock
for total proceeds of $20,000.
Subsequent
to July 31, 2019, the Company issued 75,000 common shares that were
previously classified as stock to be issued.
On January 30, 2020, the World Health Organization declared the
coronavirus outbreak a "Public Health Emergency of International
Concern" and on March 10, 2020, declared it to be a pandemic.
Actions taken around the world to help mitigate the spread of the
coronavirus include restrictions on travel, and quarantines in
certain areas, and forced closures for certain types of public
places and businesses. The coronavirus and actions taken to
mitigate it have had and are expected to continue to have an
adverse impact on the economies and financial markets of many
countries, including the geographical area in which the Company
plan to operates. While it is unknown how long these conditions
will last and what the complete financial effect will be to the
company, to date, the Company has experienced a decline in revenue
due to the decreasing price of oil.
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES
On February 7, 2020, the Company dismissed Fruci & Associates
II, PLLC as the Company’s independent registered public
accounting firm. During the fiscal years ended July 31, 2018 and
2017, there have been no disagreements with Fruci & Associates
II, PLLC on any matter of accounting principles or practices,
financial statement disclosure or auditing scope
or procedure, which disagreements if not resolved to the
satisfaction of Fruci & Associates II, PLLC would have caused
them to make reference thereto in connection with their report on
the financial statements for such years. However, from fiscal year
ended July 31, 2018 and through February 7, 2020, there has been a
disagreement with Fruci & Associates II, PLLC on auditing scope
or procedure, which disagreements if not resolved to the
satisfaction of Fruci & Associates II, PLLC we believe would
prevent the issuance of their report for the fiscal years ended
July 31, 2019.
On February 7, 2020 the Company engaged Haynie & Company as its
new independent registered public accounting firm. During the
most recent fiscal years and through February 7, 2020, the Company
had not consulted with Haynie & Company regarding any of
the following:
ITEM 9A. CONTROLS AND
PROCEDURES
Management’s Report Disclosure Controls and
Procedures
We carried out an evaluation, under the supervision and with the
participation of our management, including our principal executive
officer and principal financial officer, of the effectiveness of
our disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)). Based upon that
evaluation, our principal executive officer and principal financial
officer concluded that, as of the end of the period covered in this
report, our disclosure controls and procedures were ineffective to
ensure that information required to be disclosed in reports filed
under the Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the required time periods
specified in the Commission’s rules and forms and is
accumulated and communicated to our management, including our
principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding required
disclosure.
Our principal executive officer and principal financial officer, do
not expect that our disclosure controls and procedures or our
internal controls will prevent all error or 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. Due to 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, have been detected. During the fourth quarter
of the fiscal year ended July 31, 2019, we carried out an
evaluation, under the supervision and with the participation of our
principal executive officer and principal financial officer, of the
effectiveness of the design and operation of our disclosure
controls and procedures. Based on that evaluation and due to
the identified material weaknesses discussed below, our principal
executive officer and principal financial officer concluded that
our disclosure controls and procedures were ineffective as of the
end of the period covered by this report.
To address the material weaknesses, we performed additional
analysis and other post-closing procedures in an effort to ensure
our financial statements included in this annual report have been
prepared in accordance with generally accepted accounting
principles. Accordingly, management believes that the
financial statements included in this report fairly present in all
material respects our financial condition, results of operations
and cash flows for the periods presented.
Management’s Report on Internal Control over Financial
Reporting
Internal control over financial reporting (as defined in Rules
13a-15(f) and 15d-15(f) under the Exchange Act) is a process
designed by, or under the supervision of, our principal executive
and principal financial officers, and effected by our board of
directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. The
management is responsible for establishing and maintaining adequate
internal control over our financial reporting. Under the
supervision and with the participation of our management, including
our principal executive officer and principal financial officer, we
conducted an evaluation of the effectiveness of our internal
control over financial reporting using the Internal Control –
Integrated Framework (2013) developed by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation,
our Chief Executive Officer and Chief Financial Officer have
concluded that our internal control over financial reporting was
not effective as of July 31, 2019.
We are aware of the following material weaknesses in internal
control that could adversely affect the Company’s ability to
record, process, summarize and report financial data:
|
|
●
|
Due to our size and limited resources, we currently do not employ
the appropriate accounting personnel to ensure (a) we maintain
proper segregation of duties, (b) that all transactions are entered
timely and accurately, and (c) we properly account for complex or
unusual transactions
|
|
|
●
|
Due to our size and limited resources, we have not properly
documented a complete assessment of the effectiveness of the design
and operation of our internal control over financial
reporting.
|
Inherent limitations on
effectiveness of controls
Internal control over financial reporting has inherent limitations,
which include but is not limited to the use of independent
professionals for advice and guidance, interpretation of existing
and/or changing rules and principles, segregation of management
duties, scale of organization, and personnel factors. Internal
control over financial reporting is a process, which involves human
diligence and compliance and is subject to lapses in judgment and
breakdowns resulting from human failures. Internal control over
financial reporting also can be circumvented by collusion or
improper management override. Because of its inherent limitations,
internal control over financial reporting may not prevent or detect
misstatements on a timely basis, however these inherent limitations
are known features of the financial reporting process and it is
possible to design into the process safeguards to reduce, though
not eliminate, this risk. Therefore, even those systems determined
to be effective can provide only reasonable assurance with respect
to financial statement preparation and presentation. 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 of compliance with the policies or
procedures may deteriorate.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal controls over financial
reporting that occurred during the fourth quarter of the fiscal
year ended July 31, 2019, that have materially or are reasonably
likely to materially affect, our internal controls over financial
reporting.
ITEM 9B. OTHER INFORMATION
None