The following discussion should be read in conjunction with our audited financial statements and notes thereto date July 31, 2019. In connection with, and because we desire to take advantage of, the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we caution readers regarding certain forward-looking statements in the following discussion and elsewhere in this report and in any other statement made by us, or on our behalf, whether or not in future filings with the Securities and Exchange Commission. Forward-looking statements are statements not based on historical information and which relate to future operations, strategies, financial results or other developments. Forward-looking statements are necessarily based upon estimates and assumptions that are inherently subject to significant business economic and competitive uncertainties and contingencies, many of which are beyond our control and many of which, with respect to future business decisions, are subject to change. These uncertainties and contingencies can affect actual results and could cause actual results to differ materially from those expressed in any forward-looking statements made by us, or on our behalf. We disclaim any obligation to update forward-looking statements.

The independent registered public accounting firm’s report on the Company’s financial statements as of July 31, 2019, and for each of the fiscal years in the two-year period then ended, includes a “going concern” explanatory paragraph that describes substantial doubt about the Company’s ability to continue as a going concern.

Safe Harbor Provision

This Management’s Discussion and Analysis includes a number of forward-looking statements that reflect our current views with respect to future events and financial performance. Forward-looking statements are often identified by words like: “believe,” “expect,” “plan,” “estimate,” “anticipate,” “intend,” “project,” “will,” “predicts,” “seeks,” “may,” “would,” “could,” “potential,” “continue,” “ongoing,” “should,” and similar expressions, or words which, by their nature, refer to future events. You should not place undue certainty on these forward-looking statements, which apply only as of the date of this Form 10-Q. These forward-looking statements are subject to certain risks or uncertainties that could cause actual results to differ materially from historical results or from our predictions. We undertake no obligation to update or revise publicly any forward-looking statements, whether because of new information, future events, or otherwise.

Overview

We are in the business of exploration, development, and production of oil and gas in the Permian Basin of West Texas, in southeastern New Mexico, and in Mississippi. The Permian Basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators. The Permian Basin is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates. As of January 31, 2020, the Company has leasehold rights located within approximately 70,000 acres in Pecos County, Texas, 5,385 gross acres (4,682 net acres) in Lea County, New Mexico and approximately 900 acres in Walthall County, Mississippi. We believe that our concentrated acreage positions provides us with an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. Historically, our activities have been primarily focused on vertical development of the Queen formation over the Central Basin platform, which separates the Midland Basin from the Delaware Basin, all of which are part of the Permian Basin in West Texas. Recently, however, the Company has had several successful completions in the deeper San Andres zone of its Pecos County, Texas and Lea County, New Mexico properties. Future drilling targets could include the Grayburg, Clear Fork, Glorietta, and Devonian zones in Pecos County, Texas and the Devonian, Pennsylvanian and Wolfcamp/Wolfbone zones in Lea County, New Mexico and Lower Tuscaloosa Stinger B,C, and D Sands, Yequa, Cook Mountain, and Sparta pay zones.

The properties acquired in Mississippi include eleven production capable wells and three salt water disposal wells. The Company intends to begin a program of workover and recompletion in 2020. Existing wellbores, field infrastructure, and saltwater disposal well reduces cost and time. To date the primary saltwater well has been reworked with a successful Mechanical Integrity Test approved by the Mississippi Oil and Gas Board. The well in now in operation. The first well on the schedule to be reworked is the Doster A-1 Well. Operations are now underway in the 11,000-foot-deep formation called the Lower Tuscaloosa Stringer pay sand

Our near-term success depends primarily on attracting developmental capital to continue to drill, develop reserves and increase production within the leased acreage that we currently control. We are also open to acquiring oil and gas producing properties that would add value to our shareholders. We are the operator of 100% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of our prospects. The Company owns a small drilling rig (2,500’), completion rig, pulling unit and various equipment to operate the property.

We have been operating at a net loss situation. Given the current oil prices, and the inherent expenses of running a public company in the oil and gas industry, it is uncertain if and when we may achieve profitable operations as a small company.

Commodity Prices.

Our results of operations are heavily influenced by commodity prices. Factors that may impact future commodity prices, including the price of oil and natural gas, include: (1) weather conditions in the United States and where the Company’s property interests are located; (2) economic conditions, including demand for petroleum-based products, in the United States and the rest of the world; (3) actions by OPEC, the Organization of Petroleum Exporting Countries; (4) political instability in the Middle East and other major oil and natural gas producing regions; (5) governmental regulations; (6) domestic tax policy; (7) the price of foreign imports of oil and natural gas; (8) the cost of exploring for, producing and delivering oil and natural gas; (9) the discovery rate of new oil and natural gas reserves; (9) the rate of decline of existing and new oil and natural gas reserves; (10) available pipeline and other oil and natural gas transportation capacity; (11) the ability of oil and natural gas companies to raise capital; (12) the overall supply and demand for oil and natural gas; and (13) the availability of alternate fuel sources.

The Company cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. Furthermore, the Company has not entered into any derivative contracts, including swap agreements for oil and gas.

Fiscal Year 2019 Activity

During the fiscal year ended July 31, 2019, the Company continued to raise funds to drill oil and gas wells located within the approximately 70,000 acres, in Pecos County, Texas and the approximate 5,385 acres in Lea County, New Mexico, where our leasehold rights currently exist. Our fund raising activities were primarily through joint venture working interest holder participations, whereby the Company retained a carried working interest. In order to keep the leasehold in good standing, we adhered to the Continuous Drilling Clause for each respective lease and strictly adhered to the requirements within said Drilling Clauses.

Additionally, the WWJD #30 well was drilled to a total depth of 1,768 feet and Amazing encountered approximately fourteen feet of pay zone thickness based on comparison to a southern offset well. The Company completed the well utilizing a technique known as an “open hole completion”. Once the well quit flowing on its own, a pump jack system was installed to restart oil production. The well is currently producing an average of 5-7 BOPD.

On October 17, 2018 the Company closed on the acquisition of the deep rights in 26,000 mostly contiguous acres in the Permian Basin in Pecos County, Texas. Post-closing the Company now controls all rights to all depths within the 61,000 acres with undivided mineral interest and rights to the depth of 3,000 feet to surface on its additional ~9,000 acres. The purchased acreage is subject to the same option terms that are applicable to the other Pecos County, Texas acreage controlled by the Company. Jilpetco, Inc. will be the operator of record on all current and future wells, if any, on the acquired acreage. The cost of the acquisition was $500,000.

During the fiscal quarter ended October 31, 2019, the Company drilled and completed the Wilson 498 well and recompleted the Wilson 49-2 well on the Pecos County, Texas leasehold that was acquired in the transaction with Wyatt Energy, LLC. Management is still in the process of evaluating the results of both wells as the just entered the initial production stage. At January 31, 2020, the Company has a 100% working interest in twenty-seven (27) wells and a 37% working interest in the WWJD #31-H well located in the Pecos County, Texas leasehold premises. The Company has drilled 27 wells throughout the property, and recompleted one well that was drilled by a previous operator. Twenty-six of the wells either current producers or subjects of a scheduled workover/recompletion plan. Two wells are currently shut-in and will probably be converted to injection wells associated with a future water-flood plan. The level of capital expenditures for the remainder of the fiscal year will significantly depend on the future market prices for oil and the Company’s ability to source the necessary capital to fund the drilling of any wells in the future.

Fiscal Year 2020 Activity

At January 31, 2020, the Company has seven producing wells and three saltwater disposal wells in the Lea County project. A location has been selected and a drilling pad has been built for the Curly Well.

Amazing will leverage the extensive geological work done on the Pecos County, Texas acreage to select new well drilling locations. Identified and prolific pay zone horizons proven on the acreage include the Queen, Grayburg, Clear- Fork, Wolfcamp, Pennsylvanian, Devonian and Ellenberger. Modern 3-D seismic covers most of the leasehold, where 17 deep exploratory wells were drilled in the early 2000’s targeting Devonian and Ellenberger pay at depths of 8,000-9,000 foot Measured Depth. The Seismic data set primarily targeted Devonian wells which have produced 4 BCFG and 150,000 barrels of oil in the area. Additionally, the data has identified prospects that have yet to be drilled on the acreage and a recent new field discovery by an offset operator in 2017 which will provide additional detailed geological insight as to rock properties, reserves, and production potentials. Amazing plans to shoot a larger 3-D survey which has the potential to uncover additional new target areas from the deeper horizons.

On November 22, 2019 Amazing Energy MS, LLC (“AMS”) a newly formed, wholly-owned subsidiary of the Company closed on the acquisition of assets consisting of certain oil and gas leases encompassing approximately 900 acres, nine oil wells and a saltwater disposal well, all located in Mississippi and generally known as the “Denver Mint Project.” The company plans to restore and enhance production with multiple workovers identified in proven Lower Tuscaloosa pay zones as well as expand production into shallow regional pay zones. Shallow Yegua, Cook Mountain, and Sparta pay zones above 3,300 ft. are regional pay zones that have not been produced in Dinan Field to date. Existing well bores, field infrastructure, and saltwater disposal well reduces cost and time.

In the past Amazing has focused on shallower plays available under our existing options to incrementally increase production. Our strategy is getting a tremendous boost with the addition of these deep rights and associated well-known pay zones. We expect this acquisition to add several hundred potential new well locations to our current drilling inventory. The potential of our acreage is now on par with many of our much larger peers and in the same well-known plays where they are experiencing marked success.

The Company’s Expansion Strategy for 2020 includes the following subject to economic and liquidity conditions:

Overview of Current Operations

Through January 31, 2020, the Company has drilled twenty-seven wells and recompleted one well on its leasehold in Pecos County, Texas. Twenty-six of the twenty-eight wells are either currently producing or awaiting workover/recompletion and two wells are currently shut in. The wells have not been commercially productive. As a result of the recent Lea County, New Mexico acquisition, the Company has seven wells that are currently producing oil and gas. The Company also acquired three salt-water disposal wells in the Lea County, New Mexico asset acquisition transaction. In August, 2019, the Company began disposing salt-water in one of its Lea County, New Mexico salt-water disposal wells for another unrelated local operator. The Company will be paid an amount each month based on the total number of barrels of salt-water disposed.

The newly acquired Mississippi properties are being reviewed to develop plans to restore and enhance production with multiple workovers identified in proven Lower Tuscaloosa pay zones as well as expand production into shallow regional pay zones. Shallow Yegua, Cook Mountain, and Sparta pay zones above 3,300 ft. are regional pay zones that have not been produced in Dinan Field. Existing wellbores, field infrastructure, and saltwater disposal well reduces cost and time. To date the primary saltwater well has been reworked with a successful Mechanical Integrity Test approved by the Mississippi Oil and Gas Board. The well in now in operation. The first well on the schedule to be reworked is the Doster A-1 Well. Operations are now underway in the 11,000-foot-deep formation called the Lower Tuscaloosa Stringer pay sand.

Compliance with Government Regulations

The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Department of Interior, the U.S. Department of Transportation Office of Pipeline Safety (the “DOT”) and the U.S. Environmental Protection Agency (the “EPA”). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. For the state of Texas, the regulatory agency is the Texas Railroad Commission. These federal, state and local authorities have various permitting, licensing and bonding requirements. Various remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, suspension of production, and, in certain cases, criminal prosecution. As a result, there can be no assurance that we will not incur liability for fines, penalties or other remedies that are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with federal, state and local rules, regulations and procedures, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.

Transportation and Sale of Oil

Historically, the Company’s oil and gas revenues originated from production from its properties in Texas. Beginning February 1, 2019, the Company will also begin generating oil and gas from its newly acquired properties in New Mexico. Each revenue stream is sold to a single customer through month to month contracts. While this creates a customer concentration, there are alternate buyers of the production in event the sole customer is unable or unwilling to purchase.

During the six months ended January 31, 2020, the Company sold its oil and gas production to only four customers. Oil production was sold to Rio Energy International, Inc. (Pecos County, Texas) and to Plains Marketing L.P. (Lea County, New Mexico), and natural gas production was sold to Trans-Pecos Natural Gas Company, LLC (Pecos County, Texas) and Targa Resources (Lea County, New Mexico). During the six months ended January 31, 2019, oil and gas production in Pecos County, Texas was sold to Sunoco, LP and Trans-Pecos Natural Gas Company, LLC, respectively.

Regulation of Production

Oil and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we operate, Texas and New Mexico, have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells. Also, Texas and New Mexico impose a severance tax on production and sales of oil, and gas within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Matters and Regulation

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive and other protected areas; require action to prevent or remediate pollution (from current or former operations), such as plugging abandoned wells or closing pits; take action resulting in the suspension or revocation of necessary permits, licenses and authorizations; and/or require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all the provisions of the Resource Conservation and Recovery Act, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservation and Recovery Act, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste by March, 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. During our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Non-compliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new greenhouse gas emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the U.S. Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely because of their greenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.

Additionally, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S., including natural gas liquids fractionators and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded the greenhouse gas reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the greenhouse gas reporting rule to add the reporting of greenhouse gas emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

The EPA has continued to adopt greenhouse gas regulations applicable to other industries, such as its August 2015 adoption of three separate, but related, actions to address carbon dioxide pollution from power plants, including final Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen states as well as industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. Because of this continued regulatory focus, future greenhouse gas regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France (the “Paris Accords”). The Paris Accords call for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. On June 1, 2017, President Trump announced the United States would withdraw from the Paris Accords. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. Also, on June 29, 2016, the leaders of the United States, Canada and Mexico announced an Action Plan to, among other things, boost clean energy, improve energy efficiency, and reduce greenhouse gas emissions. The Action Plan specifically calls for a reduction in methane emissions from the oil and gas sector by 40% to 45% by 2025.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely affect the oil and natural gas industry. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

In addition, the EPA plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program in Indian country for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and gas sources. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flow-back fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. Similar types of legislation are under consideration in New Mexico and Mississippi where the Company has existing oil and gas operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as 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, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. Currently, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

the locations of wells;
the method of drilling and casing wells;
the timing of constructions or drilling activities, including seasonal wildlife closures;
the rates of productions or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third-parties

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open-access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

State Regulation. Texas, Mississippi and New Mexico regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production, while New Mexico currently imposes a 3.75% severance tax on oil and gas production as well as an additional emergency school tax (3.15%), a conservation tax (1.9%) and a production ad-valorem tax (2.2886%). Mississippi has similar severance tax structures that will apply to the Company’s future production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Office and Other Facilities

The Company leases its corporate headquarters in Plano, Texas. Reference detail in Note 10 of the Consolidated Financial Statements regarding Lease Commitments.

Employees

As of January 31, 2020, the Company had five full-time employees. We regularly use independent contractors and consultants to perform various field-level tasks as well as other required services. None of our employees are represented by a labor union or covered by any collective bargaining agreement.

Research and Development Expenditures

None.

Reports to Security Holders

We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other documents with the SEC under the Exchange Act. The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including the Company, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov.

PLAN OF OPERATION

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties. When we determine that we will conduct drilling operations on any properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Oil and Gas Leases

The typical oil and natural gas lease agreement covering our acreage positions in Pecos County, Texas, Lea County, New Mexico, and Mississippi provide for the payment of royalties to the mineral owners for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to the working interest owners generally ranging from 75% to 80%.

Oil and Gas Production and Revenue

Production Costs

Production costs increased $313,411 from $182,810 for the six months ended January 31, 2019 to $496,221 for the six months ended January 31, 2020. This increase for the comparable three-month period was attributable primarily to increased reasonable and customary lease operating expenses.

Depletion, depreciation and amortization of asset retirement obligation liability accretion (“DD&A”)

Depletion of oil and gas properties is calculated under the units of production method, following the full cost method of accounting. For the six month period ended January 31, 2020, DD&A was $202,909 as compared to $151,389 for the six month period ended January 31, 2019. The increase in DD&A of $51,520 for the six-month comparable period was primarily due to the change in increased production for the current period relative to the prior year and an increase in the basis for DD&A calculation for property acquired.

For the three months ended January 31, 2020, the Company’s general and administrative expenses were $988,509 compared to $1,114,940 for the comparative quarter ended January 31, 2019, a decrease of $126,431.

Detail of the changes in general and administrative expense is as follows:

Liquidity and Capital Resources

The Company had a working capital deficit of $7,047,377 as of January 31 2020, compared to a working capital deficit of $4,901,103 as of July 31, 2019. The increase in the working capital deficit was primarily due to the net increase in accounts payable, issuance of convertible notes payable, and the financing of property acquisitions related to the New Mexico and Mississippi asset acquisitions.

Detail of changes in cash flows for the six months ended January 31, 2020 and 2019 are as follows:

The Company continues to seek sufficient capital to expand its drilling program. The most cost-effective source of capital would be joint-ventured working interest participation funds. A typical joint venture would involve 100% of the drilling and completion funds being provided by such working interest participants who would receive a negotiated working interest in the applicable wells.

The Company’s operating cash flow is dependent upon many factors, including production levels, sales volume, oil and gas prices and other factors that may be beyond its control.

Critical Accounting Policies and Recent Accounting Pronouncements

The Company has identified the policies below as critical to business operations and the understanding of the Company’s financial statements. The impact of these policies and associated risks is discussed throughout Management’s Discussion and Analysis where such policies affect the Company’s reported and expected financial results.

Principles of Consolidation

The Company’s consolidated financial statements include all its subsidiaries.

The following table shows the wholly-owned subsidiaries of Amazing Energy Oil and Gas, Co. which are engaged in the oil and gas business: