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EX-32.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 906 OF THE SARBANES - Amazing Energy Oil & Gas, Co.exhibit_32-2.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 906 OF THE SARBANES - Amazing Energy Oil & Gas, Co.exhibit_32-1.htm
EX-31.2 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARB - Amazing Energy Oil & Gas, Co.exhibit_31-2.htm
EX-31.1 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARB - Amazing Energy Oil & Gas, Co.exhibit_31-1.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
 
FORM 10-K
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED JULY 31, 2018
 
Commission File Number 000-52392
 
Amazing Energy Oil and Gas, Co.

(Exact name of registrant as specified in its charter)
 
Nevada
82-0290112
(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification Number)
 
5700 West Plano Parkway
Suite 3600
Plano, TX 75093

(Address of principal executive offices)
 
Registrant’s telephone number, including area code: (972) 233-1244
 
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to section 12(g) of the Act:
NONE
COMMON STOCK
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES NO
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act: YES NO
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES NO
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES NO
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated Filer
Accelerated Filer
Non-accelerated Filer (Do not check if a smaller reporting company)
Smaller Reporting Company
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES NO
 
The aggregate market value of the Common Stock held by non-affiliates (as affiliates are defined in Rule 12b-2 of the Exchange Act) of the registrant, computed by reference to the average of the high and low sale price on January 31, 2018 was $33,945,429.
 
At October 29, 2018, 84,095,232 shares of the registrant’s common stock were outstanding.
 
 
TABLE OF CONTENTS
 
 
 
Page
   
 
 
 
 
 
 
 
 
3
 
 
 
6
 
 
 
Business.
6
Risk Factors.
17
Unresolved Staff Comments.
17
Properties.
17
Legal Proceedings.
22
Mine Safety Disclosures.
22
 
 
 
23
   
 
 
Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities.
23
Selected Financial Data.
26
Management’s Discussion and Analysis of Financial Condition and Results of Operation.
26
Quantitative and Qualitative Disclosures About Market Risk.
30
Financial Statements and Supplementary Data.
31
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
32
Controls and Procedures.
32
Other Information.
33
 
 
 
33
   
 
 
Directors, Executive Officers and Corporate Governance.
33
Executive Compensation.
36
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
37
Certain Relationships and Related Transactions, and Director Independence.
40
Principal Accountant Fees and Services.
42
   
 
 
43
   
 
 
Exhibits and Financial Statement Schedules.
43
 
 
 
45
   
 
 
46
 
 
 
 
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K and the exhibits attached hereto contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, as amended. Such forward-looking statements concern the Company’s anticipated results and developments in the Company’s operations in future periods, planned exploration and development of its properties, plans related to its business and other matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.
 
Any statement that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always using words or phrases such as “believes”, “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates”, or “intends”, or stating that certain actions, events or results “may” or “could”, “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors which could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:
 
 Risks related to some of the Company’s properties being in the exploration stage;
 Risks related to the Company’s operations being subject to government regulation;
 Risks related to the Company’s ability to obtain additional capital to develop the Company’s resources, if any;
 Risks related to exploration and development activities;
 Risks related to reserve and production estimates;
 Risks related to the Company’s insurance coverage for operating risks;
 Risks related to the fluctuation of prices for oil and gas;
 Risks related to the competitive industry of oil and gas;
 Risks related to the title and rights in the Company’s properties;
 Risks related to the possible dilution of the Company’s common stock from additional financing activities;
 Risks related to potential conflicts of interest with the Company’s management;
 Risks related to the Company’s shares of common stock;
 
This list is not exhaustive of the factors that may affect the Company’s forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the sections titled “Risk Factors and Uncertainties”, “Description of Business” and “Management’s Discussion and Analysis” of this Annual Report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated or expected. The Company cautions readers not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Amazing Energy Oil & Gas, Co. disclaims any obligation subsequently to revise any forward-looking statements to reflect events or circumstances after the date of such statements or to reflect the occurrence of anticipated or unanticipated events, except as required by law. The Company advises readers to carefully review the reports and documents filed from time to time with the Securities and Exchange Commission (the “SEC”), particularly the Company’s Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.
 
As used in this Annual Report, the terms “We,” “Us,” “Our,” “Amazing Energy” and the “Company”, mean Amazing Energy Oil & Gas, Co., unless otherwise indicated. All dollar amounts in this Annual Report are expressed in U.S. dollars, unless otherwise indicated.
 
Management’s Discussion and Analysis is intended to be read in conjunction with the Company’s consolidated financial statements and the integral notes (“Notes”) thereto for the fiscal year ending July 31, 2018. The following statements may be forward-looking in nature and actual results may differ materially.
 
 
 
 
GLOSSARY AND SELECTED ABBREVIATIONS
 
The following is a description of the meanings of some of the oil and gas industry terms used in this report.
 
Basin
A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
 
 
Bbl
One stock tank barrel, of 42 U.S. gallons liquid volume, used to reference oil, condensate or NGLs.
 
 
Boe
Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
 
 
Completion
The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, for reporting to the appropriate authority that the well has been abandoned.
 
 
Developed oil and gas reserves
Has the meaning given to such term in Rule 4-10(a)(6) of Regulation S-X, as follows:
 
 
 
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
 
 
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
 
 
 
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
 
 
 
 
Dry hole or well
An exploratory, development or extension well that proved to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
 
Hydraulic fracturing
 The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
 
 
Lease operating expenses
The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
 
 
Mbo
Thousand barrels of oil or other liquid hydrocarbons.
 
 
Mboe
Thousand barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
 
 
Mcf
Thousand cubic feet of natural gas.
 
 
Mmcf
Million cubic feet of gas.
 
 
Mineral interests
The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
 
 
Net Revenue Interest
An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
 
 
Oil and Natural Gas Properties
Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
   
   
Operator
The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
   
   
Play
A set of known or postulated oil and/or gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.
 
 
Productive well
An exploratory, development or extension well that is not a dry well.
 
 
Proved developed
producing reserves
Proved developed oil and gas reserves that are expected to be recovered:
 
 
 
 
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
 
 
 
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
 
 
Proved oil and gas reserves
Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, as follows:
 
 
 
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
 
 
(i)
The area of the reservoir considered as proved includes:
 
 
 
 
(A)
The area identified by drilling and limited by fluid contacts, if any, and
 
 
 
 
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geosciences and engineering data.
 
 
 
 
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
 
 
 
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
 
 
 
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
 
 
 
 
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
 
 
 
(v)
Existing economic conditions include prices and costs at which economic viability from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
 
 
 
 
 
Proved Undeveloped Reserves
Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
 
 
 
PUD
Proved undeveloped
 
 
PV-10
 
An estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of PV-10 are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.
 
 
Reserves
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
 
 
Royalty Interest
An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.
 
 
Standardized measure
 
The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions.
 
 
Working interest
The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
 
 
PART I

ITEM 1.
BUSINESS.
 
BUSINESS DEVELOPMENT
 
Amazing Energy Oil and Gas, Co. is incorporated in the State of Nevada. Through its primary subsidiary, Amazing Energy, Inc., also a Nevada corporation, the Company operates its main business of exploration, development, and production of oil and gas in the Permian Basin of West Texas. On October 7, 2014, the Company entered into a change in control agreement with certain shareholders of Amazing Energy, Inc. The change in control agreement was the first step in a reverse merger process whereby the shareholders of Amazing Energy, Inc. would control about 95% of the shares of common stock of Amazing Energy Oil and Gas, Co., and Amazing Energy Oil and Gas, Co. would own 100% of the outstanding shares of common stock of Amazing Energy, Inc. This entire reverse merger process was completed in July of 2015.
 
Amazing Energy, Inc. (“AEI”), a wholly owned subsidiary of Amazing Energy Oil and Gas, Co., was formed in 2010 as a Texas corporation and re-domiciled to Nevada in 2011. The Company owns interests in oil and gas properties located in Texas. The Company is primarily engaged in the acquisition, exploration and development of oil and gas properties and the production and sale of oil and natural gas. Amazing Energy, LLC was formed in December 2008 as a Texas Limited Liability Company. In December of 2010, Amazing Energy, Inc. and Amazing Energy, LLC were combined as commonly controlled entities.
 
 
The following table shows the wholly owned subsidiaries of Amazing Energy Oil and Gas, Co. engaged in the oiland gas business:
 
Name of Subsidiary
State of
Incorporation
 
Ownership
Interest
 
Principal Activity
Amazing Energy, Inc.
Nevada
 
 
100
%
 
Oil and gas exploration, development, and products
 
 
 
 
 
 
 
 
Amazing Energy, LLC
Texas
 
 
100
%
 
Ownership oil and gas leases
 
 
 
 
 
 
 
 
Kisa Gold Mining, Inc.
Alaska
 
 
100
%
 
Inactive
 
 
 
 
 
 
 
 
Jilpetco, Inc.
Texas
 
 
100
%
 
Operator and Oilfield services
 
On July 31, 2016, the Company acquired Gulf South Securities, Inc. (“GSSI”). GSSI was organized to be active in various aspects of the securities industry and was registered as a broker-dealer with the Financial Industry Regulatory Authority (“FINRA”) and the Securities and Exchange Commission (“SEC”). The Company allowed GSSI’s FINRA registration to lapse as of February 28, 2017.  On January 8, 2018, the Company dissolved Gulf South Securities, Inc.
 
Any bankruptcy, receivership or similar proceedings
 
There have been no bankruptcy, receivership or similar proceedings.
 
OUR BUSINESS
 
We are in the business of exploration, development, and production of oil and gas in the Permian Basin of West Texas. This 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 July 31, 2018 the Company has leasehold rights located within approximately 70,000 acres in Pecos County, Texas. We believe that our concentrated acreage position provides us with an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. Our activities are 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. Additional drilling targets could include the Greyburg, San Andreas and Devonian zones.
 
At July 31, 2018 our estimated net proved reserves were 398,308 barrels of oil equivalent (“BOE”). Additionally, probable reserves total 211,355 as of July 31, 2018. Important facts of our proved and probable reserves at July 31, 2018 include:
 
73% oil and 27% gas;
65% proved developed and undeveloped;
Reserve life of approximately 22.0 years;
Non-discounted future net cash flows of $13,045,460;
and PV-10 of $9,077,420
 
PV-10 is our estimate of the present value of future net revenues from proved oil, and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates for future income taxes. Estimated future net revenues are discounted at an annual rate of 10% to determine their present value. PV-10 is a financial measure that is not determined in accordance with accounting principles generally accepted in the United States (“GAAP”), and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure, as computed under GAAP.
 
At July 31, 2018, we owned 25 oil and gas wells in the Permian Basin. During the fiscal year ended July 31, 2018, we produced 11,177 BOE (Net). Production for the fiscal year ended July 31, 2017 was 11,820 BOE (Net).
 
Our Business Strategy
 
We intend to increase the value of the Company by increasing reserves and production in a cost-efficient manner by pursuing the following strategies:
 
 
Grow production and reserves by developing our oil-rich resource base. We intend to drill and develop our acreage base to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital.
 
Continue to drill and develop our shallow drilling play. We believe that our current acreage position (leasehold rights located within approximately 70,000 acres) provides us with the ability to continue to increase reserves and production by drilling shallow, low cost wells with joint venture investors. Typically, we strive to structure an offering in which participants/investors will “carry” (that is, bear the financial responsibility) for 25% of 8/8ths Working Interests. Each participant/investor is responsible for their pro-rata share of the Working Interest expenses. A “Carried Working Interest” is defined as a working interest which is expense-free through the stages of drilling, testing and completing a well to first sales or plugging and abandoning a well as a dry hole; participants/investors bear the portion of those costs and expenses attributable to the Carried Working Interest of the Company. The Company typically offers 75% of 8/8ths Working Interest in a drilling offering with a net revenue interest of 75%. The Carried Working Interest that the Company receives varies on the participation levels for each drilling offering. For example, if there is full participation, the Company will receive a 25% Carried Working Interest. The Company is constantly reviewing other potential acreage acquisitions, or other potential alliances with industry partners.
 
Our Competitive Strengths
 
We believe that the following strengths will help us achieve our business goals:
 
Economically efficient drilling. Given the current relative low price for oil, we believe that we have a competitive advantage over higher risk, high cost, and deeper shale drilling operations. Most of our current wells are drilled and completed for around $275,000 or less at depths of around 2,000 feet.
 
Oil rich resource base in one of North America’s leading resource plays. All our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. 
 
Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longest operating hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks in the Permian Basin as compared to emerging hydrocarbon basins.
 
Experienced, incentivized and proven management team. Our management team has many years of experience in the oil and gas industry throughout Texas. Also, the Company strives to keep drilling, completion, operating expenses and general overhead to a minimum.
 
High degree of operational control. We are currently 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 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.
 
Markets and Customers
 
The revenues generated by our operations are highly dependent upon the prices, supplies and demand for oil and natural gas. Oil and natural gas are commodities, and therefore, we are subject to market-based pricing. Since our oil is sour, we receive somewhat less per barrel than the published WTI market prices, and since our natural gas is a sour gas, we are limited to selling through a sour gas transmission line and therefore are subject to a percent of proceeds (POP) gas contract with the purchaser. Overall, the prices that we receive for our oil and gas production depend on numerous factors beyond our control, including seasonality, the status of domestic and global economies, political conditions in other oil and gas producing countries, and the extent of domestic production and imports of oil.
 
 
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 to conduct drilling operations on those 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 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 position in Pecos County provides for the payment of royalties to the mineral owners for all oil and natural gas produced form 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 Company working interest generally ranging from 75% to 80%.
 
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.
 
Patents and Trademarks
 
The Company does not own, either legally or beneficially, any patents or registered trademarks.
 
Regulation
 
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 (the “DOT”) (Office of Pipeline Safety) 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
 
Sales of crude oil and natural gas are negotiated with purchasers via crude oil purchase agreements which are subject to a month to month term, and a 30-day notice termination clause. The agreements specify the pricing terms and transportation deductions, among other terms. Our sales of crude oil are affected by the availability, terms and cost of transportation.
 
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 state in which we operate, Texas, has 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 imposes 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. It has until 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, inUtility Air Regulatory Group v. EPA, the 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 resulting Paris Agreement calls 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. 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. . On June 1, 2017 President Trump announced the United States would withdraw from the Paris Agreement, which by its terms cannot happen prior to November 4, 2020.
 
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. It also remains unclear whether and how the results of the 2016 U.S. election could impact the regulation of greenhouse gas emissions at the federal and state level.
 
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 flowback 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.
 
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 location of the wells
the method of drilling and casing wells;
the timing of construction or drilling activities, including season wildlife closures;
the rates of production 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 regulates 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. 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.
 
Employees
 
As of July 31, 2018, we had 3 full-time employees. We regularly use independent contractors and consultants to perform various drilling and other services. None of our employees are represented by a labor union or covered by any collective bargaining agreement.
 
Facilities
 
Our corporate headquarters were previously located in Amarillo, Texas but, at date of this filing, have been relocated to Plano, Texas. We believe that our facilities are adequate for our current operations.
 
Insurance Matters
 
The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high-pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. We are not insured fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
 
We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.
 
 
 
Available Information
 
We maintain an Internet website under the name www.amazingenergy.com. 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 public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, 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.
 
ITEM 1A.
RISK FACTORS.
 
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS.
 
Not applicable.
 
ITEM 2.
PROPERTIES – TEXAS OIL AND GAS
 
Pecos County, Texas – The Company has leasehold rights within approximately 70,000 gross acres in Pecos County, Texas, which lies within the Permian Basin. This basin, which is one of the major producing regions 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. The property is located in the Northeast region of the Pecos County. The Pecos leasehold is positioned west of the Yates Field (Approximately 1.6 Billion BO produced) and east of the Taylor Link Field (Approximately 17 million BO produced). Our leasehold also lies within the White & Baker Field (Approximately 5 million BO produced) and portions of the Walker Field (Approximately 10 million BO produced). The Pecos leasehold is comprised of multiple leases. Our acreage position in the Permian Basin is characterized by several commercial hydrocarbon formations which begin around 1,300 ft. down to around 10,000 ft. The formations in the area include the Yates, Seven Rivers, Greyburg, Queen (Upper and Lower), San Adreas, Strawn, Devonian and Ellenburger. The Company began drilling operations in October 2010 to target the Greyburg and Queen formation. Since then the Company has drilled 23 wells throughout the property of which 21 wells are producing intermittently and 2 wells are shut-in. All the wells that the Company has drilled have been to a depth of approximately 2,000 ft. During the year ended July 31, 2018, the WWJD #31 was drilled to approximately 4,000 ft. and the Company did several types of testing which included 26 sets of drilled sidewall cores.
 
 
 
The following table summarizes our estimated proved and probable oil and gas reserves for the fiscal years ended July 31, 2018, 2017 and 2016.
 

 
Proved and Probable Reserves (BOE)
 
 
 
July 31,
 
 
 
2018
 
 
2017
 
 
2016
 
Proved developed
  40,090 
  234,010 
  429,387 
Proved undeveloped
  358,218 
  261,958 
  315,803 
Total proved
  398,308 
  495,968 
  745,190 
 
    
    
    
Probable undeveloped
  211,355 
  - 
  - 
 
    
    
    
Total Reserves
  609,663 
  495,968 
  745,190 
 
    
    
    
 
    
    
    
Percent of total proved resources
  65%
  100%
  100%
 
    
    
    
Proved and probable oil and gas reserves
 
The following table sets forth information regarding our estimated proved reserves as of July 31, 2018. See Note 17 to our consolidated financial statements in this report for additional information.
 
Summary of oil and gas reserves as of July 31, 2018
 
 
 
Proved and Probable Reserves
 
 
 
Oil  
 
 
Natural Gas
 
 
Total
 
 
Percent
 
 
PV-10
 
 
 
(Bbl)
 
 
(Mcf)
 
 
(BOE)
 
 
(%)
 
 
($)  
 
Proved developed
  26,790 
  79,800 
  40,090 
  6.58%
 $390,410 
Proved undeveloped
  262,480 
  574,430 
  358,218 
  58.76%
 $6,122,620 
 
    
    
    
    
    
Total proved
  289,270 
  654,230 
  398,308 
  65.33%
 $6,513,030 
 
    
    
    
    
    
Probable undeveloped
  154,820 
  339,210 
  211,355 
  34.67%
 $2,564,390 
 
    
    
    
    
    
Total Reserves
  444,090 
  993,440 
  609,663 
  100.00%
 $9,077,420 
 
Reconciliation of PV-10 to Standardized Measure
 
PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure as computed under GAAP.
 
We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis.
 
 
 
The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows at July 31, 2018 and 2017:
 
 
 
2018  
 
 
2017  
 
Standardized Measure, beginning of year
 $4,465,998 
 $4,628,877 
Sales of oil produced, net of production costs
  (41,648)
  22,999 
Net changes in prices, development and production costs
  1,906,668 
  3,802,489 
Change in estimated future development costs
  (960,920)
  98,145 
Extensions, discoveries and improved recovery, less related costs
  - 
  616,979 
Development costs incurred and changes during the period
  552,135 
  370,090 
Revisions of previous quantity estimates
  (1,917,137)
  (3,752,407)
Accretion of discount
  491,923 
  792,334 
Net changes in production rates and other
  1,192,528 
  (3,216,146)
Purchase of reserves
  69,060 
  - 
Sales of reserves
  - 
  (941,505)
Net changes in income taxes
  874,362 
  2,044,143 
Standardized Measure, end of year
 $6,632,969 
 $4,465,998 
 
Proved Undeveloped Reserves
 
As of July 31, 2018, we had 358,218 BOE of undeveloped (“PUD”) reserves, which is an increase of 96,260 BOE, compared with 261,958 BOE of PUD reserves at July 31, 2017.
 
Preparation of Reserves Estimates
 
Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in accordance with “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” promulgated by the Society of Petroleum Engineers (“SPE standards”). Our proved reserves are estimated at the property level and compiled for reporting purposes by corporate reservoir engineering consultants, all of whom are independent of our operations team. We maintain our evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering consultants interact with Company Management and with accounting employees to obtain the necessary data for the reserves estimation process. Our Management staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. For the years ended July 31, 2018, and July 31, 2017, we engaged Mire & Associates, Inc., an independent petroleum engineer, to prepare independent estimates of the extent and value of the proved reserves associated with certain of our oil and gas properties.
 
Controls over Reserve Estimates
 
Compliance as it relates to reporting the Company’s reserves is the responsibility of Will McAndrew, CEO of the Company, who has over 47 years’ experience in resource-based companies.
 
With respect to the Company’s properties, the control over reserve estimates included retaining Mire & Associates, Inc. as our independent and geological engineering firm for the periods indicated in its reports.  The Company provided Mire & Associates, Inc. with information about its oil and gas properties, including production profiles, prices and costs, and Mire & Associates, Inc. reviewed the estimates of the reserves attributable to oil properties.  Mire & Associates, Inc. is an independent expert engineering, geological, technical and advisory company providing services to the oil and gas industry.  
 
 
 
All of the information on the Company’s oil and gas reserves for the years ended July 31, 2018, 2017 and 2016 in this Form 10-K is derived from Mire & Associates, Inc.’s reports. 
 
Oil and Gas Production, and Prices
 
The following table sets forth summary information regarding net oil and gas production for the last three fiscal years. We determined the BOE using the ratio of six MCF of natural gas to one BOE.
 
 
 
For the years ended July 31,      
 
 
 
2018  
 
 
2017  
 
 
2016  
 
Production (NET)
 
 
 
 
 
 
 
 
 
Oil (Bbls)
  5,761 
  5,566 
  7,396 
Gas (MCF)
  32,498 
  37,521 
  21,492 
Total BOE
  11,177 
  11,820 
  10,978 
Total average BOE per day
  31 
  32 
  30 
 
    
    
    
 
    
    
    
Average prices
    
    
    
Oil (Bbls)
 $52.59 
 $42.91 
 $36.49 
Gas (Mcf)
  1.82 
  2.22 
  2.03 
Total per BOE
 $52.89 
 $43.28 
 $36.83 
 
The oil and gas sales revenues shown in the table below are the Company’s net share of annual revenues in each project for the past three fiscal years:
 
 
 
For the years ended July 31,      
 
 
 
2018  
 
 
2017  
 
 
2016  
 
Oil revenue
  302,996 
  219,078 
  224,997 
Gas revenue
  59,249 
  57,424 
  25,479 
 
 $362,245 
 $276,502 
 $250,476 
 
Drilling Activity – Past Two Years
 
The following table sets forth information on our drilling activity. The information should not be considered indicative of future performance nor should it be assumed that there is necessarily any correlation between the numbers of productive wells drilled, quantities of reserves found or economic value.
 
 
 
 
 
Cumulative Well Status
 
 
Wells Drilled
 
 
Cumulative Well Status
 
Drilling Activity/Well Status
 
at 7/31/2018
 
 
YE 7/31/2018
 
 
7/31/2017  
 
 
 
Gross
 
 
Net
 
 
Gross
 
 
Net
 
 
Gross
 
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Development Wells:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive -Texas
  25.00 
  21.49 
  2.00 
  2.00 
  23.00 
  15.50 
Test Wells (Dry)
  - 
  - 
  - 
  - 
  - 
  - 
 
    
    
    
    
    
    
Exploration Wells:
    
    
    
    
    
    
Productive
  - 
  - 
  - 
  - 
  - 
  - 
Dry
  - 
  - 
  - 
  - 
  - 
  - 
 
    
    
    
    
    
    
 
    
    
    
    
    
    
Total Drilled Wells:
    
    
    
    
    
    
Productive -Texas
  25.00 
  21.49 
  2.00 
  2.00 
  23.00 
  15.50 
Test Wells (Dry)
  - 
  - 
  - 
  - 
  - 
  - 
 
    
    
    
    
    
    
 
    
    
    
    
    
    
Acquired Wells:
    
    
    
    
    
    
Productive -Texas
  - 
  - 
  - 
  - 
  - 
  - 
 
    
    
    
    
    
    
 
    
    
    
    
    
    
Total Wells:
    
    
    
    
    
    
Productive -Texas
  25.00 
  21.49 
  2.00 
  2.00 
  23.00 
  15.50 
Test Wells (Dry)
  - 
  - 
  - 
  - 
  - 
  - 
 
    
    
    
    
    
    
Total
  25.00 
  21.49 
  2.00 
  2.00 
  23.00 
  15.50 
 
    
    
    
    
    
    
Well Type:
    
    
    
    
    
    
Oil
  - 
  - 
  - 
  - 
  - 
  - 
Gas
  - 
  - 
  - 
  - 
  - 
  - 
Combination -Oil and Gas
  25.00 
  21.49 
  2.00 
  2.00 
  23.00 
  15.50 
Test Wells (Dry)
  - 
  - 
  - 
  - 
  - 
  - 
 
    
    
    
    
    
    
Total
  25.00 
  21.49 
  2.00 
  2.00 
  23.00 
  15.50 
 
Delivery Commitments.
 
As of July 31, 2018, the Company does not have any delivery commitments for product obtained from its wells.
 
Mineral Lease Interests
 
The following table summarizes the Company’s leased acreage as of July 31, 2018:
 
 
 
 
 
 
 
 
 
 
 
AMAZ Interest
 
 
AMAZ Interest
 
 
 
Total Acres
 
 
Developed Acres
 
 
Undeveloped Acres
 
Leasehold Interests - 7/31/2018
 
Gross
 
 
Net
 
 
Gross
 
 
Net
 
 
Gross
 
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Surface through San Andres -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pecos County, Texas AMI
  43,176 
  18,708 
  465 
  465 
  42,711 
  18,243 
 
    
    
    
    
    
    
 
    
    
    
    
    
    
 
    
    
    
    
    
    
Total Acreage
  43,176 
  18,708 
  465 
  465 
  42,711 
  18,243 
 
    
    
    
    
    
    
 
    
    
    
    
    
    
 
    
    
    
    
    
    
Additional Lease Deep Rights for a portion
    
    
    
    
    
    
of Total Acreage above
  20,400 
  8,192 
  0 
  0 
  20,400 
  8,192 
 
The Company’s mineral lease interests as detailed above represents leased acreage within the Pecos County 70,000 acre AMI as of July 31, 2018. Through a series of agreements with representatives of mineral owners, the Company has the right to acquire additional acreage for future development encompassing a large percentage of the 70,000 acres not under lease at July 31, 2018. Under those agreements the Company is required to make annual payments into trust accounts to hold the acquisition opportunity. As actual leases are acquired those trust funds are available to pay the lease cost per acre at predetermined amounts.
 
The Company is obligated to pay certain bonus lease payments related to certain of its lease properties.  The Company is required to pay $27,000 each year on the JT Walker lease on annually on August 7th.   The Company is also required to pay $200,000 every five years on August 7th for the JPMorgan lease. The most recent payment on this lease was made in July 2017. The next JPMorgan lease payment is due by August 7, 2022.  The Company is current in its lease payments under these leases. 
 
ITEM 3.
LEGAL PROCEEDINGS.
 
On September 7, 2017, Amazing Energy LLC and Jilpetco Inc. were served with a summons and complaint in Cause No. P-7600-83-CV in the 83rd District Court in Pecos County, Texas. The nature of the litigation is that Amazing Energy & Jilpetco were joined as defendants in a case in Pecos County, Texas, between Fredrick Bartlett Wulff, Sr. et al plaintiffs and Benedum & Trees, LLC et al defendants. The suit alleges breach of lease, breach of implied duty to explore and develop, and requests a declaratory judgment that the leases are terminated, and the suit requests an accounting of lease production. The case in the early stages of discover as to the claims against the Company. Management intends to seek an early resolution of this case by settlement, but will vigorously defend the case. It is too early in the litigation to evaluate the likely outcome or to evaluate the range of losses, as the lease interests involved are small fractional interests. In the opinion of the Company’s management, none of the pending litigation, disputes or claims against it, if decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations.
 
On December 11, 2017, Amazing Energy LLC and Jilpetco Inc. were each served with a summons and complaint in Cause No. P-7813-83-CV in the 83rd District Court in Pecos County, Texas. Amazing Energy and Jilpetco were named as defendants in a case by Rumson Royalty Company as the plaintiff.  The suit alleges Amazing Energy and Jilpetco have suspended certain royalty and/or overriding interest payments owed to the plaintiff, and requests a declaratory judgment seeking the plaintiff’s share of production proceeds and reasonable attorney’s fees. Management will vigorously defend the case. It is too early in the litigation to evaluate the likely outcome or to evaluate the financial impact of the lawsuit, if any. In the opinion of the Company’s Management, none of the pending litigation, disputes or claims against it, if decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations. 
 
ITEM 4.
MINE SAFETY DISCLOSURES.
 
Not applicable.
 
 
 
PART II
 
ITEM 5.
MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
 
The Company’s stock trades under the category OTCQX on the OTC Markets system. The Company’s trading symbol is “AMAZ”.
 
The Company changed its name from Gold Crest Mines, Inc. to Amazing Energy Oil and Gas, Co. and its trading symbol from “GCMN” to “AMAZ” on January 21, 2015. The Company also underwent a 40 to 1 reverse stock split. The Company also changed its fiscal year end in conjunction with the reverse acquisition from December 31st to July 31st.
 
The following table sets forth for our common stock, the high and low closing bid quotations per share, taken from the Internet, for our common stock for each quarter for the periods indicated. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.
 
 
 
Price Per Share      
 
 
 
High Bid  
 
 
Low Bid  
 
Fiscal Year Ending July 31,2018
 
 
 
 
 
 
First quarter ending October 31, 2017
 $0.46 
 $0.25 
Second quarter ending January 31, 2018
  0.87 
  0.34 
Third quarter ending April 30, 2018
  0.94 
  0.35 
Fourth quarter ending July 31,2018
  0.60 
  0.25 
 
    
    
Fiscal Year Ending July 31,2017
    
    
First quarter ending October 31, 2016
 $0.63 
 $0.30 
Second quarter ending January 31, 2017
  0.52 
  0.29 
Third quarter ending April 30, 2017
  0.30 
  0.17 
Fourth quarter ending July 31,2017
  0.40 
  0.20 
 
Shareholders
 
As of July 31, 2018, there were approximately 601 shareholders of record of the Company’s common stock as furnished to the Company by its transfer agent and does not account for shares owned through clearing houses.
 
Dividend Policy
 
Holders of common and preferred stock are entitled to receive dividends as may be declared by the Board of Directors. The Board of Directors is not restricted from paying any dividends, but is also not obligated to declare a dividend. No dividends have ever been declared and it is not anticipated that dividends will ever be paid. The Board of Director’s discretion as to the payment of a dividend will be dependent upon the Company's financial condition, results of operations, capital requirements, and such other factors as the Board of Directors deem relevant.
 
Transfer Agent
 
The transfer agent for the Company’s common stock is American Stock Transfer and Trust Company, 6201 15th Avenue, Brooklyn, NY 11219 - astfinancial.com.
 
Stockholders’ Equity and Equity Transactions
 
The Company is authorized to issue 3,000,000,000 shares of its common stock. All shares of common stock are equal to each other with respect to voting, liquidation, dividend, and other rights. Owners of shares are entitled to one vote for each share owned at any Shareholders’ meeting. The common stock of the Company does not have cumulative voting rights, which means that the holders of more than fifty percent (50%) of the shares voting in an election of directors may elect all of the directors if they choose to do so. The Company is authorized to issue 10,000,000 shares of its preferred stock with a $.001 par value per share.
 
 
 
During the year ended July 31, 2018 and 2017, the Company had the following equity transactions:
 
Common Stock:
 
During the years ended July 31, 2018 and 2017, the Company issued 12,920,010 and 6,249,959 shares of common stock, respectively, for cash of $3,230,000 and $1,636,212.
 
During the years ended July 31, 2018 and 2017, the Company issued 856,626 and 31,625 shares of common stock with total fair values of $535,200 and $12,375, respectively, as compensation for services.
 
During the years ended July 31, 2018 and 2017, the Company issued 3,617,556 and -0- shares of common stock for lease interests with total fair values of $1,736,429 and $-0-, respectively.
 
On May 27, 2017, the related party noteholders of notes payable agreed to extend the maturity date of the Notes to December 31, 2017. As consideration for the change in terms, the Company issued to the noteholders an aggregate 460,000 shares of the Company’s common stock with a fair value of $105,800.
 
Preferred Stock:
 
On July 31, 2016, the Company issued 9,000 shares of its Preferred Series A stock with par value of $0.01 per share. These shares were issued to Jed Miesner, the Company’s controlling shareholder, in exchange for cancellation of $900,000 of related party interest payable in the amount of $612,697 and convertible debt payable to JLM Strategic Investments, LP in the amount of $287,303. The stated issue price was $100 per share. Each share of preferred stock has 10,000 votes and votes with the common shares on all matters submitted to the shareholders for a vote. Holders of the Series A Preferred Stock will not be entitled to receive a dividend. Upon a liquidation event, an amount in cash equal to $100 per share, for a total of $900,000 at July 31, 2017 shall be paid prior to liquidation payments to holders of Company securities junior to the Series A Preferred Stock. On July 31, 2021, any shares of the Series A Preferred Stock outstanding will be convertible, at the discretion of the holder, for a period of three years, into common stock purchase warrants of the Company with an exercise price of $1.00 per share on the basis of 110 shares of common stock for each one share of Series A Preferred Stock outstanding.
 
During the years ended July 31, 2018 and 2017 there were no transactions with respect to outstanding preferred stock.
 
Warrants:
 
During the years ended July 31, 2018 and 2017, the Company issued 3,469,391 and -0- warrants with total fair values of $1,038,587 and $-0-, respectively, as compensation for services.
 
During the years ended July 31, 2018 and 2017, the Company issued 136,666 and -0- warrants for oil and gas property interests with total fair values of $77,961 and $-0-, respectively.
 
The composition of the Company’s warrants outstanding at July 31, 2018 is as follows:
 
 
 
 
 Exercise
 
 
Expiration Date In    
 
 
 
 
 
 Price
 
 
2019
 
 
2020
 
 
2021
 
 
2022
 
 
2023
 
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 $0.37 
  - 
  - 
  - 
  - 
  20,175 
  20,175 
 $0.40 
  - 
  - 
  1,030,000 
  300,000 
  15,000 
  1,345,000 
 $0.43 
  - 
  - 
  - 
  - 
  21,525 
  21,525 
 $0.44 
  - 
  - 
  - 
  - 
  38,900 
  38,900 
 $0.50 
  - 
  1,200,000 
  400,000 
  - 
  - 
  1,600,000 
 $0.51 
  - 
  - 
  - 
  - 
  58,150 
  58,150 
 $0.60 
  2,674,576 
  - 
  200,000 
  5,000 
  23,875 
  2,903,451 
 $0.64 
  - 
  - 
  - 
  - 
  12,125 
  12,125 
 $0.67 
  - 
  - 
  25,000 
  - 
  35,000 
  60,000 
 $0.74 
  - 
  - 
  - 
  - 
  17,975 
  17,975 
 $1.00 
  - 
  - 
  203,332 
  - 
  - 
  203,332 
 
  2,674,576 
  1,200,000 
  1,858,332 
  305,000 
  242,725 
  6,280,633 
 
There were no warrants exercised during the year ended July 31, 2018.
 
Stock Options:

In February 2017, the Board of Directors adopted and approved the 2017 Stock Option Plan (the “2017 Plan”). The 2017 Plan, by its terms, required a majority vote of the Company’s shareholders, within 12 months of the adoption of the 2017 Plan, to approve the 2017 Plan. A majority of the Company’s shareholders never approved the 2017 Plan and therefore the 2017 Plan is now void. No options were ever issued pursuant to the 2017 Plan.
 
On August 11, 2017, the Board of Directors authorized the grant of 5,835,000 options to purchase shares of common stock of the Company to certain officers related to their employment agreements (the “Listing Options”). The Listing Options will vest and be immediately exercisable on the date the Company's stock is traded on the American Stock Exchange, the New York Stock Exchange, or any of the NASDAQ trading tiers. The Listing Options shall have an exercise price equal to the closing price on the date such trading commences. As of July 31, 2018, management has determined the probability of such an event is doubtful and, therefore, has not recognized any compensation expense to date regarding the Listing Options.
 
On August 11, 2017, the Board of Directors authorized the grant of 11,750,000 options to purchase shares of common stock of the Company to certain officers. The options have an exercise price of $0.40 and expire five years from the date of grant. 2,937,500 of the options vested immediately on the grant date and the remainder shall vest 25% annually upon each anniversary of the grant date. For the year ended July 31, 2018, the Company recognized a fair value of $1,436,575 for the vested options and the ratable recognition of unvested options as stock-based compensation. Unrecognized compensation related to the option grant is $1,436,575 as of July 31, 2018, to be recognized over the remaining life of the options.
 
On August 11, 2017, the Board of Directors authorized the grant of 10,000,000 options to purchase shares of common stock of the Company to its Chief Executive Officer. The options have an exercise price of $0.40 per share and expire five years from the date of grant. 2,000,000 options vested on the date of grant. The fair value of the grant was $489,047 which was recognized as stock-based compensation at the date of grant. The remaining 8,000,000 options contained market and performance conditions, of which 4,000,000 options are to vest based on market conditions being met and 4,000,000 options will vest upon achievement of certain performance objectives. Management has assessed the likelihood of market conditions and the probability of performance conditions being realized and recognize a fair value of $647,987 for the year ending July 31, 2018.
 
 
 
On September 26, 2017, the Board of Directors also authorized the grant of 500,000 options to purchase shares of common stock of the Company to certain directors.  These options have an exercise price of $0.40 and expire on September 26, 2021. The fair value of the grant was $137,056 which the Company recognized as stock-based compensation for the year ended July 31, 2018. The options vested immediately at the date of grant.
 
The composition of the Company’s stock options outstanding at July 31,2018 is as follows:
 
 Exercise
 
Expiration Date in
 
 
 
 
 Price
 
2021
 
 
2022
 
 
Total
 
 
 
 
 
 
 
 
 
 
 
  $0.40 
  500,000 
  27,585,000 
  28,085,000 
       
    
    
    
       
    
    
    
 
 Totals
 
  500,000 
  27,585,000 
  28,085,000 
 
At July 31, 2018, the Company had reserved 34,365,633 common shares for future exercise of warrants and options.
 
ITEM 6.
SELECTED FINANCIAL DATA.
 
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
 
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
 
The following discussion should be read in conjunction with our audited financial statements and notes thereto included herein. 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 31,2018, and for each of the 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-K. 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. This 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 July 31, 2018, the Company has leasehold rights located within approximately 70,000 acres in Pecos County, Texas. We believe that our concentrated acreage position provides us with an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. 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. Additional drilling targets could include the Greyburg, San Andreas and Devonian zones.
 
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 be accretive 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 2018 Activity
 
Our fiscal year 2018 activity focused on conventional drilling in the Queen formation in Pecos County, Texas. We spudded 2 conventional wells and completed 2 wells in fiscal 2018, compared to spudding 1 conventional well and completion of 1 well in fiscal 2017. We continued to develop the Queen formation in Pecos County, Texas during fiscal 2018. The rate of drilling wells depends on raising capital to fund drilling and completion. Our overall accomplishments in fiscal 2018 include:
 
Production. Net production for fiscal 2018 totaled 11,177 BOE, compared to 11,820 BOE in fiscal 2017, a 5.5% decrease due to an emphasis on scientific testing for enhanced evaluation of the property during the year ended July 31, 2018. Production for fiscal 2018 was 52% oil and 48% natural gas.
 
In July 2017, the Company paid its largest lessors their 5-year prepaid bonuses totaling $200,000 in satisfaction of lease obligations.
 
In fiscal 2018, our estimated net proved reserves decreased 19.7%, or 97,660 BOE to 398,308 BOE from 495,968 BOE. Our proved reserves at fiscal year-end 2018 were 72% oil and 28% natural gas, compared to 62% oil and 38% natural gas at year-end 2017.
 
 
 
Plan for Fiscal 2019
 
For the fiscal year ending July 31, 2019, in order to develop additional reserves and production, we plan to continue raising funds to continue drilling shallow oil and gas wells located within the 70,000 acres, in Pecos County, where our leasehold rights exist. We anticipate raising such funds through joint ventures working interest holder participation, whereby the company would retain a carried working interest participation because of its existing lease ownership. In order to keep the leasehold in good standing, we adhere to the Continuous Drilling Clause for each respective lease and meet the requirements found therein. Capital expenditures and thus drilling activity for fiscal 2019 depend, to a significant extent, on the future market prices for oil.
 
The Company’s Expansion Strategy includes the following:
 
Capital Expenditure Strategy for Pecos Asset
 
Pecos County acreage represents the main revenue driver for Amazing Energy.
 
Management plans to implement a monthly capital budget to drill additional wells
 
Seeking to Acquire Additional Assets
 
Potential pipeline acquisition with current positive cash flow.
 
The company is geographically agnostic within the U.S. and is comfortable participating in both operated and non-operated transactions in most geological basins located in the lower 48 States  but on a more practical basis prefers locations contiguous to Texas.
 
Growth through JV/ Farm Out
 
The Company intends to initiate discussions with other operators for the purpose of forming joint-ventures on current acreage as well as any acreage acquired in the future.
 
Any such joint-ventures could allow Amazing to leverage the resources and know-how of leading operators to drive significant shareholder value within Amazing.
 
RESULTS OF OPERATIONS – FOR THE YEARS ENDED JULY 31, 2018 AND 2017
 
The following is a summary of the Company’s revenue for the years ended July 31, 2018 and July 31,2017:
 
 
 
Year ended July 31,      
 
 
 
 
 
 
 
 
 
2018  
 
 
2017  
 
 
Increase  
 
 
% Change
 
 
 
 
 
 
 
 
 
(Decrease)  
 
 
 
 
Oil sales
 $302,996 
 $219,078 
 $83,918 
  38.31%
Natural gas sales
  59,249 
  57,424 
  1,825 
  3.18%
Field services revenue
  84,389 
  124,618 
  (40,229)
  -32.28%
   Total revenue
 $446,634 
 $401,120 
 $45,514 
  11.35%
  
Our oil and gas revenue increased from $276,502 for the year ended July 31, 2017 to $362,245 for the year ended July 31, 2018, which was an increase of $85,743. Multiple factors contributed to the increase in oil and gas revenue. Although oil production slightly decreased, our natural gas production increased significantly as compared to the prior year’s production. The average commodity prices for oil and natural gas were improved for fiscal 2018 as compared to than the average price of oil and gas in fiscal 2017.
 
Field service revenue decreased from $124,618 for fiscal 2017 to $84,389 for fiscal 2018, which was a decrease of $40,229. The decrease in field service revenue was due in part to decreased field services on the properties that Jilpetco operated, acquisition of outside working interests in operated properties, and limited drilling and completion work during the fiscal year ending July 31, 2018.
 
As of July 31, 2018, the Company’s oil and gas production was generated from twenty-five wells. The working interest ownership was 100% as of July 31, 2018.
 
 
 
The following is a summary of the Company operating expenses for the years ended July 31, 2018 and July 31, 2017:
 
 
 
Year ended July 31,  
 
 
 
 
 
 
 
 
 
2018  
 
 
2017  
 
 
Increase
 
 
% Change
 
 
 
 
 
 
 
 
 
(Decrease)
 
 
 
 
Production costs
 $130,056 
 $436,604 
 $(306,548)
  -70.21%
Depletion, depreciation and amortization
  342,426 
  301,124 
  41,302 
  13.72%
Selling general and administrative expenses
  6,286,876 
  822,336 
  5,464,540 
  664.51%
Accretion expense
  9,449 
  9,396 
  53 
  0.56%
(Gain) on sale of mineral properties
  - 
  (170,000)
  170,000 
  -100.00%
   Total operating expenses
 $6,768,807 
 $1,399,460 
 $5,369,347 
  383.67%
 
General and administrative costs increased from $822,336 incurred in fiscal 2017 compared to $6,286,876 in fiscal 2018, which is an increase of $5,464,540. Detail of the increase is detailed as follows:
 
Increase(decrease) in non cash stock and warrant compensation
 $3,795,472 
Increase(decrease) in consulting expense
 $268,790 
Increase(decrease) in legal fees
 $49,213 
Increase(decrease) in investor relations expense
 $153,463 
Increase(decrease) in travel expense
 $54,345 
Increase(decrease) in reimbursements
 $111,194 
Increase(decrease) in salaries, employee benefits and payroll taxes
 $954,140 
Increase(decrease) in general corporate expenses
 $77,923 
 
    
Total Increase in General and Administrative Expenses
 $5,464,540 
 
Depletion, depreciation and amortization expense increased from $301,124 in fiscal 2017 to $342,426 in fiscal 2018.
 
Due to the volatile nature of our business, we expect that revenues, as well as the related variable expenses, will continue to fluctuate substantially quarter–to–quarter and year–to–year. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices. Our average price on a BOE basis for oil and gas changed from $43.28 in fiscal 2017 to $52.89 in fiscal 2018, which was an increase of $9.61. Production expenses will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells. Our goal is to improve cash flow in order to cover operating costs and expenses by attracting additional working interest partners to fund our drilling program.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Our primary resource is our leasehold rights which are located within an approximately 70,000-acre position in Pecos County, TX and the related oil and gas reserves. Our ability to develop our leasehold position is dependent upon investor groups willing to deploy the requisite capital with us. Our plans are to continue to attract drilling and completion funds whereby the investor earns a 75% working interest participation and our company retains a 25% “carried working interest” participation. The ability to attract such capital is dependent upon, among other economic factors, the prices for oil and gas, and the continued favorable income tax treatment that passes through to working interest participants.
 
 
 
CASH FLOWS
 
Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:
 
 
 
July 31,2018
 
 
July 31,2017
 
 
Increase
 
 
 
 
 
 
 
 
 
(Decrease)
 
 
 
 
 
 
 
 
 
 
 
Net cash used in operating activities
 $(2,014,926)
 $(961,340)
 $(1,053,586)
Net cash provided by (used in) investing activities
 $(934,922)
 $5,543 
 $(940,465)
Net cash provided by financing activities
 $2,716,440 
 $1,367,623 
 $1,349,317 

CASH FLOW PROVIDED BY (USED IN) OPERATING ACTIVITIES
 
Cash flow from operating activities is derived from net loss less noncash items that impact net loss, plus changes in current asset and liabilities account balances. For the year ended July 31, 2018, cash used by operating activities was $2,014,926 in comparison to cash used by operating activities in the amount of $961,340 for the year ended July 31, 2017. This increase in cash used by operating activities of $1,053,586 was primarily due to losses from operations.
 
CASH FLOW (USED IN) INVESTING ACTIVITIES
 
Cash flow used in investing activities is primarily attributable to investment in oil and gas properties.
 
CASH FLOW FROM FINANCING ACTIVITIES
 
Cash flow from financing activities was principally attributable to $3,230,000 in proceeds from sales of common stock. Cash used in note repayments was $513,560.
 
OIL AND GAS RESERVES
 
The Company’s total net proved developed and undeveloped and probable oil and gas reserves and related values are summarized in the following table:
 
 
 
Net Reserves      
 
 
Cash Flows      
 
 
 
Oil
 
 
Gas
 
 
Non
 
 
Discounted
 
 
 
(BO)
 
 
(Mcf)
 
 
Discounted
 
 
at 10%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As of July 31,2018
  444,090 
  993,440 
 $13,045,460 
 $9,077,420 
 
    
    
    
    
As of July 31,2017
  305,440 
  1,143,170 
 $9,722,900 
 $7,052,380 

Quantities of the oil and gas net reserves have increased from July 31, 2017 to July 31, 2018 and the projected cash flows increased because the prices for the analysis as of July 31,2017 were based upon oil at $48.71 per barrel and gas at $3.01 per MMBTU and the reserve analysis was based on oil prices at $61.55 per barrel and gas at $2.91 per MMBTU at July 31,2018.
 
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
 
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
 
 
 
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
INDEX TO FINANCIAL STATEMENTS
 
 
Index
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
F-1
Consolidated Balance Sheets
F-2
Consolidated Statements of Operations
F-3
Consolidated Statements of Changes in Stockholders’ Equity
F-4
Consolidated Statements of Cash Flows
F-5
Notes to Financial Statements
F-7
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Report of Independent Registered Public Accounting Firm
 
To the shareholders and the board of directors of Amazing Energy Oil and Gas, Co. and Subsidiaries
 
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Amazing Energy Oil and Gas, Co. and Subsidiaries (the "Company") as of July 31, 2018 and 2017, the related statements of operations, changes in stockholders’ equity and cash flows for each of the years 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 2017, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.
 
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 2 to the financial statements, the Company has limited financial resources, negative working capital and an accumulated deficit at July 31, 2018. These factors raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. 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 audits. 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 audits 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 audits we are required to obtain an understanding of internal control over financial reporting but not for expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 
Our audits 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 audits 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 audits provide a reasonable basis for our opinion.
 
/s/ DeCoria, Maichel & Teague, P.S.
 
DeCoria, Maichel & Teague, P.S.
We have served as the Company's independent auditor since 2014
Spokane, Washington
October 29, 2018
 
 
 
AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
 
 
 
July 31
 
 
July 31
 
 
 
2018
 
 
2017
 
ASSETS
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
Cash and cash equivalents
 $523,695 
 $756,603 
Receivable from working interest owners
  33,954 
  64,392 
Production revenue receivable
  48,188 
  39,901 
Prepaid expenses
  40,000 
  67,843 
Total current assets
  645,837 
  928,739 
 
    
    
Oil and gas properties - proved, net
  5,422,989 
  3,869,489 
Oil and gas properties - unproved
  3,079,492 
  2,049,593 
Property and equipment, net
  434,528 
  545,812 
Other assets
  78,600 
  76,622 
 
    
    
TOTAL ASSETS
 $9,661,446 
 $7,470,255 
 
    
    
LIABILITIES AND STOCKHOLDERS' EQUITY  
    
    
Current liabilities:
    
    
Accounts payable and accrued liabilities
 $295,015 
 $139,821 
Payable to related party
  25,038 
  - 
Promissory notes, related party
  311,730 
  430,892 
Note payable
  - 
  50,000 
Notes payable, related parties
  - 
  347,500 
Note payable on acquisition, related party
  - 
  104,167 
Equipment note payable
  10,247 
  10,006 
Due to working interest owners
  389,562 
  421,423 
Accrued interest payable, related parties
  400,805 
  244,009 
Total current liabilities
  1,432,397 
  1,747,818 
 
    
    
Long term liabilities:
    
    
Promissory notes, related party
  2,769,440 
  2,650,278 
Equipment note payable
  22,847 
  34,981 
Asset retirement obligation
  258,575 
  183,397 
 
    
    
Total liabilities
  4,483,259 
  4,616,474 
 
    
    
Commitments and contingencies, (Note 13)
  - 
  - 
 
    
    
Stockholders’ equity:
    
    
 
Preferred stock, no par value, 10,000,000 shares authorized;
 
    
    Series A, par value $0.01, 9,000 shares issued and outstanding
  90 
  90 
    Series B, par value $0.01, 50,000 shares issued and outstanding
  500 
  500 
 
    
    
Common stock, par value $0.001 per share; 3,000,000,000 shares authorized;
  83,977 
  66,581 
 83,975,232 issued and outstanding at July 31, 2018
    
    
 66,581,040 issued and outstanding at July 31, 2017
    
    
Additional paid-in capital
  37,637,323 
  28,814,857 
Accumulated deficit
  (32,543,703)
  (26,028,247)
Total stockholders' equity
  5,178,187 
  2,853,781 
 
    
    
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
 $9,661,446 
 $7,470,255 
 
The accompanying notes are an integral part of these financial statements
 
 
AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
Year Ended July 31,
 
 
 
2018
 
 
2017
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
Oil and gas sales
 $362,245 
 $276,502 
Oilfield service revenue
  84,389 
  124,618 
      Total Gross Revenue
  446,634 
  401,120 
 
    
    
Operating Expense
    
    
Production costs
  130,056 
  436,604 
Depreciation, depletion and amortization
  342,426 
  301,124 
General and administrative expense
  6,286,876 
  822,336 
Accretion expense
  9,449 
  9,396 
Gain on sale of mineral rights
  - 
  (170,000)
      Total Operating Expenses
  6,768,807 
  1,399,460 
 
    
    
 
    
    
     Loss from operations
  (6,322,173)
  (998,340)
 
    
    
Other (income) expense
    
    
Interest and other income
  (13,946)