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, 2017


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)

701 South Taylor Street

Suite 470, LB 113

Amarillo, TX 79101

(Address of principal executive offices)


Registrant’s telephone number, including area code: (806) 322-1922


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, 2017 was $14,937,900.



At November 13, 2017,  68,431,040 shares of the registrant’s common stock were outstanding.











TABLE OF CONTENTS


 

Page

 

 

 

CAUTIONARY NOTE REGARDING FORWARD LOOKING FINANCIAL STATEMENTS

 

 

 

 

 

Glossary

3

 

 

 

PART I

5

 

 

 

Item 1.

Business.

5

Item 1A.

Risk Factors.

14

Item 1B.

Unresolved Staff Comments.

14

Item 2.

Properties.

14

Item 3.

Legal Proceedings.

18

Item 4.

Mine Safety Disclosures.

18

 

 

 

PART II

18

 

 

Item 5.

Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities.

18

Item 6.

Selected Financial Data.

20

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operation.

20

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

27

Item 8.

Financial Statements and Supplementary Data.

27

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

50

Item 9A.

Controls and Procedures.

51

Item 9B.

Other Information.

52

 

 

 

PART III

52

 

 

Item 10.

Directors, Executive Officers and Corporate Governance.

52

Item 11.

Executive Compensation.

56

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

57

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

60

Item 14.

Principal Accountant Fees and Services.

61

 

 

PART IV

62

 

 

Item 15.

Exhibits and Financial Statement Schedules.

62

 

 

 

Signatures

64

 

 

Exhibit Index

65













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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 financial statements and the integral notes (“Notes”) thereto for the fiscal year ending July 31, 2017.  The following statements may be forward-looking in nature and actual results may differ materially.








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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


Oil and Natural Gas Properties


Operator




Play


An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.


Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.



The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.



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.



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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.

 

 

 



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Proved Undeveloped Reserves


PUD


PV-10

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.



Proved undeveloped


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



Standardized measure

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.


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.



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The following table shows the wholly owned subsidiaries of Amazing Energy Oil and Gas, Co. engaged in the oil, gas, and mining 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

 

 

 

 

 

 

 

 

Gulf South Securities, Inc.

Delaware

 

 

100

%

 

Inactive

 

 

 

 

 

 

 

 

Jilpetco, Inc.

Texas

 

 

100

%

 

Operator and Oilfield services


On July 31, 2016, we completed the acquisition of Gulf South Securities, Inc., a broker-dealer registered with the Securities and Exchange Commission (“SEC”) and the Financial Industry Regulatory Authority (“FINRA”) and on August 31, 2016, we acquired Jilpetco, Inc., a Texas corporation engaged in the business of operating and providing oilfield services to oil and gas properties.  GSSI has since allowed, on February 28, 2017, its FINRA registration to lapse and ceased operations and Amazing Energy intends to dissolve GSSI in fiscal year 2018.


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, 2017 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, 2017 our estimated net proved reserves were 495,968 barrels of oil equivalent (“BOE”). Important facts of our proved reserves at July 31, 2017 include:


·

62% oil and 38% gas;

·

47% proved developed;

·

Reserve life of approximately 19.3 years;

·

Non-discounted future net cash flows of $9,722,900;

·

and PV-10 of $7,052,380


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, 2017, we owned 23 oil and gas wells in the Permian Basin.  During the fiscal year ended July 31, 2017, we produced 11,820 BOE (Net).  Production for the fiscal year ended July 31, 2016 was 10,978 BOE (Net).


Our Business Strategy



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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, while also providing quality services.


·

High degree of operational control. 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 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.



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For the fiscal year ended July 31, 2017, sales to Sunoco, Inc. and to Trans-Pecos Natural Gas Company, LLC accounted for approximately 79% and 21%, respectively, of our total sales of oil and gas.


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 Working Interest owners 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



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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 are negotiated with Sunoco, Inc. via a crude oil purchase agreement which is subject to a month to month term, and a 30-day notice termination clause.  The agreement specifies the pricing terms and transportation deductions, amongst 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



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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



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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.


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.




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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 wells;


 

 

the method of drilling and casing wells;


 

 

the timing of construction or drilling activities, including seasonal 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, 2017, we had 6 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 are located in Amarillo, 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.




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ITEM 2.

PROPERTIES – TEXAS OIL AND GAS


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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.


The following table summarizes our estimated proved oil and gas reserves for the fiscal years ended July 31, 2017, 2016 and 2015.


 

 

Proved Reserves (BOE)

July 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Proved developed

 

 

234,010

 

 

 

429,387

 

 

 

457,852

 

Proved undeveloped

 

 

           261,958

 

 

 

315,803

 

 

 

118,188

 

Total

 

 

           495,968

 

 

 

745,190

 

 

 

576,040

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent of total proved resources

 

 

100%

 

 

 

100%

 

 

 

100%

 


Proved oil and gas reserves

 

The following table sets forth information regarding our estimated proved reserves as of July 31, 2017.  See Note 18 to our consolidated financial statements in this report for additional information.  


Summary of oil and gas reserves as of July 31, 2017



  

 

Proved Reserves

 

 

 

Oil

(Bbl)

 

 

Natural Gas

(Mcf)

 

 

Total

(BOE)

 

 

Percent

(%)

 

 

PV-10

 

Proved developed

 

 

149,280

 

 

 

508,380

 

 

 

234,010

 

 

 

47

%

 

$

3,415,720

 

Proved undeveloped

 

 

156,160

 

 

 

634,790

 

 

 

261,958

 

 

 

53

%

 

$

3,636,660

 

Total proved reserves

 

 

305,440

 

 

 

1,143,170

 

 

 

495,968

 

 

 

100

%

 

$

7,052,380

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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, 2017 and 2016:


 

 

 

 

 

2017

 

2016

Standardized Measure, beginning of year

$

4,628,877

 

$

7,849,707

Sales of oil produced, net of production costs

 

22,999

 

 

279,026

Net changes in prices, development and production costs

 

3,900,634

 

 

(7,500,569)

Extensions, discoveries and improved recovery, less related costs

 

616,979

 

 

3,381,367

Development costs incurred and changes during the period

 

370,090

 

 

76,471

Revisions of previous quantity estimates

 

(3,752,407)

 

 

(1,166,679)

Accretion of discount

 

792,334

 

 

776,341

Net changes in production rates and other

 

(3,216,146)

 

 

(1,002,119)

Sales of reserves

 

(941,505)

 

 

-

Net changes in income taxes

 

2,044,143

 

 

1,935,332

Standardized Measure, end of year

$

$4,465,998

 

$

4,628,877

 

 

 

 

 

 


Proved Undeveloped Reserves


As of July 31, 2017, we had 261,958 BOE of undeveloped (“PUD”) reserves, which is a decrease of 53,845 BOE, compared with 315,803 BOE of PUD reserves at July 31, 2016.


Preparation of Proved 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 our corporate reservoir engineering staff, all of whom are independent of our operations team.  We maintain our internal evaluations of our reserves in a secure reserve engineering database.  The corporate reservoir engineering staff interacts 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, 2017, and July 31, 2016, 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 Reese Pinney, COO of the Company, who has over 37 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, 2017, 2016 and 2015 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.

 

 

 

Years Ended July 31,

 

 

2017

 

 

2016

 

 

2015

 

Production (NET)

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

 

 5,566

 

 

 

7,396

 

 

 

12,127

 

Gas (MCF)

 

 

 37,521

 

 

 

21,492

 

 

 

65,096

 

Total BOE

 

 

11,820

 

 

 

10,978

 

 

 

22,976

 

Total average BOE per day

 

 

32

 

 

 

30

 

 

 

63

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

$

42.91

 

 

$

36.49

 

 

$

57.06

 

Gas (Mcf)

 

 

2.22

 

 

 

2.03

 

 

 

2.09

 

Total per BOE

 

$

43.28

 

 

$

36.83

 

 

$

57.41

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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


 

 

Years Ended July 31,

 

 

2017

 

 

2016

 

 

2015

 

Oil revenue

 

 

219,078

 

 

 

224,997

 

 

 

694,804

 

Gas revenue

 

 

57,424

 

 

 

25,479

 

 

 

86,328

 

 

 

$

276,502

 

 

$

250,476

 

 

$

781,133

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Drilling Activity – Past Three Years


The following table sets forth information on our drilling activity for the last three fiscal years.  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.


  

 

Years Ended July 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Development wells:

 

 

 

 

 

 

 

 

 

Productive

 

 

1

 

 

 

3

 

 

 

2

 

Dry

 

 

-

 

 

 

-

 

 

 

0

 

 

The following table sets forth the wells, working interest percentage, and status of all the wells that the Company owned at the fiscal year end July 31, 2017:


Well Name

 

Working Interest

 

Status

WWJD 1

 

100.00%

 

Shut in

WWJD 4

 

100.00%

 

Producing well

WWJD 5

 

100.00%

 

Producing well

WWJD 6

 

100.00%

 

Producing well

WWJD 7

 

40.74%

 

Producing well

WWJD 8

 

100.00%

 

Producing well

WWJD 9

 

100.00%

 

Producing well

WWJD 10

 

40.74%

 

Producing well

WWJD 11

 

100.00%

 

Producing well

WWJD 12

 

100.00%

 

Producing well

WWJD 13

 

40.00%

 

Producing well

WWJD 14

 

40.00%

 

Producing well

WWJD 15

 

40.00%

 

Producing well

WWJD 16

 

100.00%

 

Producing well

WWJD 21

 

40.74%

 

Producing well

WWJD 27

 

100.00%

 

Shut in

WWJD B-1

 

49.50%

 

Producing well

WWJD B-2

 

49.50%

 

Producing well

WWJD B-3

 

49.50%

 

Producing well

WWJD C-1

 

40.00%

 

Producing well

WWJD C-2

 

40.00%

 

Producing well

WWJD C-3

 

40.00%

 

Producing well

WWJD C-4

 

40.00%

 

       Producing well

 

 

 

 

Producing wells

21

 

 

 

 

Shut-in wells

2

 

 

 

 

Total wells

23

 

 

 

 

 

 

Delivery Commitments.


As of July 31, 2017, the Company does not have any delivery commitments for product obtained from its wells.


ITEM 3.

LEGAL PROCEEDINGS.


As of July 31, 2017, the Company was not a party to any litigation.  However, on September 7, 2017, Amazing Energy LLC and Jilpetco Inc. were served with a lawsuit, being 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.


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 following stock quotations reflect the reverse stock split.  The Company also changed its fiscal year end in conjunction with the reverse acquisition from December 31st to July 31st.  All quarters presented below reflect the fiscal year change 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, 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

 

Fiscal Year Ending July 31, 2016

 

 

 

 

 

 

 

 

First quarter ending October 31, 2015

 

$

1.07

 

 

$

0.29

 

Second quarter ending January 31, 2016

 

 

0.35

 

 

 

0.30

 

Third quarter ending April 30, 2016

 

 

0.51

 

 

 

0.30

 

Fourth quarter ending July 31, 2016

 

 

1.06

 

 

 

0.30

 


Shareholders


As of July 31, 2017, there were approximately 773 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 Columbia Stock Transfer Company, 1869 East Seltice Way, Suite 292, Post Falls, Idaho, 83854.


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 no par value per share.


During the year ended July 31, 2016, the Company had the following equity transactions:


Preferred shares issued for debt and interest - On July 31, 2016, the Company issued 9,000 shares of 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 debt payable to JLM Strategic Investments, LP in the amount of $287,303. The stated issue price is at $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, 2016 shall be paid prior to liquidation payments to holders of Company securities junior to the Series A Preferred Stock. On the fifth anniversary of the acquisition of GSSI, 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.  


Shares Issued for services– On November 20, 2015 and January 27, 2016, 50,000 shares of common stock were issued to Delany Equity Group, LLC valued at $0.30 per share, the fair value of the Company’s common stock on the date of issuance, totaling $15,000 for financial consulting services.  On June 27, 2016, 250,000 shares of common stock were issued to Delany Equity Group, LLC and 25,000 shares were issued to Irwin Renneisen valued at $0.34 per share, the fair value of the Company’s common stock on the date of issuance, totaling $93,500 for cost of acquisition of the GSSI.


Shares Issued for cash – On May 16, 2016, the Company began a private placement offering of 20,000,000 restricted shares of common stock at $0.26 per share.  As of July 31, 2016, 699,400 shares had been sold for $181,844.  


Shares Issued for acquisition of GSSIOn July 31, 2016, we issued 5,373,528 restricted shares of our common stock and 2,674,576 stock purchase warrants to Gulf South Holding, Inc. (GSHI) and others in consideration of GSHI transferring to us 100,000 shares of common stock of Gulf South Securities, Inc. (GSSI) which constitutes all of the issued and outstanding shares of common stock of GSSI.


As part of the acquisition of GSSI effective July 31, 2016, the Company issued 50,000 shares of Preferred Series B stock with par value of $0.01 per share.  These preferred shares were issued to Bories Capital, LLC, owned by Robert Bories, an officer of the Company as of July 31, 2016.  Robert Bories is an officer of GSHI and Bories Capital, LLC has released its security interest in the common stock of GSSI. The Series B Preferred Stock has no voting rights other than to be voted when required by Nevada law.  Holders of the Series B 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 $5,000,000 at July 31, 2016 shall be paid prior to liquidation payments to holders of Company securities junior to the Series B Preferred Stock.  Holders of the Company’s Series A Preferred Stock shall be paid in advance of holders of the Series B Preferred Stock on the occurrence of a liquidation event.  On the fifth anniversary of the acquisition of GSSI, any shares of the Series B 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 B Preferred Stock outstanding.  


For each new oil and gas well drilled by the Company with funds raised or delivered due to the efforts of the former GSHI officers, now Company officers, the Company will pay Miesner $10,000 in exchange for 100 shares of Series A Preferred Stock and Bories $10,000 in exchange for 100 shares of Series B Preferred Stock.  In the event that the Company drills wells for its own account the Board of Directors of the Company will decide if such wells qualify for the aforementioned redemption.  The Company will promptly cancel any Series A or B Preferred Stock purchased.


During the year ended July 31, 2017, the Company had the following equity transactions:


Shares Issued for cash - For the year ended July 31, 2017, the Company sold 6,169,084 restricted shares of common stock for $1,603,962 at $0.26 per share pursuant to the terms of a private placement offering (Note 14).  


Cumulatively (including shares sold during fiscal year 2016), as of July 31, 2017, the private placement has sold 6,868,484 restricted shares of common stock for total gross proceeds of $1,785,806. The private placement was terminated on March 31, 2017.


Shares Issued in lieu of cash for services - On January 20, 2017, the Company issued 112,500 restricted shares of common stock for services provided by a vendor.  The shares issued were payment of $32,250 for common stock payable at July 31, 2016 and $12,375 in services for the year ended July 31, 2017. The shares were issued at an average fair value of $0.40 per share.


Other shares issued - On May 31, 2017, the related parties noteholders of notes payable (Note 9) 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 based on the closing share price of $0.23.


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, 2017, 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, 2017, 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.


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.


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.


The Company is no longer active in the gold exploration business.  Kisa Gold Mining, Inc. (“Kisa”), a wholly owned subsidiary of the Company, granted Afranex Gold Limited (“Afranex”) an option to purchase all of the outstanding common stock of Kisa or purchase all of Kisa’s right, title and interest in certain mining permits and associated assets of Kisa. On January 3, 2017, Afranex paid a $50,000 non-refundable option fee to the Company, as consideration for extending the option period to March 31, 2017. Afranex agreed to pay the Company a total of $120,000 in cash consideration to exercise the option.   On March 29, 2017, Afranex exercised the option and paid the Company $120,000 in cash and took transfer of all of Kisa’s right, title and interest in and to all of the mining claims.  For the fiscal year ended July 31, 2017, the Company recognized a gain on sales of mineral rights of $170,000 because the carrying value of the mineral interest was zero. Afranex elected to take possession of the claims by acquiring all of Kisa’s right, title and interest in certain mining permits and associated assets of Kisa. The Company executed a Quitclaim deed with Afranex whereby 38 Kisa claims and 50 Luna claims were conveyed to Afranex.


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 2017 Activity


Our fiscal year 2017 activity focused on conventional drilling in the Queen formation in Pecos County, Texas.  We spudded 1 conventional well and completed 1 well in fiscal 2017, compared to spudding 2 conventional wells and completion of 1 well in fiscal 2016.  We plan to continue to develop the Queen formation in Pecos County, Texas during fiscal 2018.  The rate of drilling wells would depend, to some degree, on raising capital to fund drilling and completion.  Our overall accomplishments in fiscal 2017 include:


·

Production.  Net production for fiscal 2017 totaled 11,820 BOE, compared to 10,978 BOE in fiscal 2016, a 7.7% increase.  Production for fiscal 2017 was 47% oil and 53% natural gas.


·

Completed the acquisition of Jilpetco, Inc. Jilpetco owns a drilling rig, two workover rigs and other equipment and machinery that provide drilling, completion, workover and lease operational services to the wells that Amazing owns in Pecos County, TX. Owning Jilpetco allows the Company to be fully integrated in the process of planning and implementing the steps that are essential in helping us accomplish our workover, drilling, completion and operational goals.  


·

Completed the sale of Kisa’s gold claims to Afranex. The Company plans to dissolve Kisa in Fiscal 2018.


·

For the year ended July 31, 2017, the Company sold 6,169,084 restricted shares of common stock for $1,603,962 at $0.26 per share pursuant to the terms of a private placement offering (Note 11).  Cumulatively (including shares sold in fiscal year 2016), as of July 31, 2017, through the private placement the Company sold 6,868,484 restricted shares of common stock for total gross proceeds of $1,785,806. The private placement was terminated on March 31, 2017.


·

The Company divested a portion of their working interest in the WWJD C wells (C-1, C-2, C-3, C-4) and the WWJD 21 Tank Battery (WWJD 7,10,21) which allowed the Company to de-risk their positions in the wells while also providing working capital.   


·

Electrical service to additional wells was achieved which allowed wells to run pumping units on electricity which is more efficient for production.


·

In July 2017, the Company paid its largest lessors their 5-year prepaid bonuses totaling $200,000 in satisfaction of lease obligations.


In fiscal 2017, our estimated net proved reserves decreased 33.4%, or 249,222 BOE to 495,968 BOE from 745,190 BOE.  Our proved reserves at fiscal year-end 2017 were 62% oil and 38% natural gas, compared to 59% oil and 41% natural gas at year-end 2016.


During Fiscal 2017, our subsidiary Gulf South Securities, Inc. (“GSSI”), was unable to raise drilling capital through offerings of oil and gas limited partnerships. The Company allowed, on February 28, 2017, GSSI’s registration with FINRA to lapse and plans to dissolve GSSI in fiscal 2018.


The Company participated in workovers of all four WWJD C wells which varied from fracking, re-fracking and acidizing the wells. While production was boosted, the daily production for the wells was significantly less than anticipated.  


Plan for Fiscal 2018   


For the fiscal year ending July 31, 2018, 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 2018 depend, to a significant extent, on the future market prices for oil. The Company plans to complete the well that was drilled in 2017 and any wells drilled in 2018 to place those wells into production.


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

Through its wholly owned oilfield services subsidiary, Jilpetco, the Company owns and operates their own rigs and can drill a well in a target pay zone in a shorter amount of time than if relying on third-party drillers. Increasing not only the production and reserves for the Company more efficiently, but also fueling the growth of Jilpetco.

Seeking to Acquire Additional Acreage

Potential pipeline in place to acquire cash flow from producing properties

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.

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, 2017 AND 2016


The following is a summary of the Company’s revenue for the years ended July 31, 2017 and July 31, 2016:


 

 

Year ended July 31,

 

 

 

 

 

 

 

 

 

2017

 

 

2016

 

 

Increase

(Decrease)

 

 

% Change

Oil sales

 

$

219,078

 

 

$

224,997

 

 

$

 (5,919)

 

 

 

 (2.6)

%

Natural gas sales

 

 

57,424

 

 

 

25,479

 

 

 

 31,945

 

 

 

 125.4

%

Field service revenue

 

 

285,277

 

 

 

323,793

 

 

 

 (38,516)

 

 

 

 (11.9)

%

   Total revenue

 

$

 561,779

 

 

$

574,269

 

 

$

 (12,490)

 

 

 

 (2.17)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Our oil and gas revenue increased from $250,476 for the year ended July 31, 2016 to $276,502 for the year ended July 31, 2017, which was an increase of $26,026.  Multiple factors contributed to the increase in oil and gas revenue. Although oil production slightly decreased, our natural gas production increased significantly due to the gas pipeline becoming operational as compared to the prior year’s production.  The average commodity prices for oil and natural gas were improved for fiscal 2017 as compared to than the average price of oil and gas in fiscal 2016.


Field service revenue decreased from $315,480 for fiscal 2016 to $285,277 for fiscal 2017, which was a decrease of $30,203. The decrease in field service revenue was due in part to decreased field services on the properties that it operates and limited drilling and completion work during the fiscal year ending July 31, 2017.


As of July 31, 2017, the Company’s oil and gas production was generated from twenty-three wells with its working interest ownership ranging from 40% to 100%.  Following is a summary of the ownership percentage in these twenty-one producing wells:


  

 

Number of

Producing Wells

 

Wells with 100% working interest ownership

 

 

10

 

Wells with 49.5% working interest ownership

 

 

3

 

Wells with 40.74% working interest ownership

 

 

3

 

Wells with 40% working interest ownership

 

 

7

 

   Total producing wells

 

 

23

 

 

 

 

 

 


The following is a summary of the Company operating expenses for the years ended July 31, 2017 and July 31, 2016:


 

 

Year ended July 31,

 

 

 

 

 

 

 

 

 

2017

 

 

2016

 

 

Increase

(Decrease)

 

% Change

 

Oil and gas production expenses

 

$

245,457

 

 

$

175,105

 

 

$

70,352

 

 

 

 40.2

%

Oilfield service and lease operating expenses

 

 

351,806

 

 

 

282,803

 

 

 

69,003

 

 

 

 24.4

%

Depletion, depreciation and accretion

 

 

310,520

 

 

 

218,005

 

 

 

92,515

 

 

 

 42.4

 

Selling, general and administrative expenses

 

 

822,336

 

 

 

645,125

 

 

 

177,211

 

 

 

 27.5

%

(Gain) on sale of mineral properties

 

 

 (170,000)

 

 

 

 (103,854)

 

 

 

 (66,146)

 

 

 

 63.7

 

   Total operating expenses

 

$

 1,560,119

 

 

$

 1,217,184

 

 

$

 409,081

 

 

 

 33.61

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses increased from $282,803 in fiscal 2016 to $351,806 in fiscal 2017, which is an increase of $69,003.   A major component of the increase was for installation of electricity and the fracking/re-fracking of the WWJD C wells in the fall of 2016.


Selling, general and administrative costs increased from $645,125 incurred in fiscal 2016 compared to $822,336 in fiscal 2017, which is an increase of $177,211.  Several factors contributed to the increase, which include the syndication costs associated with the partnership of Amazing Energy Partners 2016 LP, increased payroll expense, and increased field service related expenses, such as rental expense and field supplies expense.  The Company also incurred additional professional fees associated with its acquisition of Jilpetco, Inc.


Depletion, depreciation and accretion expense increased from $218,005 in fiscal 2016 to $310,520 in fiscal 2017.


Fiscal Year Ended

July 31,

 

Average Price of

Oil Per Barrel

 

Average Price of

Gas per Mcf

 

 

 

 

 

2016

 

$42.46

 

$2.25

2017

 

$48.71

 

$3.01



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 increased from $36.83 in fiscal 2016 to $43.28 in fiscal 2017, which was an increase of $6.45.  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.


Subsequent Events.


Resignation of Officers and Directors.


On August 11, 2017, Jed Miesner resigned as Chief Executive Officer of the Company.


Appointment of Officer and Director.


On August 11, 2017, Willard McAndrew was appointed Chief Executive Officer of the Company.


On August 31, 2017, Willard McAndrew III, Edward Devereaux, and Rolf Berg were elected to the Company’s Board of Directors.


On September 29, 2017, Ira Glasser was appointed our Executive Vice President. Mr. Glasser has entered into an employment agreement with us.  Under the terms of the agreement, Mr. Glasser will be paid a base salary of $175,000 for the first year with annual salary increases of $25,000 for each subsequent year.  Salary will accrue commencing October 1, 2017.  Mr. Glasser will be entitled to monthly bonuses as determined by the Board of Directors.  Further, the Company will issue Mr. Glasser a stock option to acquire up to 4,000,000 shares of the Company's common stock, the terms of which will be evidenced by a separate stock option grant. 


On August 11, 2017, Mr. McAndrew entered into an employment agreement with us, where, among other things, Mr. McAndrew was awarded a signing bonus of $100,000, an annual salary of $250,000 plus a discretionary bonus to be determined by the board of directors, plus the options to acquire up to 15,000,000 shares of our common stock pursuant to two (2) stock option grants for a total of 15,000,000 shares of our common stock. Mr. Andrew’s salary and signing bonus will accrue until certain defined events occur.


On August 11, 2017, Jed Miesner entered into a similar agreement with us, wherein Mr. Miesner was retained by us as our President. Mr. Miesner previously severed as our Chief Executive Officer and will continue to serve as our President. Under our agreement with Mr. Miesner, Mr. Miesner will be paid a signing bonus of $100,000, an annual salary of $250,000 plus a discretionary bonus to be determined by the board of directors, plus the options to acquire up to 5,000,000 shares of our common stock pursuant to one (1) stock option grant for a total of 5,000,000 shares of our common stock. Mr. Meisner’s salary and signing bonus will accrue until certain defined events occur.


On August 11, 2017, Stephen Salgado entered into a similar agreement with us, wherein Mr. Salgado will continue to serve as our Chief Financial Officer. Under our agreement with Mr. Salgado, Mr. Salgado will be paid a signing bonus of $33,000, an annual salary of $125,000 plus a discretionary bonus to be determined by the board of directors, plus the options to acquire up to 1,750,000 shares of our common stock pursuant to one (1) stock option grant for a total of 1,750,000 shares of our common stock. Mr. Salgado’s signing bonus and a portion of his salary will accrue until certain defined events occur.


On August 11, 2017, we engaged Noble Capital Markets, Inc. to provide financial advisory and investment banking services to the Company.


On August 11, 2017, the Board of Directors approved increasing the total number of Director seats to (9) nine.


On August 14, 2017, we retained MZHCI, LLC, a MZ Group Company, as our investor relations advisor.


On September 26, 2017, the Board of Directors approved the grant of 1,000,000 share purchase warrants and 500,000 stock options in aggregate to various members of the Board of Directors, consultants and employees.  The share purchase warrants and stock options have an exercise price of $0.40 per and have a four-year term.  


On October 1, 2017, Jilpetco Inc. executed a purchase agreement with National Crude Marketing, LLC (NCM) for NCM to purchase oil for all Pecos County, Texas properties. NCM replaced Sunoco Inc. as the crude purchaser.   


LIQUIDITY AND CAPITAL RESOURCES


Our primary financial 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.


The changes in our capital resources are set forth in the table below:

 

 

July 31, 2017

 

 

July 31, 2016

 

 

Increase

(Decrease)

 

 

% Change

 

Cash

 

$

 756,603

 

 

$

 344,777

 

 

$

 411,826

 

 

 

119.4

%

Current assets

 

 

 928,739

 

 

 

 585,990

 

 

 

 342,749

 

 

 

58.5

%

Total assets

 

 

 7,470,255

 

 

 

 7,248,398

 

 

 

 221,857

 

 

 

3.1

%

Current liabilities

 

 

 1,747,819

 

 

 

 1,209,318

 

 

 

 538,501

 

 

 

44.5

%

Total liabilities

 

 

 4,616,474

 

 

 

 2,995,133

 

 

 

 1,621,341

 

 

 

54.1

%

Working capital (deficit)

 

$

 (819,080)

 

 

$

 (623,328)

 

 

$

 (195,752)

 

 

 

31.4

%)


Our working capital decreased by $195,752 from July 31, 2016 to July 31, 2017.  The primary reasons for this decrease are as follows:  

1)

Cash increased by $411,826

2)

Oil and gas receivables decreased by $2,858

3)

Interest payable, related parties increased by $223,685.

4)

Current portion of convertible debt, related party increased by $101,387

5)

Current portion of notes payable on acquisition, related party increased by $104,167

6)

Equipment note payable, current portion increased by $10,006


We intend on improving our working capital position by reworking some of our existing wells, completing wells that have been drilled, and continuing to raise investor capital in order to drill additional wells by July 31, 2018.   


Our business is very capital intensive and we are dependent on raising the requisite drilling capital through various investors.  In turn, these capital raises are highly dependent upon the prices of oil and gas.  There is no assurance that we will be able to raise sufficient drilling funds, and therefore, there is no assurance that we will be able to achieve profitability.  


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, 2017

 

 

July 31, 2016

 

 

Increase

(Decrease)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash used in operating activities

 

$

 (961,340)

 

 

$

 (753,978)

 

 

$

 (207,362)

 

Net cash provided by (used in) investing activities

 

$

 5,543

 

 

$

 (270,918)

 

 

$

 276,461

 

Net cash provided by financing activities

 

$

 1,367,623

 

 

$

 394,094

 

 

$

 973,529

 


CASH FLOW PROVIDED BY (USED IN) OPERATING ACTIVITIES


Cash flow from operating activities is derived from the production out of oil and gas production and sales, plus changes in the balances of non-cash accounts, receivables, payables, or other account balances.  For the year ended July 31, 2017, cash used by operating activities was $961,340 in comparison to cash used by operating activities in the amount of $753,978 for the year ended July 31, 2016.  This increase in cash used by operating activities of $207,362 was primarily due to losses from operations, resulting from prolonged low oils prices and decrease in production.  


CASH FLOW (USED IN) INVESTING ACTIVITIES


Cash flow from investing activities is primarily derived from changes in oil and gas properties.  The Company sold their rights to gold claims for $170,000 and certain working interests in oil and gas properties for $656,596 during the year ended July 31, 2017.  This essentially offset development and acquisition costs for oil and gas properties of $562,155 and purchase of property and equipment of $212,898.  


OIL AND GAS RESERVES


The company’s total net proved developed and undeveloped oil and gas reserves and related values are summarized in the following table:


 

 

Net Reserves

 

 

Cash Flows

 

 

 

Oil

(BO)

 

 

Gas

(Mcf)

 

 

Non

Discounted

 

 

Discounted

at 10%

 

As of July 31, 2017

 

 

305,440

 

 

 

1,143,170

 

 

$

9,722,900

 

 

$

7,052,380

 

As of July 31, 2016

 

 

436,980

 

 

 

1,849,260

 

 

$

9,787,960

 

 

$

7,324,060

 


Even though the quantities of the oil and gas net reserves have decreased from July 31, 2016 to July 31, 2017, the projected cash flows slightly decreased because the prices for the analysis as of July 31, 2016 were based upon oil at $42.46 per barrel and gas at $2.25 per MMBTU and the reserve analysis was based on oil prices at $48.71 per barrel and gas at $3.01 per MMBTU at July 31, 2017.


CHANGES IN FINANCIAL CONDITION


As of, July 31, 2017 our total assets were $7,470,255 compared to total assets of $7,248,398 as of July 31, 2016, for an increase of $221,857.


At July 31, 2017, total liabilities were $4,616,474 an increase of $412,023 in comparison to $4,204,451 at July 31, 2016.  Long-term debt remained stable; however most of the increase in total liabilities was attributable to the increase in current liabilities, specifically short-term notes payable, related parties, note payable to a related party with respect to the acquisition of Jilpetco, and additional current portion of convertible debt, related party.


Our common stock increased from 59,839,456 outstanding shares as of July 31, 2016 to 66,581,040 outstanding shares at July 31, 2017.  The primary reason for this increase in the number of outstanding shares of common stock was the sale of the Company’s shares in a private placement closed during fiscal 2017.


The accumulated deficit increased from $24,655,439 as of July 31, 2016, to $26,028,247 as of July 31, 2017.  


MINING OPERATIONS:


We were also in the business of exploration, development, and if warranted the mining of properties containing valuable mineral deposits.  The focus of our exploration programs was directed at precious metals; primarily gold.  We no longer continue to identify, investigate, acquire or develop properties.  We have disposed of all our mining claims and suspended all our mining operations in lieu of our oil and gas operations.


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-6



-14-



dm-t   decoria-maichel-teague

Certified Public Accountants

7307 N Division, Suite 222

Spokane, WA 99208


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and

Stockholders of Amazing Energy Oil and Gas, Co.


We have audited the accompanying consolidated balance sheets of Amazing Energy Oil and Gas, Co. (“the Company”) as of July 31, 2017 and 2016, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.


In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Amazing Energy Oil and Gas, Co. as of July 31, 2017 and 2016, and the results of its operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.


The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has accumulated losses since inception and has negative working capital. 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.



[f20170731amaz10kdonenomor003.gif]

DeCoria, Maichel & Teague P.S.

Spokane, Washington


November 13, 2017



Table of Contents              

The accompanying notes are an integral part of these financial statements.

See Note 1 for information regarding recast amounts and basis of financial statement presentation.






PART I   

ITEM 1.

FINANCIAL STATEMENTS.


AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

July 31, 2017

 

 

July 31, 2016

ASSETS

 

 

 

 

(Recast)

CURRENT ASSETS:

 

 

 

 

 

 

Cash and cash equivalents

$

 756,603

 

$

 344,777

 

Oilfield service receivable

 

 64,392

 

 

 71,342

 

Oilfield service receivable, related party, net of allowance for bad debt of $31,404 and      $Nil

 

-

 

 

 71,745

 

Oil and gas receivables

 

 39,901

 

 

 37,043

 

Prepaid expenses and other current asset

 

 67,843

 

 

 61,083

 

 

TOTAL CURRENT ASSETS

 

928,739

 

 

585,990

 

Property and equipment, net of accumulated depreciation of $306,392

and $192,403

 

545,812

 

 

399,077

OIL AND GAS PROPERTIES, Full Cost Method

 

 

 

 

 

 

Evaluated properties, net of accumulated depletion of $1,179,955 and $997,986

 

5,919,082

 

 

6,236,709

Other assets and restricted cash

 

76,622

 

 

26,622

 

 

TOTAL ASSETS

$

7,470,255

 

$

7,248,398

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

Accounts payable

$

 77,618

 

$

 167,141

 

Accrued liabilities

 

62,203

 

 

 39,482

 

Revenue payable to interest owners

 

 421,423

 

 

 422,865

 

Interest payable, related parties

 

 244,009

 

 

 20,324

 

Current portion of convertible debt, related party

 

 430,892

 

 

 329,506

 

Note payable on acquisition, related party

 

 104,167

 

 

 -   

 

Note payable

 

 50,000

 

 

 -   

 

Notes payable, related parties

 

 347,500

 

 

 180,000

 

Line of credit

 

 -   

 

 

 50,000

 

Equipment note payable, current portion

 

  10,006

 

 

 -   

 

 

TOTAL CURRENT LIABILITIES

 

1,747,818

 

 

1,209,318

LONG TERM LIABILITIES:

 

 

 

 

 

 

Asset retirement obligation

 

 183,397

 

 

 211,218

 

Equipment note payable, net of current portion

 

34,981

 

 

 -   

 

Common stock payable

 

 -   

 

 

 32,250

 

Convertible debt, related party, net of current portion

 

2,650,278

 

 

 2,751,665

 

 

TOTAL LONG-TERM LIABILITIES

 

2,868,656

 

 

2,995,133

 

 

 

TOTAL LIABILITIES

 

4,616,474

 

 

4,204,451

COMMITMENTS AND CONTINGENCIES (Note 10)

 

 

 

 

 

STOCKHOLDERS’ EQUITY:

 

 

 

 

 

 

Preferred stock, no par value, 10,000,000 shares authorized,

no shares issued and outstanding

 

 

 

 

 

 

Series A Preferred Stock, $0.01 par value, 9,000 shares issued and outstanding, liquidation preference $900,000

 

90

 

 

 90

 

Series B Preferred Stock, $0.01 par value, 50,000 shares issued and outstanding, liquidation preference $900,000

 

500

 

 

 500

 

Common stock, $0.001 par value, 3,000,000,000 shares

authorized, 66,581,040 and 59,839,456 issued and outstanding

 

66,581

 

 

 59,840

 

Additional paid-in capital

 

 28,814,857

 

 

 27,638,956

 

Accumulated deficit

 

 (26,028,247)

 

 

 (24,655,439)

 

 

TOTAL STOCKHOLDERS’ EQUITY

 

2,853,781

 

 

3,043,947

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

$

7,470,255

 

$

7,248,398

 

 

 

 

 

 

 

 

 



Table of Contents

The accompanying notes are an integral part of these financial statements

See Note 1 for information regarding recast basis of financial statement presentation.

-16-



AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS





 

 

 

 

 

July 31, 2017

 

 

July 31, 2016

REVENUE

 

 

 

 

(Recast)

 

Oilfield service revenue

$

 285,277

 

$

 323,793

 

Oil and gas sales

 

 276,502

 

 

 250,476

 

 

TOTAL GROSS REVENUE

 

561,779

 

 

574,269

OPERATING EXPENSE

 

 

 

 

 

 

Oil and gas production expenses

 

 245,457

 

 

 175,105

 

Oilfield service and lease operating expenses

 

 351,806

 

 

 282,803

 

Selling, general and administrative expenses

 

 822,336

 

 

 645,125

 

Depreciation expense

 

 119,155

 

 

 80,192

 

Depletion expense

 

 181,969

 

 

 124,959

 

Accretion expense

 

 9,396

 

 

 12,854

 

Gain on sale of leasehold mineral rights

 

 (170,000)

 

 

 (103,854)

 

 

TOTAL OPERATING EXPENSES

 

1,560,119

 

 

1,217,184

LOSS FROM OPERATIONS

 

(998,340)

 

 

(642,915)

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

Interest income

 

3,175

 

 

2,054

 

Financing fees associated with debt modification

 

(105,800)

 

 

-

 

Impairment of goodwill

 

-

 

 

(5,975,836)

 

Interest expense

 

(7,276)

 

 

(2,109)

 

Interest expense, related parties

 

(264,567)

 

 

(290,046)

 

 

TOTAL OTHER INCOME (EXPENSE)

 

(374,468)

 

 

(6,265,937)

NET INCOME (LOSS) BEFORE INCOME TAXES

 

(1,372,808)

 

 

(6,908,852)

 

Income tax provision (Note 12)

 

-

 

 

-

NET INCOME (LOSS)

 

(1,372,808)

 

 

(6,908,852)

 

Deemed capital distribution on acquisition of common control entity

 

(423,648)

 

 

-

 

Deemed capital contribution on exchange of related party debt and interest for preferred stock

 

-

 

 

454,265

NET LOSS AVAILABLE TO COMMON STOCKHOLDERS

$

(1,796,456)

 

$

(6,454,587)

NET LOSS PER COMMON SHARE, Basic and diluted

$

(0.03)

 

$

(0.12)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING – basic and diluted

 

64,437,390

 

 

53,464,977

 

 

 

 

 

 



Table of Contents              

The accompanying notes are an integral part of these financial statements.

See Note 1 for information regarding recast amounts and basis of financial statement presentation.



AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS






 

 

Year Ended July 31,

 

 

2017

 

2016

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

(Recast)

Net loss

$

(1,372,808)

$

(6,908,852)

Adjustments to reconcile net loss to net cash (used) by operating activities:

 

 

 

 

 

Common stock issued for services

 

12,375

 

 108,500

 

Gain on sale of leasehold and mineral rights

 

 (170,000)

 

 (100,772)

 

Gain on sale of equipment

 

 

 

 (3,080)

 

Bad debt expense

 

 31,404

 

 -   

 

Depreciation expense

 

 119,155

 

 80,192

 

Depletion expense

 

 181,969

 

 124,959

 

Accretion expense

 

 9,396

 

 12,854

 

Impairment of goodwill

 

 -   

 

 5,975,836

 

Financing fees associated with debt modification

 

 105,800

 

 -   

Changes in operating assets and liabilities

 

 

 

 

 

Oilfield service receivable

 

 6,950

 

 181,546

 

Oilfield service receivable, related party

 

 (31,404)

 

 -   

 

Oil and gas receivable

 

 (2,858)

 

 68,727

 

Prepaid expenses and other current asset

 

 (6,760)

 

 (29,605)

 

Accounts payable

 

 (89,523)

 

 (100,959)

 

Revenue payable to interest owners

 

 (1,442)

 

 (393,935)

 

Accrued liabilities

 

22,721

 

 (59,191)

 

Interest payable, related parties

 

 223,685

 

 289,802

 

 

NET CASH USED IN OPERATING ACTIVITIES

 

(961,340))

 

(753,978)

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Proceeds from sale of leasehold and mineral rights

 

 170,000

 

 -   

 

Proceeds from sale of working interests, oil and gas properties

 

 656,596

 

 -   

 

Net cash acquired (advanced) in acquisition of companies

 

 -   

 

 (900)

 

Proceeds from sale of property and equipment

 

 4,000

 

 21,000

 

Purchase of secured letter of credit, restricted

 

 (50,000)

 

 -   

 

Acquisition of property and equipment

 

 (212,898)

 

 (5,435)

 

Acquisition of oil and gas properties

 

 (562,155)

 

 (285,583)

 

 

NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES

 

5,543

 

(270,918)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Proceeds from sale of common stock

 

 1,603,961

 

181,844

 

Common stock payable

 

-

 

32,250

 

Payments on equipment note payable

 

 (8,005)

 

-

 

Proceeds from note payable

 

 50,000

 

-

 

Advances from line of credit  

 

 175,000

 

-

 

Payments on line of credit  

 

 (225,000)

 

-

 

Payments on notes payable, related parties

 

 (57,500)

 

-

 

Proceeds from notes payable, related parties

 

 225,000

 

180,000

 

Payments on notes payable on acquisition, related party

 

 (395,833)

 

-

 

 

NET CASH PROVIDED BY FINANCING ACTIVITIES

 

1,367,623

 

394,094

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

411,826

 

(630,802)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

 

344,777

 

975,579

CASH AND CASH EQUIVALENTS AT END OF YEAR

$

756,603

$

344,777

NON-CASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

Interest paid in cash

$

27,834

$

-   

 

Equipment acquired with note payable

 

52,992

 

-

 

Deemed capital distribution on acquisition of common control entity (Note 1)

 

423,648

 

 

 

Acquisition of common control entity in exchange for related party note and oilfield services receivable, related party (Note 6)

 

571,745

 

-

 

Common stock issued for common stock payable

 

32,250

 

-   

 

Preferred series A shares issued for conversion of debt and accrued interest (Note 8)

 

-

 

900,000

 

Acquisition of subsidiary through issuance of common stock, stock purchase warrants, and preferred stock (Note 7)

 

-

 

5,974,914



Table of Contents

The accompanying notes are an integral part of these financial statements

See Note 1 for information regarding recast basis of financial statement presentation.

-18-



AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY




 

Preferred Stock

 

Common Stock

 

Additional

Paid-In

 

Accumulated

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Capital

 

Deficit

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCES, JULY 31, 2015 Prior to recast

--

$

-

 

53,441,528

$

53,442

$

20,480,686

$

(18,490,545)

$

2,043,583

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Jilpetco net assets at August 1, 2015

 

 

 

 

 

 

 

 

 

 

743,958

 

743,959

BALANCE, JULY 31, 2015 After recast

 

 

 

 

53,441,528

 

53,442

 

20,480,686

 

(17,746,587)

 

2,787,542

 

Common shares issued for services

-

 

-

 

50,000

 

50

 

14,950

 

-

 

15,000

 

Common shares issued for acquisition

of Gulf South Securities, Inc. (“GSSI”)

-

 

-

 

5,373,528

 

5,374

 

2,434,209

 

-

 

2,439,583

 

Warrants issued for acquisition of GSSI

-

 

-

 

-

 

-

 

1,058,528

 

-

 

1,058,528

 

Common shares issued for cost of acquisition of GSSI

-

 

-

 

275,000

 

275

 

93,225

 

-

 

93,500

 

Preferred series B shares issued for

acquisition of GSSI

50,000

 

500

 

-

 

-

 

2,476,303

 

-

 

2,476,803

 

Preferred series A shares issued for

conversion of debt and interest

9,000

 

90

 

-

 

-

 

445,645

 

-

 

445,735

 

Deemed capital contribution on the

exchange of related party debt and interest

-

 

-

 

-

 

-

 

454,265

 

-

 

454,265

 

Common shares issued for cash

-

 

-

 

699,400

 

699

 

181,145

 

-

 

181,844

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss for the year ended July 31, 2016

-

 

-

 

-

 

-

 

-

 

(6,908,852)

 

(6,908,852)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCES, July 31, 2016

59,000

$

590

 

59,839,456

$

59,840

$

27,638,956

$

(24,655,439)

$

3,043,947

 

Acquisition of common control entity

-

 

-

 

 

 

 

 

(571,745)

 

 

 

(571,745)

 

Common shares issued for common stock payable

-

 

-

 

80,875

 

81

 

32,169

 

-

 

32,250

 

Common shares issued for services

-

 

-

 

31,625

 

31

 

12,344

 

-

 

12,375

 

Common shares issued for cash

-

 

-

 

6,169,084

 

6,169

 

1,597,793

 

-

 

1,603,962

 

Common shares issued for modification of debt

-

 

-

 

460,000

 

460

 

105,340

 

-

 

105,800

 

Net loss for the year ended July 31, 2017

-

 

-

 

-

 

-

 

-

 

 (1,372,808)

 

(1,372,808)

BALANCES, July 31, 2017

59,000

$

590

 

66,581,040

$

66,581

$

28,814,857

$

(26,028,247)

$

2,853,781

 

 

 

 

 

 

 

 

 

 

 

 

 

 




Table of Contents

The accompanying notes are an integral part of these financial statements

See Note 1 for information regarding recast basis of financial statement presentation.

-19-



AMAZING ENERGY OIL AND GAS, CO. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

JULY 31, 2017



NOTE 1 – NATURE OF OPERATIONS


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. was formed in 2010 as a Texas corporation and then changed its domicile 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.


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 April 15, 2016, the Company entered into an agreement with Jed Miesner, the Chairman of the Company’s board of directors, to acquire all of his interest (100% of the total outstanding shares of common stock) of Jilpetco, Inc., a Texas corporation (“Jilpetco”) in consideration of $500,000. Jilpetco is engaged in the business of operating and providing oilfield services to oil and gas properties. As a result, Jilpetco became a wholly owned subsidiary corporation of the Company. On August 25, 2016, the foregoing agreement was amended to extend the closing date to August 31, 2016 and exclude certain property therefrom. The parties agreed to allow Jed Miesner to assign certain accounts receivable and to exclude certain personal property from the transaction. In addition, the $500,000 consideration for the acquisition is in the form of a note payable at 6% interest. (See Note 6).


Effective August 31, 2016, the Company completed the acquisition of Jilpetco. As the Company and Jilpetco were under common control at the time of the acquisition, it is required under U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) to account for this common control acquisition similar to the pooling of interest method of accounting. Under this method of accounting, the Company’s Consolidated Financial Statements as of July 31, 2016 have been recast to reflect Jilpetco’s historical book basis in its assets and liabilities instead of reflecting the fair value of the assets and liabilities. The historical balances reflected herein have been adjusted and recast as if the entities had been combined as of July 31, 2015. The difference between the purchase price and historical cost of the net assets acquired was recorded as a deemed capital distribution of $423,648 as of August 1, 2016.  Intercompany balances and transactions between the entities are eliminated in consolidation of the financial statements.


NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES


Basis of presentation


This summary of significant accounting policies is presented to assist in understanding the financial statements. The financial statements and notes are representations of the Company’s management, which is responsible for their integrity and objectivity. These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States.


The financial statements are presented on a consolidated basis and include all of the accounts of Amazing Energy Oil and Gas, Co. and its wholly owned subsidiaries, Amazing Energy, Inc., Amazing Energy LLC, Kisa Gold Mining, Inc., Gulf South Securities, Inc. and Jilpetco, Inc.  All significant intercompany balances and transactions have been eliminated.


Going Concern


These consolidated financial statements have been prepared in accordance with generally U.S. GAAP to a going concern, which assumes that the Company will be able to meet its obligations and continue its operations for its next fiscal year.


As shown in the accompanying financial statements, the Company has incurred operating losses since inception. As of July 31, 2017, the Company has limited financial resources with which to achieve the objectives and obtain profitability and positive cash flows. As shown in the accompanying consolidated balance sheets and statements of operations, the Company has an accumulated deficit of $26,028,247.  At July 31, 2017, the Company's working capital deficit was $819,079. Achievement of the Company's objectives will be dependent upon the ability to obtain additional financing, to locate profitable mining properties and generate revenue from current and planned business operations, and control costs. The Company plans to fund its future operations by joint venturing, obtaining additional financing from investors, and/or lenders, and attaining additional commercial production. However, there is no assurance that the Company will be able to achieve these objectives, therefore substantial doubt about its ability to continue as a going concern exists.  Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful.  The financial statements do not include adjustments relating to the recoverability of recorded assets nor the implications of associated bankruptcy costs should the Company be unable to continue as a going concern.


Revenue and Cost Recognition


The Company uses the sales method of accounting for oil and gas revenues. Under this method, revenues are recognized based on the actual volumes of gas and oil sold to purchasers. The volume sold may differ from the volumes the Company may be entitled to, based on the Company’s individual interest in the property. Periodically, imbalances between production and nomination volumes can occur for various reasons. In cases where imbalances have occurred, a production imbalance receivable or liability will be recorded when determined. Costs associated with production are expensed in the period in which they are incurred.


The Company also provides oilfield services to both related party entities and outside oil and gas well owners.  Revenue and costs are recognized on an accrual basis and associated revenue and expense recognized in the period in which service was provided.  


Receivables


Oilfield service receivables are carried at original invoice amount less an estimate for doubtful accounts. Management determines the allowance by regularly evaluating individual customer receivables and considering a customer’s financial condition, credit history and current economic conditions. Receivables are written off when deemed uncollectible. Recoveries of receivables previously written off are recorded as income when received.


Oil and gas receivable consist of oil and natural gas revenues due under normal trade terms. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. As of July 31, 2017, management estimated uncollectable accounts at $31,404.  As of July 31, 2016, no  allowance was considered necessary.


Revenue payable to interest holders


The Company provides oilfield services which includes interest owner accounting and subsequent disbursement of the interest owners’ pro-rata share of oil proceeds from a given lease.  Generally, the pro-rata share of oil proceeds less any applicable pro-rata share of operating expenses is distributed to the interest owner within two months of sale of oil and natural gas.  The revenue payable liability comprises those proceeds which have yet to be distributed to interest owners as a result of the time required to process administrative functions and process payment.   


Asset Retirement Obligations


The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company depletes the amount added to proved oil and gas property costs and gathering assets using the units-of-production method. The Company's asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties and gathering assets. The asset retirement liability is allocated to operating expense using a systematic and rational method


Use of estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and certain assumptions that affect the amounts reported in these consolidated financial statements and accompanying notes. Management’s estimates include estimates of impairment in carrying value of assets and liabilities, and collectability of recorded oilfield services receivables, stock based compensation, deferred income taxes, asset retirement obligations, oil and gas property ceiling tests, and depreciation, depletion and amortization. Actual results could differ from these estimates.


Risks and uncertainties

The Company’s operations are subject to significant risks and uncertainties, including financial, operational, technological, and other risks associated with operating an emerging oil and gas business, including the potential risk of business failure.


Concentration of risks

The Company’s cash is placed with a highly rated financial institution, and the Company periodically reviews the credit worthiness of the financial institutions with which it does business. At times, the Company’s cash balances are in excess of amounts guaranteed by the Federal Deposit Insurance Corporation.


The Company’s oil and gas revenue originated from production from its property in Texas.  Each revenue stream is sold to a single customer through month to month contracts.  While this creates a customer concentration, there are alternate buyers of the production in event the sole customer is unable or unwilling to purchase.


The Company sells most of its production to only two customers. As a result, during the fiscal years ended July 31, 2017 and 2016, these customers represented 50% or more of its oil and gas revenue (“major customers”).


Cash and Cash Equivalents


The Company considers all highly liquid investments purchased with a remaining maturity of three months or less when acquired to be cash equivalents.


Restricted Cash


As of July 31, 2017, the Company has a letter of credit in the amount of $50,000 in favor of the Texas Railroad Commission as a bond for reclamation on its oil and gas properties.


Income Taxes


The Company accounts for income taxes using the liability method. The liability method requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of (i) temporary differences between financial statement carrying amounts of assets and liabilities and their basis for tax purposes and (ii) operating loss and tax credit carry-forwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when management concludes that it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.


Fair value of financial instruments


Financial instruments consist of cash and various notes payable. The estimated fair value of convertible debt, related party approximates $5.4 million at July 31, 2017 based on its common stock equivalents and exchange trading price.


Property, plant, and equipment


Property, plant, and equipment are stated at cost. Improvements which significantly increase an asset’s value or significantly extend its useful life are capitalized and depreciated over the asset’s remaining useful life. When property, plant or equipment is sold at a price either higher or lower than its carrying amount, or un-depreciated cost at the date of disposal, the difference between the sale proceeds over the carrying amount is recognized as gain, while a loss is recognized when the carrying amount exceeds the sale proceeds. Property, plant, and equipment are depreciated on a straight-line basis over their useful lives, which are typically five to seven years for equipment.


Oil and gas properties


The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological, and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company allocates a portion of its acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated over the life of the reservoir.


Depletion and amortization


The depletion base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, and amortization (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depletion base of oil and natural gas properties is amortized on a units-of-production method.


Long-Lived Assets


The Company reviews long-lived assets which include property, plant and equipment and oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Events relating to recoverability may include significant unfavorable changes in business conditions or a forecasted inability to achieve break-even operating results over an extended period. The Company evaluates the recoverability of long-lived assets based upon forecasted undiscounted cash flows and reports any impairment at the lower of the carrying amount or the fair value less costs to sell.


Ceiling test


Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax affects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The ceiling test calculation uses a commodity price assumption, which is based on an un-weighted arithmetic average of the price on the first day of each month for each month within the prior 12-month period and excludes future cash outflows related to estimated abandonment costs. The Company did not recognize impairment on its oil and gas properties during the years ended July 31, 2017 and 2016. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that a write-down could occur. Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. The independent engineering estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.


The determination of oil and gas reserves is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent re- evaluation of reserves and cost estimates related to future development of proved oil and gas reserves could result in significant revisions to proved reserves. There other issues, such as changes in regulatory requirements, technological advances, and other factors, which are difficult to predict, could also affect estimates of proved reserves in the future.


Gains and losses on the sale of oil and gas properties are not generally reflected in income. Sales of less than 100% of the Company’s interest in the oil and gas property are treated as a reduction of the capital cost of the field, with no gain or loss recognized, as long as doing so does not significantly affect the unit-of-production depletion rate. Costs of retired equipment, net of salvage value, are usually charged to accumulated depreciation.


Stock-based compensation


Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award.


Environmental laws and regulations


The Company is subject to extensive federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The Company believes that it is in compliance with existing laws and regulations.


Fair value measurements


When required to measure assets or liabilities at fair value, the Company uses a fair value hierarchy based on the level of independent, objective evidence surrounding the inputs used.  The Company determines the level within the fair value hierarchy in which the fair value measurements in their entirety fall.  The categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  Level 1 uses quoted prices in active markets for identical assets or liabilities, Level 2 uses significant other observable inputs, and Level 3 uses significant unobservable inputs.  The amount of the total gains or losses for the period are included in earnings that are attributable to the change in unrealized gains or losses relating to those assets and liabilities still held at the reporting date.  At July 31, 2017 and July 31, 2016, the Company had no assets or liabilities accounted for at fair value on a recurring basis.


Recent accounting pronouncements


In August 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-15, “Presentation of Financial Statements – Going Concern”. The provisions of ASU No. 2014-15 require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated, and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). The amendments in this ASU are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter.  This ASU was adopted effective August 1, 2016 and did not have an effect on the Company’s consolidated financial statements.


In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09), which supersedes the revenue recognition requirements in FASB Accounting Standards Codification (ASC) Topic 605, “Revenue Recognition”. The guidance requires that an entity recognize revenue in a way that depicts the transfer of promised goods or services to customers in the amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods and services. The guidance will be effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. The Company is currently evaluating the new standard and its impact on the Company’s consolidated financial statements.

 

In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) No. 2015-17 Income Taxes - Balance Sheet Classification of Deferred Taxes (Topic 740). The update is designed to reduce complexity of reporting deferred income tax liabilities and assets into current and non-current amounts in a statement of financial position. ASU No. 2015-17 requires the presentation of deferred income taxes, changes to deferred tax liabilities and assets be classified as non-current in the statement of financial position. The update is effective for fiscal years beginning after December 15, 2016.  The adoption of this update on August 1, 2017 had no impact on the consolidated financial statements.


In March 2016, the FASB issued ASU No. 2016-09 Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The update simplifies the accounting for stock-based compensation, including income tax consequences and balance sheet and cash flow statement classification of awards. The update is effective for fiscal years beginning after December 15, 2016, with early adoption permitted.  The Company is currently considering the effects of adoption of this ASU.


In August 2016, the FASB issued ASU No. 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The update provides guidance on classification for cash receipts and payments related to eight specific issues. The update is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the impact of implementing this update on the consolidated financial statements.


In January 2017, the FASB issued ASU No. 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The update is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company will apply the provisions of the update to potential future acquisitions occurring after the effective date.


Other accounting standards that have been issued or proposed by FASB that do not require adoption until a future date are not expected to have a material impact on the consolidated financial statements upon adoption. The Company does not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to its financial condition, results of operations, cash flows or disclosures.


NOTE 3 – EARNINGS PER SHARE


Basic Earnings Per Share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares outstanding during the period and includes no dilution.  Diluted EPS reflects the potential dilution of securities that could occur from common shares issuable through convertible debt, convertible preferred stock and warrants.


The outstanding securities at July 31, 2017 and 2016, that could have a dilutive effect are as follows:

 

July 31, 2017

 

 

July 31, 2016

 

Conversion option on related party debt

 

12,661,985

 

 

 

11,832,724

 

Convertible preferred stock

 

6,490,000

 

 

 

6,490,000

 

Warrants

 

2,674,576

 

 

 

2,674,576

 

Total potential dilution

 

21,826,561

 

 

 

20,997,300

 

 

 

 

 

 

 

 

 


For the years ended July 31, 2017 and 2016,  the effect of this potential dilution has not been recognized since it  would have been anti-dilutive.


NOTE 4 – PROPERTY AND EQUIPMENT


As of July 31, 2017 and July 31, 2016, the property and equipment asset balance was composed of the following:


 

July 31, 2017

 

 

July 31, 2016  

 

 

 

 

 

 

 

(Recast)

 

Drilling equipment

$

 600,000

 

 

$

 425,000

 

Other equipment

 

 252,204

 

 

 

 166,480

 

Less: Accumulated depreciation

 

 (306,392)

 

 

 

 (192,403)

 

Total property and equipment

$

 545,812

 

 

$

 399,077

 

 

 

 

 

 

 

 

 


NOTE 5 – OIL AND GAS PROPERTIES  


The Company is currently participating in oil and gas exploration activities in Texas. The Company’s oil and gas properties are located entirely in the United States.


The Company has leasehold rights located within approximately 70,000 contiguous acres in Pecos County, Texas, which lies within the Permian Basin. The property is located in the Northeast region of the County. The Pecos leasehold is comprised of multiple leases, and the Company has a variable working interest in twenty-three wells on these leases. The Company has drilled twenty-three wells throughout this property, with twenty-one producing and two shut-in. The oil and gas property balances at July 31, 2017 and July 31, 2016 are set forth in the table below:


 

July 31, 2017

 

 

July 31, 2016

 

 

 

 

 

 

 

(Recast)

 

Proved leasehold costs

$

 2,049,593

 

 

$

 2,477,079

 

Cost of wells and development

 

 4,920,558

 

 

 

 4,591,513

 

Asset retirement obligation, asset

 

 128,886

 

 

 

 166,103

 

 Total cost of oil and gas properties

 

 7,099,037

 

 

 

 7,234,695

 

Less: Accumulated depletion

 

 (1,179,955

)

 

 

 (997,986

)

Oil and gas properties, net full cost method

$

 5,919,082

 

 

$

 6,236,709

 

 

 

 

 

 

 

 

 

For the year ended July 31, 2017, the Company has sold an 11% working interest in four wells and a 60% working interest in three wells for a total of $656,596 in cash to Gulf South Energy Partners, a related entity controlled by Robert Bories, a member of the Company’s Board of Directors.  The sale of working interests in seven wells resulted in a reduction in oil and gas properties of $656,596 for the year ended July 31, 2017.  Gain or loss was not recognized on this sale since the sale did not significantly alter the relationship between capitalized costs and proved reserves.

 

NOTE 6 – COMMON CONTROL ACQUISITION OF JILPETCO, INC.


On April 15, 2016, the Company entered into an agreement with Jed Miesner, the Chairman of the Company’s Board of Directors, to acquire all of his interest (100% of the total outstanding shares of common stock) in Jilpetco, Inc., a Texas corporation (“Jilpetco”) in consideration of $500,000.  Jilpetco is engaged in the business of operating and providing oilfield services to oil and gas properties, including the Company’s.


On August 25, 2016, the foregoing agreement was amended to extend the closing date to August 31, 2016 and exclude certain property therefrom. The parties agreed to allow Jed Miesner to exclude certain oilfield service receivables for $71,745 from the transaction. In addition, the $500,000 in additional consideration for the acquisition was in the form of a note payable at 6% interest calling for monthly payments of principal and interest totaling $511,962 and maturing on December 25, 2017 (Note 8 – Notes Payable, Related Parties).  The Note called for five monthly payments of $50,752.49 commencing on September 25, 2016, and twelve payments of $21,517 commencing on January 25, 2017.


The Company completed the acquisition of Jilpetco on August 31, 2016 (Note 1 - Nature of Operations).  As the Company and Jilpetco were under common control at the time of the acquisition, the results of operations have been combined (recast) for the Company and Jilpetco as of August 1, 2015.


Separate results for the Company and Jilpetco for the year ended July 31, 2017 and 2016 were as follows:


 

Year ended July 31, 2017

 

Year ended July 31, 2016

 

Amazing

 

Jilpetco

 

Total

 

Amazing

 

Jilpetco

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

$

 276,502

 

$

 285,277

 

$

 561,779

 

$

 250,476

 

$

 323,793

 

$

 574,269

   Depreciation, depletion and accretion

 

(187,793)

 

 

 (113,331)

 

 

  (301,124)

 

 

 (130,796)

 

 

 (74,355)

 

 

 (205,151)

Other Operating Expenses

 

 (814,359)

 

 

 (435,240)

 

 

 (1,249,599)

 

 

 (847,997)

 

 

 (164,036)

 

 

 (1,012,033)

   Loss from operations

 

 (735,046)

 

 

 (263,294)

 

 

 (998,340)

 

 

 (728,317)

 

 

 85,402

 

 

 (642,915)

Other Income (Expense)

 

 (353,521)

 

 

 (20,947)

 

 

 (374,468)

 

 

 (6,245,471)

 

 

 (20,466)

 

 

 (6,265,937)

   Net income (loss)

$

 (1,088,567)

 

$

 (284,241)

 

$

 (1,372,808)

 

$

 (6,973,788)

 

$

 64,936

 

$

 (6,908,852)

Earnings per commons share: Basic and Diluted

$

(0.01)

 

$

Nil

 

$

(0.03)

 

$

(0.12)

 

$

(0.01)

 

$

(0.12)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Intercompany profit between the entities was eliminated in presentation of these results.


NOTE 7 - ACQUISITION OF GULF SOUTH SECURITIES, INC.


On July 31, 2016, the Company issued 5,373,528 shares of common stock and 2,674,576 common stock purchase warrants to Gulf South Holdings, Inc. (“GSHI”) and others in consideration of GSHI transferring to us 100,000 shares of common stock of Gulf South Securities, Inc. (“GSSI”), a registered broker-dealer located in Gig Harbor, WA.  The 100,000 shares received by the Company constituted all the issued and outstanding shares of common stock of GSSI.  The common stock purchase warrants have an exercise price of $0.60 per share and are exercisable through July 31, 2019.


Further, the Company issued 50,000 restricted shares of its Series B Preferred Stock to Bories Capital, LLC. These preferred shares were issued to Bories Capital, LLC, owned by Robert Bories, an officer of the Company as of April 30, 2017. Robert Bories is an officer of GSHI and Bories Capital, LLC has released its security interest in the common stock of GSSI.  Upon the completion of the foregoing stock exchange, GSSI became a wholly owned subsidiary corporation of the Company. GSSI is an SEC, FINRA registered securities broker-dealer.


The Company allowed GSSI’s FINRA registration to lapse as of February 28, 2017. GSSI is inactive and the Company plans on dissolving GSSI in fiscal 2018.


The acquisition was a business combination accounted for using the acquisition method.  Total consideration given for the purchase of GSSI is valued by the Company at $5,984,914.  The 5,373,528 restricted shares of common stock issued was valued at $0.454 per share based on the trading price on July 31, 2016 for a value of $2,439,583.  The 2,674,576 stock purchase warrants were valued at $0.396 per warrant for a value of $1,058,528 by applying a Black-Scholes model.  The fair value of the convertible Series B Preferred Stock was based on the convertible option of 5,500,000 common share equivalents at $0.45 per share for a value of $2,476,803 by applying a Black-Scholes model.  The Black-Scholes model used the following variables:

 

Warrants

 

Preferred B

Stock price on transaction date

$

0.454

 

$

0.454

Exercise price

 

1.00

 

 

1.00

Expected life in years

 

3.00

 

 

8.00

Expected volatility – peer group

 

196.40%

 

 

195.18%

Risk free rate

 

0.76%

 

 

1.29%

 

 

 

 

 

 

Fair value per unit

 

0.396

 

 

0.45

Units

 

2,674,576

 

 

5,500,000

Total Fair value

$

1,058,528

 

$

2,476,803

 

 

 

 

 

 

The Company incurred $93,500 in expenses specifically related to the acquisition. On June 27, 2016, 250,000 shares of common stock were issued to Delany Equity Group, LLC and 25,000 shares were issued to Irwin Renneisen valued at $0.34 per share, the fair value of the Company’s common stock on the date of issuance, totaling $93,500 for cost of acquisition of the GSSI.

The purchase price allocation of the acquisition is summarized as follows:

 

 

 

 

 

 

Common stock issued on acquisition

 

 

 

$

2,439,583

Stock purchase warrants issued on acquisition

 

 

 

 

1,058,528

Series B Preferred stock issued on acquisition

 

 

 

 

2,476,803

Cash

 

 

 

 

10,000

 

 

 

 

$

5,984,914

 

 

 

 

 

 

Net assets acquired:

 

 

 

 

 

 

Cash

 

 

 

$

9,100

Prepaid expenses

 

 

 

 

2,357

Goodwill

 

 

 

 

5,975,836

Accounts payable

 

 

 

 

(2,379)

 

 

 

 

$

5,984,914

 

 

 

 

 

 

The Company has analyzed the acquired entity of GSSI and determined that it had no identified intangible assets thus the excess of consideration over fair value of net assets acquired was recognized as goodwill.  However, on the date of the acquisition, management determined that the goodwill was not recoverable and recorded an adjustment of $5,975,836 to fully impair the amount on the consolidated statement of operations for the year ended July 31, 2016.


NOTE 8 – NOTES PAYABLE– RELATED PARTIES


Convertible debt, related parties


On January 3, 2011, the Company formalized a loan agreement with Jed Miesner, the Company’s CEO and Chairman for $1,940,000. The loan is scheduled to mature on December 31, 2030, bear interest at the rate of 8% per annum, and collateralized with a leasehold deed of trust covering certain leasehold interests in Pecos County, Texas.  At July 31, 2017 and 2016, the current component of this loan was $248,704 and $191,029, respectively. The long-term amounts at July 31, 2017 and 2016 were $1,691,296 and $1748,971, respectively.


On December 30, 2010, Amazing Energy, LLC, formalized loan agreements with Petro Pro Ltd., an entity controlled by Jed Miesner for $1,100,000. The loan is scheduled to mature on December 31, 2030, bear interest at the rate of 8% per annum and are collateralized with a leasehold deed of trust covering certain leasehold interests in Pecos County, Texas. At July 31, 2017 and 2016, the current component of this loan was $141,018 and $108,315, respectively.  The long-term amounts at July 31, 2017 and 2016, were $958,982 and $991,685, respectively.


On December 30, 2010, Amazing Energy, LLC, (a wholly owned subsidiary of the Company) entered into a $2,000,000 line of credit facility with JLM Strategic Investments LP, an entity controlled by Jed Miesner. Funds advanced on the line of credit mature on December 31, 2030, bear interest at the rate of 8% per annum and are collateralized with a leasehold deed of trust covering certain leasehold interests in Pecos County, Texas. There was a reduction in this debt of $287,303 on July 31, 2016 by the issuance of the Series A Preferred Stock (see below).  At July 31, 2017 and 2016, the current component of this loan was $41,170 and $30,162, respectively.  The long-term amounts at July 31, 2017 and 2016, were $Nil and $11,009, respectively.


Terms of the notes, as amended, provide for adjustment to the interest rate beginning February 1, 2017 from 8% to a rate of 6% through February 1, 2019, and a rate of Prime plus 2% for the remaining years. The notes also included a conversion feature that allows the principal and accrued interest of the loans to be converted into common stock of Amazing Energy, Inc. at $0.60 per share at the option of related party note holders.


Principal maturities for the two loan agreements and the credit facility outstanding at July 31, 2017 for the remaining terms are summarized by year as follows:


 

 

Principal Maturities

Year ending July 31,

 

Jed Miesner

 

 

Petro Pro, Ltd.

 

 

JLM Strategic Investments, LP

 

 

Total

2018

 

$

248,704

 

 

$

141,018

 

 

$

41,170

 

 

$

430,892

2019

 

 

62,290

 

 

 

35,319

 

 

 

-

 

 

 

97,609

2020

 

 

67,273

 

 

 

38,144

 

 

 

-

 

 

 

105,417

2021

 

 

72,655

 

 

 

41,196

 

 

 

-

 

 

 

113,851

2022

 

 

78,467

 

 

 

44,492

 

 

 

-

 

 

 

122,959

Subsequent years

 

 

1,410,611

 

 

 

799,831

 

 

 

-

 

 

 

2,210,443

 

 

$

1,940,000

 

 

$

1,100,000

 

 

$

41,170

 

 

$

3,081,170

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


On July 31, 2016, the Company authorized the issuance of 9,000 shares of Preferred Series A stock with par value of $0.01 per share. (Note 15). These shares were issued to Jed Miesner, the Company’s controlling shareholder, in exchange for cancellation of related party interest payable is associated with the convertible notes in the amount of $612,697 and a convertible note payable to JLM Strategic Investments, LP in the amount of $287,303.  This was accounted for as a deemed contribution on exchange of related party convertible debt and interest for preferred stock during the year ended July 31, 2016.


At July 31, 2017, Mr. Miesner has waived any event of default on the delinquent payments of principal and interest due on the loans and credit facility.   


As of July 31, 2017 and 2016, the accrued and unpaid interest on this related party convertible debt was $215,935 and $Nil, respectively. Related party interest expense for the year ended July 31, 2017 and 2016, was $215,935 and $269,722, respectively.  


At July 31, 2017, the balance of the convertible debt and accrued interest was convertible to 12,661,985 shares of common stock at a conversion price of $0.60 per share.


Note payable on acquisition, related party


On April 15, 2016, the Company entered into an agreement with Jed Miesner, the Chairman of the Company’s Board of Directors, to acquire all of his interest (100% of the total outstanding shares of common stock) in Jilpetco, Inc., a Texas corporation (“Jilpetco”) for consideration of $500,000 and oilfield service receivables of $71,745.  On August 25, 2016, the Company announced that the foregoing agreement was amended to extend the closing date to August 31, 2016 and excluded certain property therefrom. The parties agreed to allow Jed Miesner to assign certain accounts receivable and to exclude certain personal property from the transaction.


In addition, the $500,000 consideration for the acquisition was in the form of a note payable at 6% interest calling for monthly payments of principal and interest and maturing on December 25, 2017. For the year ended July 31, 2017, the Company made payments of $395,833 plus interest of $8,973 on this note.


Notes payable, related parties


On May 27, 2016, Jilpetco entered into loan agreements (the “May 2016 Notes”) with Tony Alford, Robert Bories, Robert Manning, Petro Pro Ltd., and Reese Pinney.  Messrs. Alford and Manning are members of the Board of Directors and Miesner is Chairman. Messrs. Bories and Pinney are officers of the Company. The aggregate principal amount of the notes was $180,000.


Principal, interest and fees for the May 2016 Notes at July 31, 2016 are summarized as follows:

 

 

 

 

Interest and financing fees payable

 

 

Principal amount

 

Interest

 

Fee

 

Total

Petro Pro Ltd.

 

$

 50,000

 

$

 722

 

$

 5,000

 

$

 5,722

Robert Bories

 

 

 50,000

 

 

 722

 

 

 5,000

 

 

 5,722

Tony Alford

 

 

 50,000

 

 

 722

 

 

 5,000

 

 

 5,722

Robert Manning

 

 

 20,000

 

 

 13

 

 

 2,000

 

 

 2,013

Reese Pinney

 

 

 10,000

 

 

 144

 

 

 1,000

 

 

 1,144

Total

 

$

 180,000

 

$

 2,324

 

$

 18,000

 

$

 20,324

 

 

 

 

 

 

 

 

 

 

 

 

 


The notes were scheduled to mature on November 23, 2016 and bore interest at the rate of 8% per annum. and included an initial participation fee of $18,000 equal to 10% of the principal amount of the loans.  On August 15, 2016, the loan agreements were modified to accept additional amounts from all the individual noteholders except Mr. Manning. A total of $50,000 was subsequently advanced on these notes, and an additional participation fee of $5,000 was incurred.


On November 23, 2016, the Noteholders waived any event of default and commenced discussion to extend or replace the loans with  new loan agreements.  On January 6, 2017, the Company paid 25% of the principal, $57,500, paid the initial 10% participation fee of $23,000, and paid the accrued interest through November 23, 2016, $8,035, for a grand total of $88,536 paid.


On May 31, 2017, the noteholders 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 based on the closing share price of $0.23.  This modification was accounted for as an extinguishment, and the $105,800 was expensed as a financing fee associated with debt modification.


On July 21, 2017, the Company entered into additional loan agreements (the “July 2017 Notes”) with Robert Bories, Robert Manning, Petro Pro Ltd., and Rolf Berg. The aggregate principal amount of the new notes was $175,000.  The notes bear interest at a rate of 8% per annum and incurred a participation fee of $17,500 equal to 10% of the principal amounts of the loans.  The July 2017 Notes are due January 21, 2018.


Principal, interest and fees for the notes payable, related parties at July 31, 2017 are summarized as follows:


 

 

Notes payable, related parties

 

Interest and financing fees payable

 

 

May 2016 Notes

 

July 2017 Notes

 

Total

 

May 2016 Interest

 

July 2017 Interest

 

July 2017 fee

 

Total

Petro Pro Ltd.

 

$

48,750

 

$

50,000

 

$

98,750

 

$

2,867

 

$

122

 

$

5,000

 

$

7,989

Robert Bories

 

 

 48,750

 

 

 50,000

 

 

 98,750

 

 

 2,867

 

 

 122

 

 

 5,000

 

 

 7,989

Tony Alford

 

 

 48,750

 

 

 -   

 

 

 48,750

 

 

 2,867

 

 

 -   

 

 

 -   

 

 

 2,867

Robert Manning

 

 

 15,000

 

 

 25,000

 

 

 40,000

 

 

 882

 

 

 61

 

 

 2,500

 

 

 3,443

Reese Pinney

 

 

 11,250

 

 

 -   

 

 

 11,250

 

 

 662

 

 

 -   

 

 

 -   

 

 

 662

Rolf Berg

 

 

 -   

 

 

 50,000

 

 

 50,000

 

 

 -   

 

 

 122

 

 

 5,000

 

 

 5,122

Total

 

$

172,500

 

$

 175,000

 

$

 347,500

 

$

10,146

 

$

428

 

$

17,500

 

$

 28,073

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Related party interest expense on these May 2016 and July 2017 Notes for the years ended July 31, 2017 and 2016 was $40,087 and $20,324 respectively.


NOTE 9 – NOTE PAYABLE AND LINE OF CREDIT


On February 24, 2016 the Company renewed a revolving line of credit whereby the Company was permitted to advance funds on the promissory note up to $500,000 for the purpose of general operating capital.  The line of credit bore interest at a variable rate of prime plus one percent and was calculated from the date of each advance until repayment of the note. At July 31, 2016, the balance of the  line of credit was $50,000.


For the year ended July 31, 2017, the Company advanced $175,000 on the line of credit and paid $225,000 on the balance.  On February 24, 2017, the Company elected not to renew the promissory note.


On July 21, 2017, the Company entered into a loan agreement with an unrelated party.  The principal amount of the note was $50,000.  The note matures on January 21, 2018 and bears interest at a rate of 8% per annum and includes a participation fee of $5,000 equal to 10% of the principal amounts of the loan.  During the year ended July 31, 2017, no principal payments were made on the note.  As of July 31, 2017, the note had accrued unpaid interest and fees of $5,122.



NOTE 10 – EQUIPMENT NOTE PAYABLE


On September 13, 2016, the Company entered into a retail installment sale contract and security agreement (the “Equipment Note”) for the purchase of equipment.  The Equipment Note is collateralized by a tractor loader backhoe.  The principal amount of the equipment note was $52,992, and it bears interest at 4.75% per annum.  The equipment note requires 60 monthly installment payments of $994 through September 13, 2021.  


Principal maturities for the equipment note payable at July 31, 2017 for the remaining term are summarized by year as follows:

 

 

For the year ended July 31,

 

 

 

2018

 

 

$

10,006

2019

 

 

 

10,491

2020

 

 

 

10,998

2021

 

 

 

11,535

2022

 

 

 

1,957

 

 

 

$

44,987

 

 

 

 

 


NOTE 11 – ASSET RETIREMENT OBLIGATIONS


During the year ended July 31, 2017, the Company revised its asset retirement obligation to reflect the sale of certain working interests in its oil and gas properties considered to be subject to remediation exposure for the Company.  The decrease in present value liability was subtracted from the Company’s asset retirement obligation asset.


The information below reconciles the value of the asset retirement obligation for years ended July 31, 2017 and 2016, respectively:


 

For the year ended July 31,

 

2017

 

2016

Beginning balance

$

 211,218

 

$

240,254

   Asset retirement obligation incurred

 

 -   

 

 

4,238

   Accretion expense

 

 9,396

 

 

12,854

   Revisions in estimated cash flows

 

 (37,217)

 

 

(46,128)

Ending balance, July 31, 2017

$

 183,397

 

$

211,218

 

 

 

 

 

 


NOTE 12 - INCOME TAXES


The Company did not recognize a tax provision for the years ended July 31, 2017 and July 2016


The following is reconciliation between the federal income tax benefit computed at the statutory federal income tax rate of 34% and actual income tax benefit for the years ended July 31, 2017 and July 31, 2016:

 

For the year ended July 31,

 

2017

 

2016

Statutory benefit

$

(736,582)

 

$

(2,395,430

Permanent differences:

 

 

 

 

 

   Prior year change in estimate

 

(260,131)

 

 

2,031,784

   Sale of subsidiary

 

57,800

 

 

208,317

   Meals and entertainment and other

 

3,813

 

 

4,621

   Change in valuation allowance

 

935,100

 

 

150,708

Net tax benefit

$

-   

 

$

-

 

 

 

 

 

 


 

2017

 

2016

Deferred Tax Assets:

 

 

 

 

 

   Net operating loss carryforward

$

3,628,293

 

$

2,711,635

   Depletion and depreciation

 

65,443

 

 

57,679

Total deferred tax assets

 

3,693,736

 

 

2,769,314

   

 

 

 

 

 

Deferred Tax Liabilities:

 

 

 

 

 

   Intangible drilling and other costs for oil and gas properties

$

 (1,466,531)

 

$

(1,466,532)

   Other

 

 (30,449)

 

 

(41,126)

Total deferred tax liabilities

 

(1,496,980)

 

 

(1,507,658)

   Net deferred tax assets and liabilities

 

2,196,756

 

 

1,261,656

      Less valuation allowance

 

(2,196,756)

 

 

(1,261,656

Total deferred tax assets and liabilities

$

-   

 

$

-

 

 

 

 

 

 

The Company had federal net operating loss carry forwards of approximately $10,671,450 and $7,975,397 at July 31, 2017 and July 31, 2016, respectively. The federal net operating loss carry forwards will begin to expire in fiscal years ending July 31, 2033 through July 31, 2037. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carry forwards.  The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.


Authoritative guidance for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an examination.  Management has reviewed the Company’s tax positions and determined there were no uncertain tax positions requiring recognition in the consolidated financial statements. Currently tax years from fiscal 2015 through 2017 remain open for examination by tax authorities. Net operating losses prior to 2015 could be adjusted during an examination of open years.


Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits would be classified as a component of tax expense in the statement of operation.  The Company has not recorded any interest or penalties associated with unrecognized tax benefits for any periods covered by these financial statements.


NOTE 13 – COMMITMENTS AND CONTINGENCIES


The Company is subject to contingencies because of environmental laws and regulations. Present and future environmental laws and regulations applicable to the Company's operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time.


Legal contingency


As of July 31, 2017, the Company was not a party to any litigation.  However, on September 7, 2017, Amazing Energy LLC and Jilpetco Inc. were served with a lawsuit, being 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 discovery as to the claims against the Company. Management intends to seek an early resolution 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.


Lease commitments


The Company’s principal executive offices are in leased office space in Amarillo, Texas. The leased office space consists of approximately 3,700 square feet and is leased through February 28, 2019 at an annual cost of approximately $52,000.


Oil and gas lease commitments


The Company is obligated to pay royalties to holders of oil and natural gas interests in its Texas operations.  The Company is also obligated to pay working interest holders a pro-rata portion of revenue in oil operations net of shared operating expenses.  The amounts are based on monthly oil and gas sales and are charged monthly net of oil and gas revenue and recognized as “Revenue Payable to Interest Owners” on the Company’s Balance Sheet.  


The Company is also obligated to pay certain ‘bonus’ lease payments related to certain of its Pecos, TX lease properties.  The Company is required to pay $27,000 each year on the JT Walker lease, with the first payment due August 7, 2017.   The Company is also required to pay $200,000 every five years on the JPMorgan lease, with the first payment due August 7, 2017


NOTE 14 – BUSINESS SEGMENTS


The Company is current organized and managed by two segments, which represent two operating units.  Oil and gas operations includes activities related to production and sales of oil and natural gas.  Oilfield services includes a variety of services to the energy industry, including drilling and completion of wells.  Both segments operate in Texas.


The Company’s segment disclosures are as follows:


Oil and gas properties

 

 

July 31, 2017

 

July 31, 2016

Oilfield services

$

-

 

$

-

Oil and gas operations

 

5,919,082

 

 

6,236,709

Total property and equipment, net

$

5,919,082

 

$

 6,236,709

 

 

 

 

 

 



Property and equipment, net

 

 

July 31, 2017

 

July 31, 2016

Oilfield services

$

 527,683

 

$

 379,763

Oil and gas operations

 

 18,129

 

 

 19,314

Total property and equipment, net

$

 545,812

 

$

 399,077

 

 

 

 

 

 


Total assets

 

 

July 31, 2017

 

July 31, 2016

Oilfield services

$

 1,178,139

 

$

 722,417

Oil and gas operations

 

 6,292,116

 

 

 6,525,981

Total assets

$

 7,470,255

 

$

 7,248,398

 

 

 

 

 

 


Capital expenditures

 

For the year ended

 

For the year ended

 

July 31, 2017

 

July 31, 2016

Oilfield services

$

 261,251

 

$

 5,435

Oil and gas operations

 

 566,794

 

 

 285,583

Total property and equipment, net

$

 828,045

 

$

 291,018

 

 

 

 

 

 


Operations for the year ended July 31, 2017

 

Oil and gas operations

 

Oilfield services

 

Total

Total revenues

$

 276,502

 

$

 285,277

 

$

 561,779

Depletion and depreciation

 

(187,793)

 

 

 (113,331)

 

 

(301,124)

Operating expenses

 

(823,755)

 

 

 (435,240)

 

 

(1,258,995)

Income (loss) from operations

 

 (735,046)

 

 

 (263,294)

 

 

 (998,340)

Other income (expense)

 

 (353,521)

 

 

 (20,947)

 

 

 (374,468)

NET INCOME (LOSS)

$

 (1,088,567)

 

$

 (284,241)

 

$

 (1,372,808)

 

 

 

 

 

 

 

 

 


Operations for the year ended July 31, 2016

 

Oil and gas operations

 

Oilfield services

 

Total

Total revenues

$

 250,476

 

$

 323,793

 

$

 574,269

Depletion and depreciation

 

 (130,796)

 

 

 (74,355)

 

 

 (205,151)

Operating expenses

 

 (847,997)

 

 

 (164,036)

 

 

 (1,012,033)

Income (loss) from operations

 

 (728,317)

 

 

 85,402

 

 

 (642,915)

Other income (expense)

 

 (6,245,471)

 

 

 (20,466)

 

 

 (6,265,937)

NET INCOME (LOSS)

$

 (6,973,788)

 

$

 64,936

 

$

 (6,908,852)

 

 

 

 

 

 

 

 

 


During the year ended July 31, 2016, $29,904 was billed to Petro Pro, a related party, for oilfield services.  No such charges were incurred in the year ended July 31, 2017.


NOTE 15 – STOCKHOLDERS’ EQUITY


Common stock


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.


Preferred stock


The Company is authorized to issue 10,000,000 shares of its preferred stock with a no par value per share.  

 

Series A convertible preferred stock:


The Company has 9,000 shares of Series A preferred stock outstanding at July 31, 2017.  These shares were issued from the designated 10,000,000 shares of preferred stock, no par value, with the following rights and preferences:


·

Liquidation preference:  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 the Company securities junior to the Series A preferred stock.


·

Dividends:  Holders of the Series A preferred stock are not entitled to receive a dividend.


·

Voting:  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.


·

Non-transferrable:  The shares of Series A preferred stock are not transferrable except under a plan for wealth transfer and estate planning or upon conversion or redemption as set forth below.


·

Conversion:  On the fifth anniversary of the acquisitions of GSSI (Note 7), any shares of the Series A preferred stock outstanding will be convertible, at the discretion of the shareholder, 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.


Series B convertible preferred stock:


The Company has 50,000 shares of Series B preferred stock outstanding at July 31, 2017.  These shares were issued from the designated 10,000,000 shares of preferred stock, no par value, with the following rights and preferences:


·

Liquidation preference:  Upon a liquidation event, an amount in cash equal to $100 per share, for a total of $5,000,000 at July 31, 2017, shall be paid prior to liquidation payments to holders of Company securities junior to the Series B preferred stock.  Holders of the Company’s Series A preferred stock shall be paid in advance of holders of the Series B preferred stock on the occurrence of a liquidation event.


·

Dividends:  Holders of the Series B preferred stock are not entitled to receive a dividend.


·

Voting:  The Series B preferred stock has no voting rights other than to be voted when required by the laws of the State of Nevada.


·

Non-transferrable:  The shares of Series B preferred stock are not transferrable except under a plan for wealth transfer and estate planning or upon conversion or redemption as set forth below.


·

Conversion:  On the fifth anniversary of the acquisitions of GSSI (Note 7), any shares of the Series B preferred stock outstanding will be convertible, at the discretion of the shareholder, 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 B preferred stock outstanding.


Redemption of preferred stock


In connection with the issuance of the Series A and Series B Preferred Stock as discussed in Note 7 and Note 8, for each new oil and gas well drilled by the Company with funds raised or delivered due to the efforts of the former GSHI officers, now Company officers, the Company will pay Jed Miesner $10,000 in exchange for 100 shares of Series A Preferred Stock and Robert Bories $10,000 in exchange for 100 shares of Series B Preferred Stock.  In the event that the Company drills wells for its own account the Board of Directors of the Company will decide if such wells qualify for the aforementioned redemption.  The Company will promptly cancel any Series A or B Preferred Stock purchased. As of July 31, 2017, there was no redemption or accrual made under this provision.

  

During the year ended July 31, 2017, the Company had the following equity transactions:

Common shares issued for cash  


On May 16, 2016, the Company began a private placement offering of 20,000,000 shares of common stock at $0.26 per share.  As of July 31, 2016, 699,400 shares had been sold for $181,844.  



For the year ended July 31, 2017, the Company issued 6,169,084 shares of common stock at $0.26 per share for $1,603,961.  


Cumulatively, as of July 31, 2017, the private placement sold 6,868,484 shares of common stock for total gross proceeds of $1,785,805.


Common shares issued in lieu of cash for services


On January 20, 2017, the Company issued 112,500 shares of common stock with a total fair value of $44,625 ($12,275 earned in the fiscal year end July 31, 2017) for services provided by a vendor. The shares were issued at an average fair value of $0.40 per share.


Common shares issued for extensions of notes payable, related parties


On May 27, 2017, the related party noteholders of notes payable (Note 8)  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 based on the closing share price of $0.23.


During the year ended July 31, 2016, the Company had the following equity transactions:


Preferred shares issued for debt and interest


On July 31, 2016, the Company issued 9,000 shares of 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 (See Note 10).  The stated issue price is at $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, 2016 shall be paid prior to liquidation payments to holders of Company securities junior to the Series A Preferred Stock. On the fifth anniversary of the acquisition of GSSI (Notes 7 & 13), 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.


Common shares issued for services


On November 20, 2015 and January 27, 2016, 50,000 shares of common stock were issued to Delany Equity Group, LLC valued at $0.30 per share, the fair value of the Company’s common stock on the date of issuance, totaling $15,000 for financial consulting services.  On June 27, 2016, 250,000 shares of common stock were issued to Delany Equity Group, LLC and 25,000 shares were issued to Irwin Renneisen valued at $0.34 per share, the fair value of the Company’s common stock on the date of issuance, totaling $93,500 for cost of acquisition of GSSI (Notes 7 & 13).


Common shares issued for acquisition of GSSI


On July 31, 2016, we issued 5,373,528 restricted shares of our common stock and 2,674,576 stock purchase warrants to Gulf South Holding, Inc. (GSHI) and others in consideration of GSHI transferring to us 100,000 shares of common stock of GSSI which constitutes all of the issued and outstanding shares of common stock of GSSI. (See Notes 7 & 13).


As part of the acquisition of GSSI effective July 31, 2016, the Company issued 50,000 shares of Preferred Series B stock with par value of $0.01 per share.  These preferred shares were issued to Bories Capital, LLC, owned by Robert Bories, an officer of the Company as of July 31, 2016.  Robert Bories is an officer of GSHI and Bories Capital, LLC has released its security interest in the common stock of GSSI.  The Series B Preferred Stock has no voting rights other than to be voted when required by Nevada law.  Holders of the Series B 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 $5,000,000 at July 31, 2016 shall be paid prior to liquidation payments to holders of Company securities junior to the Series B Preferred Stock.  Holders of the Company’s Series A Preferred Stock shall be paid in advance of holders of the Series B Preferred Stock on the occurrence of a liquidation event.  On the fifth anniversary of the acquisition of GSSI, any shares of the Series B 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 B Preferred Stock outstanding.  


For each new oil and gas well drilled by the Company with funds raised or delivered due to the efforts of the former GSHI officers, now Company officers, the Company will pay Miesner $10,000 in exchange for 100 shares of Series A Preferred Stock and Bories $10,000 in exchange for 100 shares of Series B Preferred Stock.  In the event that the Company drills wells for its own account the Board of Directors of the Company will decide if such wells qualify for the aforementioned redemption.  The Company will promptly cancel any Series A or B Preferred Stock purchased.


Warrants


The composition of the Company’s warrants outstanding at July 31, 2017 is as follows:


Issue Date

 

Expiration Date

 

Warrants

 

Exercise Price

July 31, 2016

 

July 31, 2019

 

2,674,576

 

$

0.60


There were no warrants issued or exercised during the year ended July 31, 2017.


NOTE 16 – GAIN FROM SALES OF LEASEHOLD AND MINERAL RIGHTS


Kisa granted Afranex Gold Limited (“Afranex”) an option to purchase all of the outstanding common stock of Kisa or purchase all of Kisa’s right, title and interest in certain mining permits and associated assets of Kisa. The option period was to originally end on December 31, 2016 or such later date which was to be agreed upon by both parties.


On January 3, 2017,  Afranex paid a $50,000 non-refundable option fee to the Company, as consideration for extending the option period to March 31, 2017.  Afranex agreed to pay the Company a total of $120,000 to exercise the option and acquire either the stock or the claims.   On March 29, 2017, Afranex exercised the option by paying the Company $120,000 in cash and taking transfer of all of Kisa’s right, title and interest in and to the claims.  For the year ended July 31, 2017, the Company recognized a gain on sales of mineral rights of $170,000 because the carrying value of the mineral interest was zero.


NOTE 17 – FAIR VALUE MEASUREMENTS


During the year ended July 31, 2016, the Company had the following non-recurring transactions which required measurement of fair value within the fair value hierarchy:


·

Preferred Stock Series A exchanged for convertible debt and interest (Note 8)

·

Warrants issued in an acquisition transaction (Note 7)

·

Preferred Stock Series B issued in a purchase transaction (Notes 7 & 15)

·

The Company recorded an impairment loss on goodwill (Note 7)


Fair Value Measurement on a Non-Recurring Basis

 

 

 

Fair value for the year ended July 31, 2016

 

  

 

Total

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

Preferred stock series A

$

445,735

 

$

-

 

$

445,735

 

$

-

 

Common stock purchase warrants

$

1,058,528

 

$

-

 

$

1,058,528

 

$

-

 

Preferred stock series B

$

2,476,803

 

$

-

 

$

2,476,803

 

$

-

 

Goodwill impairment

$

5,965,836

 

$

-

 

$

-

 

$

5,965,836


Estimated fair values during the year ended July 31, 2016 for the preferred stock and warrants were determined using a Black Scholes model with inputs as indicated in the respective footnotes referenced above.  The fair value estimation of goodwill was determined by the Company based on unobservable inputs, therefore the valuation is classified within Level 3 of the fair value hierarchy.


There were no similar transactions during the year ended July 31, 2017 which required fair value measurement on a non-recurring basis.


NOTE 18– SUBSEQUENT EVENTS


On August 11, 2017, the Board of Directors approved an offering of common shares at $0.25 to raise $2,000,000. The offering is for a total of 8,000,000 restricted common shares at $0.25 per share. As of October 31, 2017, 1,200,000 common shares had been sold for a total of $300,000.


On September 26, 2017, the Board of Directors approved the grant of 1,000,000 share purchase warrants and 500,000 stock options in aggregate to various members of the Board of Directors, consultants and employees.  The share purchase warrants and stock options have an exercise price of $0.40 per and have a four-year term.  


NOTE 19 – SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)


Costs Incurred – Costs incurred in oil and gas property acquisition, exploration and development activities, whether expensed or capitalized, are reflected in the table below for the years ended July 31, 2017 and 2016.


 

2017

 

2016

Development costs

$

 370,090

 

$

283,750

Total costs incurred

$

 370,090

 

$

283,750

 

 

 

 

 

 

Capitalized Costs – The aggregate amount of capitalized costs related to oil and gas producing activities and the aggregate amount of the related accumulated depreciation, depletion and amortization (“DD&A”), including any accumulated valuation allowances, are reflected in the table below for the years ended July 31, 2017 and July 31, 2016.


 

2017

 

2016

Proved properties

$

7,099,037

 

$

7,243,509

Total oil and gas properties

 

7,099,037

 

 

7,243,509

Accumulated DD&A

 

(1,179,955)

 

 

(997,986

Net oil and gas properties

$

5,919,082

 

$

6,236,709

 

 

 

 

 

 


Proved Oil and Gas Reserve – Proved oil and gas reserves were estimated by independent petroleum engineers. The reserves were based on the following assumptions:

·

Future revenues were based on an un-weighted 12-month average of the first-day-of-the-month price held constant throughout the life of the properties.

·

Production and development costs were computed using year-end costs assuming no change in present economic conditions.

·

Future net cash flows were discounted at an annual rate of 10%.


Reserve estimates are inherently imprecise, and these estimates are expected to change as future information becomes available.


Basis of Presentation – The proved oil and gas reserve quantities for fiscal 2017 and 2016 are based on estimates prepared by Mire & Associates, Inc., Petroleum Engineering Consultants. There are numerous uncertainties in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as our properties. The following reserve data represents estimates only and actual reserves may vary substantially from these estimates. All of our proved reserves were in United States as of July 31, 2017 and 2016. Our net quantities of proved developed and undeveloped reserves of crude oil and gas and changes therein are reflected in the table below.


As of July 31, 2017, we had twenty-three wells drilled with twenty-one producing and two wells shut-in awaiting workovers.

The proved reserves as of July 31, 2017 represent the reserves that were estimated to be recovered from twenty-three current wells. There are also seven wells planned for future drilling. All direct offset well locations in this report are proved undeveloped and are based on 10-acre drainage patterns unless current developed completions are estimated to drain an area larger than their volumetric assignment. In this case, the reserves of certain offset locations have been reduced. All locations have a scheduled Queen and/or Grayburg reservoir completion and each of these reservoir completions includes the cost of drilling a single wellbore. All reserves included in this report were estimated using either historical performance or volumetric methods.


Estimated Quantities of Net Proved Oil and Natural Gas Reserves – Estimated quantities of net proved oil and natural gas reserves are reflected in the table below for the years ended July 31, 2017 and 2016.

 

 

 

 

 

 

 

2017

 

2016

 

 

Oil (1)

 

Natural Gas (1)

 

Oil (1)

 

Natural Gas (1)

RESERVES:

 

 

 

 

 

 

 

 

Beginning of year

 

436,980

 

1,849,260

 

357,290

 

1,312,500

 

Revisions of previous estimates

 

(111,458)