DIVERSIFIED RESOURCES, INC. (OTCMKTS:DDRI) Files An 8-K Other Events

Diversified Resources, Inc.

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of the consolidated financial statements.

The accompanying notes are an integral part of the consolidated financial statements.

The accompanying notes are an integral part of the consolidated financial statements.

The accompanying notes are an integral part of the consolidated financial statements.

DIVERSIFIED RESOURCES INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Years Ending October 31, 2016 and 2015

Note 1. Summary of Significant Accounting Policies

Organization

Diversified Resources Inc. (“the Company”) was incorporated in the State of Nevada on March 19, 2009 to pursue mineral extraction in the United States.

On June 15, 2009, the Company leased two mining claims in Esmerelda County, Nevada, in the Dunfee Mine Area. The lease includes all additional claims within one mile of these claims. The term of the lease was for 20 years and was terminated during November 2013.

Effective November 21, 2013 we acquired 100% of the outstanding shares of Natural Resource Group, Inc. in exchange for 14,558,150 shares of our common stock. In connection with this acquisition, the then President of the Company sold 2,680,033 shares of the Company’s common stock to the Company for nominal consideration. The shares purchased from the President were returned to the status of authorized but unissued shares. Additionally, the former principals of the Company assumed all of the debts of the Company at the date of the exchange.

On October 14, 2014, the Company acquired approximately 98% of the outstanding shares of BIYA Operators, Inc. (“BIYA”) an independent oil and gas company. BIYA has oil and gas leases in the Horseshoe Gallop field in San Juan County, New Mexico covering approximately 10,100 acres and 48 producing wells. The majority of the leased acreage and producing wells are on Mountain Ute tribal land and are leased under an operating agreement with the tribe, which commenced on April 15, 2008.

On February 1, 2016, we acquired 100% of the outstanding shares of Diversified Energy Services, Inc. (“DESI”), a holding company comprised of three oilfield services companies.

The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.

Going Concern

As shown in the accompanying consolidated financial statements, the Company has incurred significant operating losses since inception, has an accumulated deficit of ($12,269,149) and has negative working capital of $2,585,018 at October 31, 2016. As of October 31, 2016, the Company has limited financial resources. These factors raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s ability to achieve and maintain profitability and positive cash flow is dependent upon its ability to locate profitable mineral properties, generate revenue from planned business operations, and control exploration costs. Management plans to fund its future operations by joint venturing, obtaining additional financing, and attaining additional commercial production. However, there is no assurance that the Company will be able to obtain additional financing from investors or private lenders, or that additional commercial production can be attained.

The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the possible inability of the Company to continue as a going concern.

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value due to the short maturity of these instruments.

Accounts Receivable

Our credit terms for our billings is net 30 days. Accounts receivables are determined to be past due if payments are not made in accordance with the terms and an allowance is recorded for accounts when there are indicators that the receivables may not be recovered. Customary collection efforts are initiated and receivables are written off when we determine they are not collectible and abandon these collection efforts.

We evaluate the past due accounts to setup an allowance for doubtful accounts on a regular basis for adequacy based upon our periodic review of the collectability of the receivables in light of historical experience, adverse situations that may affect our customers’ ability to pay, estimated value of any underlying collateral and prevailing economic conditions. This evaluation is inherently subjective, as it requires estimates that are susceptible to significant revision as more information becomes available. The Company did not record any adjustment for uncollectible receivables in 2016 or 2015.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the financial statements. Actual results could differ from those estimates.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash equivalents. The Company places its cash equivalents with a high credit quality financial institution. The Company periodically maintains cash balances at a commercial bank in excess of the Federal Deposit Insurance Corporation insurance limit of $250,000.

Stock-based compensation

ASC 718, Stock Compensation requires that all stock-based compensation be recognized as an expense in the financial statements and that such cost be measured at the grant date fair value of the award.

We record compensation and other charges related to the issuance of stock-based compensation awards at the fair value of the awards. Such awards can be comprised of stock, restricted stock and stock options. The Company recognized stock-based compensation of $365,132 in general and administrative expense for the year ended October 31, 2016. No such expense was recorded for the year ended October 31, 2015.

We record the grant date fair value of stock-based compensation awards as an expense over the vesting period of the related stock options. In order to determine the fair value of the stock options on the date of grant, we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock-price volatility, option life, risk-free interest rate and dividend yield. Although the risk-free interest rates and dividend yield are less subjective assumptions, typically based on factual data derived from public sources, the expected stock-price volatility, forfeiture rate and option life assumptions require a greater level of judgment which makes them critical accounting estimates.

We use an expected stock price volatility assumption that is based on historical volatilities of our common stock and we estimate the forfeiture rate and option life based on historical data related to prior option grants, as we believe such historical data will be similar to future results.

Dependence on Oil and Gas Prices

As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for natural gas and oil. Historically, the energy markets have been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. Prices for oil and natural gas have recently declined materially. Any continued and extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that we can economically produce.

Revenue Recognition

We recognize oil and gas revenue from interests in producing wells as the oil or gas is sold. Revenue from the purchase, transportation, and sale of natural gas is recognized upon completion of the sale and when transported volumes are delivered. We recognize revenue related to gas balancing agreements based on the sales method. Our net imbalance position at October 31, 2016 and 2015 was immaterial.

We recognize revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. DESI prices services by the hour, day, or project depending on the type of service performed.

Accounting for Oil and Gas Activities

Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization amounts are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred.

Assets are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Proved Property Impairment We review individually significant proved oil and gas properties and other long-lived assets for impairment at least annually at year-end, or quarterly when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Our valuation of Garcia field resulted in impairment expense of $2,427,968 during the period ending October 31, 2015.

Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property, and the remaining months in the lease term for the property.

Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the well. Geological and geophysical costs were $37,089 and $16,513 for the years ended October 31, 2016 and 2015, respectively, and are included in Exploration Costs in the accompanying financial statements.

Asset Retirement Obligations Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is determined at current costs and is inflated into future dollars using an inflation rate that is based on the consumer price index. The future projected cash flows are then discounted to their present value using a credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset.

Net Income (Loss) per Common Share

Basic earnings (loss) per share are calculated by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share are calculated by dividing net income (loss) by the weighted average number of common shares and dilutive common stock equivalents outstanding. During the periods when they are anti-dilutive, common stock equivalents, if any, are not considered in the computation.

Property and Equipment

Property and equipment are stated at cost, expenditures for repairs and maintenance are charged to expense as incurred and additions and improvements that significantly extend the lives of the assets are capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation and amortization are removed from the related accounts and any gain or loss is reflected in operations. All property and equipment are depreciated or amortized (to the extent of estimated salvage values) on the straight-line method and the estimated useful lives of the assets are as follows:

The components of a well servicing rig generally require replacement or refurbishment during the well servicing rig’s life and are depreciated over their estimated useful lives, which ranges from 3 to 15 years. The costs of the original components of a purchased or acquired well servicing rig are not maintained separately from the base rig.

Impairment of Long Lived Assets

The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company reviews the carrying values of its oil and gas properties and undeveloped leaseholds annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows. The impairment analysis performed by the Company may utilize Level 3 inputs.

The Company recorded impairment expense of $2,427,968 based on valuation of Garcia field for the year ending October 31, 2015. No such impairment was recorded for the years ended October 31, 2016.

Income Taxes

We compute income taxes in accordance with ASC Topic 740, Income Taxes. Under ASC 740, provisions for income taxes are based on taxes payable or refundable during each reporting period and changes in deferred taxes. Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Also, the effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred taxes are classified as current or non-current depending on the classifications of the assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change.

We follow the guidance in ASC Topic 740-10, Accounting for Uncertainty in Income Taxes, which prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The Company does not believe that any material uncertain tax positions exist at October 31, 2015.

Major Customers

As of October 31, 2016, three customers each comprised more than 10% of the Company’s accounts receivable balance; at approximately 16%, 15% and 12%, respectively. Revenues from these customers represented 10%, 35% and 2% of total revenues, respectively, for the year ended October 31, 2016. No other customer exceeded 10% of total revenues for the year ended October 31, 2016.

As of October 31, 2015, Sales to major unaffiliated customers consisted of approximately 95% of revenue.

The Company sells its oil and gas production to a small number of customers, as is customary in the industry. Yet, based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

Recent Accounting Pronouncements

In August 2015, the FASB issued Update No. 2015-14 – Revenue from Contracts with Customers to defer the effective date of the new revenue recognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is reviewing its contracts and is assessing the impact of Update 2015-14, but does not currently believe this guidance will have a material effect on the Company’s financial statements or disclosures.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)”, which requires a lessee to record a right-of-use asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the impact of our pending adoption of the new standard on our consolidated financial statements.

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The Company will elect to remove forfeiture rates and record a cumulative-effect adjustment to equity at the beginning of 2017 when the guidance is adopted and does not expect the adoption of this guidance to have a material impact on its cash flows or results of operations.

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its statement of cash flows.

In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

The Company does not believe that any other recently issued or proposed accounting pronouncements will have a material impact on its financial position, results of operations or cash flows.

FASB Codification Topic 280, Segment Reporting, establishes standards for reporting financial and descriptive information about an enterprise’s reportable segments. The Company has two reportable segments: Exploration and Production (EP) and the Services division. The segments are determined based on several factors, including the nature of product and service. Refer to Note 1 for a description of the various services performed by the Company. Prior to the February 1, 2016, the Company only had one reporting segment.

An operating segment’s performance is evaluated based on its pre-tax operating contribution, or segment income. Segment income is defined as oil and gas sales and service revenue less cost of sales and services, and segment selling, general and administrative expenses.

2. Oil and gas properties

Oil and gas properties consist of the following:

Total depletion of oil and gas properties amounted to $35,699 and $88,287 for the years ended October 31, 2016 and 2015 respectively. Impairment of $2,427,968 was recorded during the period ending October 31, 2015.

3. Property and Equipment

Property and equipment consisted of the following:

4. Participation Agreement

In connection with the convertible promissory note described in note 5, the Company entered into a participation agreement with a nonaffiliated company whereby the nonaffiliated company would advance up to $350,000 to conduct additional development of the underlying leases at the Garcia Field and drill and complete three additional wells on the acreage. As of October 31, 2016, $248,895 was due on the note. Subsequently in 2017, this note was converted into a 1% overriding royalty interest in the 640 acre field and conversion of the principle into the drilling program that provides revenue sharing and 140% return on the contributed amount with no maturity date.

5. Notes Payable – Affiliates

Notes Payable AffiliatesIn December 2010, the Company entered into a purchase and sale agreement to acquire certain oil and gas assets located in Adams, County, Broomfield, County, Huerfano County, Las Animas County, Morgan County and Weld County, Colorado. The Company issued 2,500,000 shares of its $0.0001 par value Common Stock and a promissory note for $360,000 bearing interest at 10% with an original maturity date of March 1, 2011. The shares were valued at $1 per share based on sales of the Company’s common stock to third-parties. The promissory note is collateralized by the property and equipment transferred and was subsequently subrogated to a convertible promissory note on January 12, 2012 (See Note 5). In December 2015, the maturity date of the note was extended to December 2017. The balance on the note is $107,070 at October 31, 2016 and 2015, with interest accrued in the amount of $26,081 and $15,286, respectively.

In February 2016, the Company entered into a purchase and sales agreement to acquired DESI. As part of the purchase price, the Company issued an unsecured note for $2,000,000, to one of the owners of DESI, bearing interest at 2% with a maturity date of February 2018.

6. Long-term Debt and Note Payable

Promissory Notes: On October 14, 2014, the Company acquired approximately 98% of the outstanding shares of BIYA Operators, Inc. (“BIYA”) an independent oil and gas company. The Company issued a promissory note in the principal amount of $1,860,000 (subject to adjustment for unknown liabilities). The note will be effective when certain leases covering Indian tribal lands have been issued. The note is in arbitration for deduction in the principle balance related to undisclosed royalties, other liabilities, costs related to undisclosed spills and contamination and for the related lost production and revenue.

In May 2012 BIYA entered into a settlement agreement with a previous partner for $1.2 million. The amount is non-interest bearing and has a minimum monthly payment of $10,000, plus one third of BIYA’s net profits, as defined in the agreement. On April 1, 2015, the agreement was amended, where the balance due will bear interest at 6% a year and has a fixed monthly payment of $5,500 until paid in full. The balance due was $486,161 at October 31, 2016.

Secured NotesIn 2015, the Company issued secured notes in the principal amounts of $1,250,000, bearing interest at 12% payable quarterly beginning June 1, 2015 with a two year maturity date. In January 2016, the Company issued secured notes in the principal amounts of $200,000, bearing interest at 12% payable quarterly beginning January, 2016 with a two year maturity date. The notes are collateralized by a first priority deed of trust on certain producing wells and their spacing units located in the Horseshoe Gallup Field. The notes and any interest outstanding may be converted, one time only, for new securities offered by the Company. The notes guarantee one year of interest which would be due even upon prepayment of the notes during the first year. The lenders received two year warrants which entitles the holders to purchase up to 360,000 shares of the Company’s common stock at a price of $0.80 and $1.50 per common share, valued at approximately $126,000 at October 31, 2015, using the Black Scholes method. The value of the warrants has been recorded as discount on the note and a credit to additional paid in capital. The company recorded accretion of the discount in the amount of $72,000 for the year ended October 31, 2016. The secured notes had accrued interest payable of approximately $198,883 at October 31, 2016.

In October 2016, the Company settled a lawsuit, to the terms of the settlement, the Company agreed to pay the plaintiffs $1,050,000 plus interest at 8% per year. The amount due the plaintiffs is payable between October 1, 2016 and December 31, 2019 with the first payment due October 1, 2016. See note 10 for further details.

Installment Loans On July 4, 2013, the Company entered into an installment loan bearing interest of 5.39%. The loan is payable in monthly installments of $464 over 48 months commencing August 4, 2013. The loan is collateralized by a vehicle. On July 5, 2015, the Company entered into installment loans bearing interest of 3.62%. The loans are payable in monthly installments of $2,118 over 48 months. The loans are collateralized by two vehicles.

The Company entered into various installment loans in 2014 and 2015 bearing interest ranging from 0% to 4.5%. The loans are payable in monthly installments ranging from $715 and $4,000 over 36 to 60 months. The loans are collateralized by heavy equipment, trucks and vehicles. On August 15, 2015, the Company entered into installment loans bearing interest of 4.5%. The loans are payable in monthly installments of $38,000 over 48 months and are collateralized by heavy equipment and trucks.

The following summarizes the notes payable:

The above debt matures as follows:

7. Asset Retirement Obligation

The following table reflects a reconciliation of the Company’s asset retirement obligation liability:

8. Income Taxes

ASC 740 guidance requires that the Company evaluate all monetary tax positions taken, and recognize a liability for any uncertain tax positions that are not more likely than not to be sustained by the tax authorities. The Company has not recorded any liabilities, or interest and penalties, as of October 31, 2015 related to uncertain tax positions. Deferred tax assets and liabilities are recorded based on the differences between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes, referred to as temporary differences. Deferred tax assets and liabilities at the end of each period are determined using the currently-enacted tax rates applied to taxable income in the periods in which the deferred tax assets and liabilities are expected to be settled or realized. The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before provision for income taxes. The Company’s estimated effective tax rate of 39% is offset by a valuation allowance due to the uncertainty regarding the realization of the deferred tax asset.

The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of October 31, 2016 and 2015 were:

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income. At October 31, 2016, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $10.8 million, which will begin expiring in 2030.

The following table shows the reconciliation of the Company’s effective tax rate to the expected federal tax rate for the years ended October 31, 2016 and 2015:

The Company files income tax returns in the U.S. and Colorado jurisdictions. There are currently no federal or state income tax examinations underway for these jurisdictions. Income tax returns since inception are subject to audit by taxing authorities as a result of the net operating loss carryforward.

9. Stockholder’s Equity

Common Stock The Company is authorized to issue 450,000,000 common shares of par value at $0.001 and 50,000,000 preferred shares of par value at $0.001.

2016 – As of October 31, 2016, 44,883,462 shares of common stock were issued and outstanding. In March 2016, the Company converted 301,000 outstanding preferred shares for common shares at a conversion rate of two common shares for each preferred share. During the twelve months ended October 31, 2016, the Company sold 120,000 shares of its common stock to a group of private investors for cash of $60,000.

In October 2016, the Company Issued warrants to purchase 3,276,551 restricted shares of the Company’s common stock. The warrants can be exercised any time on or before January 1, 2027 at a price of $.05 per share. See note 10 for further details.

2015 – The Company issued 50,000 shares to National Petroleum Corporation with a fair value of $22,500, which was treated as lease expense, to extend the convertible promissory note for additional one year (see Note 5). The Company also issued 663,720 shares for cash of $663,720.

The Company issued 280,000 shares of preferred stock for cash of $280,000 and, as per the payment option under secured note agreement. The preferred stock holders received three year warrants which entitles the stockholders to purchase up to 75,250 shares of the Company’s common stock at a price of $1.50 per common share. The Company also issued 21,000 shares of preferred stock to pay $21,000 in accrued interest.

10. Commitments and Contingent Liabilities

Legal

The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.

In March 2016 Gilbert Bernal and two companies he controls (collectively, the “Plaintiffs”) filed a lawsuit against us in the District Court of Weld County, Colorado. In their lawsuit, Plaintiffs claim that:

1.	Bernal had an ownership interest in Ultra Energy Solutions and Vinco Logistics, two of the three entities that combined to form Diversified Energy Services.

2.	Bernal never consented to the transfer of his interest in Ultra Energy Solutions and Vinco Logistics to Diversified Energy Services.

3.	Diversified Energy Services has possession of equipment owned by the Plaintiffs and has ignored Plaintiffs demand to return the equipment to the Plaintiffs.

Diversified Energy Services has refused to repay approximately $1.3 million loaned to Ultra Energy Solutions and Vinco Logistics by the Plaintiffs.

In October 2016 the Company and the Plaintiffs settled the lawsuit. to the terms of the settlement, the Company agreed to:

1. Pay the Plaintiffs $1,050,000 plus interest at 8% per year. The amount due the Plaintiffs is payable between October 1, 2016 and December 31, 2019 with the first payment due October 1, 2016.

2. Return equipment to the Plaintiffs.

3. Issue Mr. Bernal warrants to purchase 3,276,551 restricted shares of the Company’s common stock. The warrants can be exercised any time on or before January 1, 2027 at a price of $.05 per share.

In the event of default all amounts remaining unpaid will be immediately due and payable and the interest rate will increase to 18%. For the interest rate to remain at 8%, the Company is required to make the following payments:

no less than $100,000 by December 31, 2017;

no less than $100,000 by December 31, 2018; and

the balance of $107,995 by December 31, 2019.

If the Company fails to make any of these payments the interest rate will retroactively increase to:

14% for the period between October 1, 2016 through July 1, 2019; and

16% after July 1, 2019.

In the event the interest rate increases, the remaining payments to the Plaintiffs will be adjusted and all amounts payable to the Plaintiffs will be due on October 1, 2020.

Environmental

We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable. The Company was unaware of any material environmental issues as of October 31, 2016.

Employment Agreements

The Company has a written employment agreement with its president, effective January 1, 2015. to his employment agreement, the President will devote such time as each deems necessary to perform his duties to the Company and are subject to conflicts of interest. The employment agreement is an “at will agreement;” however, in the event of termination by the Company, the agreement provides for severance pay equal to one year of base salary in effect at the time of termination. There is also a provision providing for twelve months of base pay in the event of a change in control of the Company. The agreement provides for a two year non-compete in the event of termination. to the employment agreements, effective July 1, 2015, the president will receive a base salary of $234,000 per year. If the Company receives cumulative financing, equity or debt of $4 million, the salary will be increased to $280,000. In addition, if the Company sustains production thresholds of 1,000 BOE/day, 1,500 BOE/day and 2,000 BOE/day, the President’s salary will be increased to $300,000, $325,500 and $360,000 per year, respectively.

The Company has a written employment agreement with its chief financial officer (“CFO”), effective January 1, 2016. to his employment agreement, the CFO will devote such time as each deems necessary to perform his duties to the Company and are subject to conflicts of interest. The employment agreement is an “at will agreement;” however, in the event of termination by the Company, the agreement provides for severance pay equal to one year of base salary in effect at the time of termination. There is also a provision providing for eighteen months of base pay in the event of a change in control of the Company. to the employment agreements, effective January 1, 2016, the CFO will receive a base salary of $220,000 per year.

The Company has a written “at will” employment agreement with its Operations Manager (also a principal shareholder) which provides for annual compensation of $66,000 and provides that when the Company achieves three consecutive months of positive cash flows, and to the extent that the Company would still have positive cash flow in the event the compensation was increased by 50%, then there will be a permanent increase in compensation equal to the current compensation multiplied by 150%. In the event of termination by the Company, the agreement provides for severance pay equal to four months of base salary in effect at the time of termination. There is also a provision providing for twelve months of base pay in the event of a change in control of the Company. The agreement provides for a two year non-compete in the event of termination. The Operations Manager may be granted royalties to the royalty program.

11. Related Parties

The Company has a lease for office space in Littleton, Colorado, with Spotswood Properties, LLC, a Colorado limited liability company (“Spotswood”), and an affiliate of the Company’s president. The Company is currently leasing the office space on a month to month basis under the same terms and conditions as the lease that expired July 31, 2013. The lease provides for the payment of $2,667 per month plus utilities and other incidentals. The president of the Company owns 50% of Spotswood. The Company is of the opinion that the terms of the lease are no less favorable than could be obtained from an unaffiliated party. Spotswood was paid $24,000 and $29,000 in fiscal years 2016 and 2015, respectively.

The Company paid $97,000 and $73,299, in fiscal years 2016 and 2015 respectively, to the President’s brother for land-man fees and expense reimbursements in connection with performing contract land services for the Company.

The Company paid $95,000 and $201,110 to a director for financial public relations consulting in fiscal years 2016 and 2015, respectively.

The Company paid $77,465 to companies owned by President of BIYA Operators Inc., the Company’s wholly owned subsidiary and by his son in fiscal year 2015, no such payment was made in 2016.

12. Acquisition

On February 1, 2016, the Company acquired 100% of the outstanding shares of DESI, a holding company comprised of three oilfield services companies, for 20,032,710 restricted shares of our common stock having a value of approximately $10,016,356, a promissory note in the principal amount of approximately $2,000,000 and the assumption of DESI’s liabilities in the approximate amount of $4,162,900 (subject to adjustment for unknown liabilities). As a result, we recorded goodwill of $3,984,695. The note bears interest at 2% a year and is payable in February 2018.

DESI provides a wide range of services, including Crane and Rigging, Trucking Various Materials, Custom Fabrication, Well Site Construction; including Land cleaning/leveling/grading, Excavation and backfill, Access roads, Pad construction, Tank battery installation teardown, and replacement etc, Well Site Supervision, Pipeline Construction, Pressure Testing, Fencing, Environmental Remediation and Equipment Rental. DESI’s operations are concentrated in northern Colorado and Wyoming.

The consolidated pro forma results of operations as if the acquisition had occurred at the beginning of the last fiscal year and the beginning of this fiscal year are as follows:

The consolidated unaudited pro forma operating revenue and net loss for the twelve months ended October 31, 2015 is $22.6 million and ($2.5) million, respectively, resulting in loss per share of $0.06. The consolidated unaudited pro forma operating revenue and net loss for the three months ended January 31, 2016 is $4.7 million and ($1.4) million, respectively, resulting in loss per share of $0.04.

The Company has included the results of DESI’s operations in its consolidated financial statements beginning on February 1, 2016. Fair values of the assets acquired and liabilities assumed in the acquisition of DESI are summarized below:

The amounts shown above are considered preliminary and are subject to change once the Company receives certain information it believes is necessary to finalize its determination of the fair value of assets acquired and liabilities assumed under the acquisition method. Thus, these amounts are subject to refinement, and additional adjustments to record fair value of all assets acquired and liabilities assumed may be required.

13. Subsequent Events

Effective March 2, 2017, Eric Whitehead was terminated as an officer of the Company.

In February 2017, the Company created Santa Fe Production Fund, LLC (SPD”) for the purpose of offering units of production payment interest and common stocks in the Company. The Company offered up to 100 units at $25,000 per unit, each unit is comprised on the following detachable components:

$35,000 Production Payment Interest in current and future New Mexico production

50,000 shares of common stock

The production payment interest is an economic interest assigned to SPD by Diversified Resources in certain oil and gas wells located in San Juan County, New Mexico. Each unit’s production payment interest will be paid from SPD. Payments will be allocated according to each member’s pro rata percentage ownership proportionate to a full subscription of 100 units. The definition of the production payment interest is 50% of gross monthly production revenues, after the deduction of taxes, royalties, transportation and lease operating expenses. No general corporate or GA expenses will be deducted. The total return on the production payment interest will be capped at 140% of the total value of the unit subscriptions. Once that 140% threshold has been reached for all investors, the LLC will be terminated and the unit investors will cease having any economic interest in any future production and related payments.

On March 24, 2017, the Company signed a subscription agreement with ERG Diversified, LLC (“ERG”). to the subscription agreement ERG purchased 20 units of SPD through an investment of $500,000.

14. Disclosures about Oil and Gas Producing Activities (Unaudited)

Capitalized costs relating to oil and gas producing activities:

Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:

15. Results of Operations for Oil and Gas Producing Activities

The results of operations for oil and gas producing activities, excluding capital expenditures and corporate overhead and interest costs, are as follows (all in the United States):

How We Evaluate Our Operations

Our management uses a variety of financial metrics to analyze our performance. The key financial metric we evaluate is Adjusted EBITDA.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus depreciation, depletion, amortization and accretion, share-based compensation; and excluding the effect of certain other non-cash or non-recurring items that we do not consider to be indicative of our ongoing operating performance such as, but not limited to and accrued liability related to the lawsuit. Adjusted EBITDA is a non-U.S. GAAP financial measure. This measurement is not recognized in accordance with U.S. GAAP and should not be viewed as an alternative to U.S. GAAP measures of performance. The U.S. GAAP measure most directly comparable to Adjusted EBITDA is net income (loss). The presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or non-recurring items.

We believe Adjusted EBITDA is useful to investors in evaluating our operating performance because securities analysts and other interested parties use such calculations as a measure of financial performance and borrowers’ ability to service debt. In addition, Adjusted EBITDA is used by our management for internal planning purposes including certain aspects of our consolidated operating budget and capital expenditures.

However, Adjusted EBITDA has limitations as an analytical tool because it does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments, does not reflect changes in, or cash requirements for, working capital, does not reflect the cash requirements necessary to service principal payments on our outstanding debt, does not reflect payments made or future requirements for income taxes, and excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results of operations. Adjusted EBITDA is a non-U.S. GAAP measure and should not be considered an alternative to net income (loss) or any other performance or liquidity measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculations of Adjusted EBITDA are not necessarily comparable to EBITDA as calculated by other companies. Investors should not rely on these measures as a substitute for any U.S. GAAP measure, including net income (loss).

The following table presents a reconciliation of net loss to Adjusted EBITDA and cash available for distribution for the year ended October 31, 2016:

Our current officers and directors are listed below. Directors are generally elected at an annual shareholders’ meeting and hold office until the next annual shareholders’ meeting, or until their successors are elected and qualified. Executive officers are elected by directors and serve at the board’s discretion.

On November 21, 2013, we acquired all of the outstanding shares of NRG in exchange for 14,558,150 shares of our common stock. In connection with this transaction, Paul Laird, Duane Bacon, Roger May and Albert McMullin were appointed as our officers and/or directors.

The principal occupations of our officers and directors during the past several years are as follows:

Paul Laird was appointed our Chief Executive Officer and a director on November 21, 2013. Since 1997, Mr. Laird has been the Chief Executive Officer and a Director of NRG. Between 2004 and 2009 Mr. Laird was the Chief Executive Officer of New Frontier Energy, Inc. Mr. Laird has over 30 years of experience in the Rocky Mountain oil and gas industry.

Duane Bacon was appointed as our Chief Operating Officer and a director on November 21, 2013. Since December, 2010 Mr. Bacon has been the Chief Operating Officer of NRG. From 2000 to 2010, Mr. Bacon has been the President of Energy Oil and Gas, Inc. a private exploration and production company located in Longmont, Colorado.

Abdul Khan was appointed our Chief Financial and Accounting Officer on January 1, 2016. Since 2014, Mr. khan has been working as consulting CFO on contract basis. Mr. Khan has almost 20 years of experience with progressive leadership roles with medium and large EP and midstream companies.

Roger May was appointed as one of our directors on November 21, 2013. Since 2010, Mr. May has been a director of NRG. Since 2005 Mr. May has been the Chief Executive Officer of RM Advisors, LLC, a firm that consults with development-stage companies in the areas of capital formation and corporate structure. Mr. May has over 25 years of experience in the financial industry with Rauscher Pierce and Schneider Securities.

Albert McMullin was appointed as one of our directors on November 21, 2013. Mr. McMulllin has been a director of NRG since 2011. Since 2010 he has been a senior Vice President of All American Oil and Gas Company, a firm focusing on enhanced oil recovery in California and Texas. Between 2006 and 2010 Mr. McMullin was the President of Standard Investment Company, a firm which provided consulting services to development stage companies. He has over 35 years of experience in the energy field and has worked for Exxon, Atlantic Richfield and United Gas Pipeline.

Mike Miller was appointed as one of our directors on February 1, 2017. Mr. Miller has more than 15 years of Rocky mountain oil and gas experience in oil field services industry. Mr. Miller is founder and president of Champion oilfield services company that he grew from a one-man company to a multi-million dollar company with over 100 employee.

The basis for the conclusion that each current director is qualified to serve as a director is shown below.

Roger May and Albert McMullin are the members of our compensation committee. The Board of Directors serves as our audit committee.

Mr. May and Mr. McMullin, are independent, as that term is defined in Section 803 A(2) of the NYSE MKT Company Guide.

The following table shows the beneficial ownership of our common stock as of January 31, 2017 by (i) each person whom we know beneficially owns more than 5% of the outstanding shares of our common stock; (ii) each of our officers; (iii) each of our directors; and (iv) all the officers and directors as a group. Unless otherwise indicated, each owner has sole voting and investment powers over his shares of common stock. Unless otherwise indicated, beneficial ownership is determined in accordance with the Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended, and includes voting or investment power with respect to shares beneficially owned.

Name and Address		Number of Shares		Percentage
of Beneficial Owner		Beneficially Owned		of Class
Michael Miller		5,032,710		11.21%
16461 HWY 52
Wiggins, CO 80654
Bryan Dale		3,659,289		8.15%
430 Lyons Street
For Collins, CO 80522
K W Capital, LTD		3,642,090		8.11%
5516 West 2nd St Road
Greeley, CO 80634
Rocking R, LLC		3,642,090		8.11%
25749 WCR# 53
Kersey, CO 80644
BrokenN LLC		3,642,090		8.11%
5208 West 14th Street
Greeley, CO 80634
Paul Laird		3,135,642		6.97%
1789 W. Littleton Blvd
Littleton, CO 80120
Duane Bacon		979,508(1)		2.18%
5982 Heather Way
Longmont, CO 80503
Abdul Khan		150,000		0.30%
1789 W. Littleton Blvd
Littleton, CO 80120
Roger May		412,174		1%
2780 Indiana Street
Golden, CO 80401
Albert McMullin		425,000(2)		1%
4501 Merrie Lane
Belaire, TX 77401
All officers and directors		24,720,593		55.06%
as a group (four persons).

The following table shows the aggregate fees billed by Frazer Deeter to us for the periods ending October 31, 2015 and 2016, respectively.

Audit fees represent amounts invoiced for professional services rendered for the audit of our 2015 annual financial statements and the reviews of the financial statements included in our 2016 10-Q reports. All other fee relates to legal fees paid to various attorneys for litigation, corporate and securities related work.

		January 31,			October 31,
ASSETS
CURRENT ASSETS
Cash		$	46,234			$	197,389
Accounts receivable, trade			1,513,435				1,543,652
Prepaid assets			116,194				73,857
Accrued revenue			535,884				470,494
Total current assets			2,211,747				2,285,392
LONG-LIVED ASSETS
Property and Equipment, net of accumulated depreciation and
amortization of $1,690,999 and $1,456,242			8,248,752				8,807,447
Bonds and deposits			160,360				160,897
Oil and gas properties – proved developed (successful efforts method)
net of accumulated depletion and impairment of $2,690,921 and $2,690,921			1,215,294				1,215,294
Oil and gas properties – proved undeveloped (successful efforts method)			1,241,724				1,241,724
Oil and gas properties – unproved (successful efforts method)			2,932,730				2,932,730
Land and other equipment			214,088				340,257
Goodwill			4,735,139				4,735,139
Total assets		$	20,959,834			$	21,718,878
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	2,257,623			$	1,726,047
Accounts payable, related party			424,145				400,845
Current portion of notes payable			1,389,142				1,384,191
Note payable related party			107,070				107,070
Accrued interest, related party			26,081				26,081
Estimated income tax liability			410,620				441,744
Line of credit			115,380				174,862
Accrued expenses			566,380				609,570
Total current liabilities			5,296,441				4,870,410
LONG TERM LIABILITIES
Long term debt, notes payable			7,984,852				8,622,519
Asset retirement obligation			366,498				362,350
COMMITMENTS AND CONTINGENT LIABILITIES
STOCKHOLDERS’ EQUITY
Preferred stock, $0.001 par value 50,000,000 shares authorized:			–				–
301,000 shares issued and outstanding in 2015
Common stock, $0.001 par value, 450,000,000 shares authorized,
44,883,462 and 23,215,926 shares issued and outstanding in 2017 and 2015, respectively			44,883				44,884
Additional paid in capital			20,087,866				20,087,866
Accumulated deficit			(12,820,706	)			(12,269,149	)
Total stockholders’ equity			7,312,043				7,863,601
Total liabilities and stockholders’ equity		$	20,959,834			$	21,718,601

Diversified Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
		Three Months Ended
		January 31,			January 31,
Operating revenues
Oil and gas sales		$	43,788			$	34,548
Oilfield and construction services			3,212,625				–
Revenue – other			4,443				–
Total operating revenue			3,260,856				34,548
Cost of services
Subcontractor expenses			1,143,153				–
Field payroll			846,366				–
Fuel expenses			132,050				–
Equipment rental			215,260				–
Material			66,235				–
Total cost of services			2,403,064				–
Gross margin			857,792				34,548
Operating expenses
Lease operating expenses			98,162				81,688
General and administrative			863,383				277,061
Insurance expense			116,179				–
Depreciation expense			286,365				74,502
Depletion expense							7,778
Production tax and royalty expense			11,662				12,830
Accretion expense			4,148				8,736
Total operating expenses			(1,380,031	)			462,595
(Loss) from operations			(552,239	)			(428,047	)
Other income (expense)
Loss on sale of assets			(27,652	)
Interest expense			(53,050	)			(58,783	)
Other income (expense), net			(80,702	)			(58,783	)
Net (loss)		$	602,941			$	(486,830	)
Net (loss) per common share
Basic and diluted		$	(0.01	)		$	(0.02	)
Weighted average shares outstanding
Basic and diluted			44,509,074				22,904,666

Diversified Resources, Inc.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		January 31,			January 31,
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities		$	88,371			$	(50,483	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets			206,042				–
Net cash provided by investing activities			206,042				–
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable							200,000
Payments on notes payable			(445,568	)			(6,802	)
Net cash provided by financing activities			(445,568	)			193,198
INCREASE IN CASH			(151,155	)			142,715
BEGINNING BALANCE			197,389				21,706
ENDING BALANCE		$	46,234			$	164,421
Cash paid for income taxes		$				$	–
Cash paid for interest		$	53,050			$	2,196

Asset retirement obligation as of beginning of period		$	362,350			$	321,101
Liabilities added			–				–
Liabilities settled			–				–
Revision of estimated obligation			–				–
Accretion expense on discounted obligation			4,148				41,249
Asset retirement obligation as of end of period		$	366,498			$	362,350

Heavy Equipment	3-15 years
Furniture and fixture	3-5 years
Vehicles	3-7 years

Selected Financial Data;		Three months ended
		January 31, 2017
Sales
Oil and Gas		$	43,788
Oilfield Services			3,217,068
Total Sales		$	3,260,856
Segment income (loss) and reconciliation before tax
Oil and Gas		$	(95,983	)
Oilfield Services			409,475
Total segment income (loss)		$	313,492
Reconciling items
General and administrative		$	863,383
Interest			53,050
Net loss		$	(602,941	)
Total assets
Oil and Gas		$	7,298,336
Oilfield Services			13,661,497
		$	20,959,834

		January 31,			October 31,
Heavy equipment		$	6,992,308			$	7,316,088
Pickup trucks			844,494				844,494
Other property and equipment			2,317,037				2,443,364
			10,153,839				10,603,946
Less accumulated depreciation and amortization			(1,690,999	)			(1,456,242	)
Property and equipment, net		$	8,462,840			$	9,147,704

		January 31,			October 31,
Convertible promissory note		$	248,895			$	248,895
BIYA note			1,860,000				1,860,000
BIYA settlement			486,161				486,161
Convertible promissory notes			1,450,000				1,450,000
Discount on convertible promissory notes			(36,000	)			(54,000	)
DESI note			2,000,000				2,000,000
DESI settlement			912,169
Installment loan			2,452,769				2,965,598
			9,373,994				8,956,710
Less current portion			1,389,142				(1,384,191	)
		$	7,984,852			$	7,572,519

Current assets, including cash and cash equivalents of $503,389		$	3,906,845
Property, plant and equipment			8,270,765
Bonds and other assets			16,000
Total assets acquired			12,196,610
Current liabilities			(1,487,535	)
Long-term liabilities			(3,427,858	)
Net assets acquired			7,281,217
Goodwill			4,735,139
Net consideration		$	12,016,356