UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x Quarterly Report Pursuant To Section 13 or 15(d) Of The Securities Exchange Act Of 1934

For the quarterly period ended July 31, 2015

o Transition Report Under Section 13 or 15(d) of the Securities Exchange Act Of 1934

For the transition period from _______________ to _______________

COMMISSION FILE NUMBER    333-175183

DIVERSIFIED RESOURCES INC.

(Exact name of registrant as specified in its charter)

NEVADA	98-0687026
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1789 W. Littleton Blvd., Littleton, CO 80120

(Address of principal executive offices, including zip code)

303-797-5417

(Issuer’s telephone number, including area code)

Check whether the issuer (1) filed all reports required to be filed by section 13 or 15(d) of the Exchange Act during the past 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 x  No o

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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes o  No x

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date. 23,165,926 shares of common stock as of September 10, 2015.

1

DIVERSIFED RESOURCES, INC.

Index

		Page
Part I – FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Consolidated Balance Sheets as of July 31, 2015 (unaudited) and October 31, 2014	3
	Consolidated Statements of Operations for the three months ended July 31, 2015 and 2014 (unaudited)	4
	Consolidated Statements of Operations for the nine months ended July 31, 2015 and 2014 (unaudited)	5
	Condensed Consolidated Statements of Cash Flows for the nine months ended July 31, 2015 and 2014  (unaudited)	6
	Notes to Condensed Consolidated Financial Statements (unaudited)	7 - 13
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19
Item 4.	Controls and Procedures	19
Part II – OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	19
Item 6.	Exhibits	20
SIGNATURES		21

2

PART I

ITEM 1.  FINANCIAL STATEMENTS

Diversified Resources, Inc.

CONSOLIDATED BALANCE SHEETS

	July 31,			October 31,
	2015			2014
	(unaudited)
ASSETS
CURRENT ASSETS
Cash	$	79,861		$	209,054
Accounts receivable, trade		44,700			130,495
Prepaid expenses		3,363			7,948
Total current assets		127,924			347,497
LONG-LIVED ASSETS
Property and Equipment, net of accumulated depreciation
of $269,896 and $149,957		1,805,739			1,904,403
Bonds and deposits		167,867			167,867
Oil and gas properties - proved (successful efforts method)
net of accumulated depletion of $191,817 and $100,062		3,746,399			3,806,153
Oil and gas properties - proved undeveloped (successful efforts method)		1,209,724			1,209,724
Oil and gas properties - unproved (successful efforts method)		2,932,730			2,932,730
Total assets	$	9,990,383		$	10,368,374
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	296,633		$	221,880
Accounts payable, related party		119,736			145,473
Current portion of notes payable		319,633			373,846
Note payable – related party		107,070			-
Accrued interest, related party		12,588			4,579
Accrued expenses		409,363			560,548
Total current liabilities		1,265,023			1,306,326
LONG TERM LIABILITIES
Long term debt, related party		-			107,070
Long term debt, notes payable		3,292,639			2,294,943
Asset retirement obligation		313,144			290,312
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value  50,000,000 shares authorized:
none issued and outstanding
Common stock, $0.001 par value, 450,000,000 shares authorized,
23,165,926 and 22,502,206 shares issued and outstanding in 2015 and 2014 respectively		23,166			22,502
Additional paid in capital		9,292,610			8,629,554
Accumulated deficit		(4,196,199	)		(2,282,333	)
Total stockholders' equity		5,119,577			6,369,723
Total liabilities and stockholders' equity	$	9,990,383		$	10,368,374

See accompanying notes to the financial statements.

3

Diversified Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	Three Months Ended
	July 31,			July 31,
	2015			2014
Operating revenues
Oil and gas sales	$	161,052		$	46,352
Operating expenses
Lease operating expenses		218,130			84,205
General and administrative		363.790			335,287
Depreciation expense		41,768			3,820
Depletion expense		25,263			9,974
Production tax and royalty expense		49,643			-
Accretion expense		7,870			2,000
Total operating expenses		706,464			435,286
Loss from operations		(545,412	)		(388,934	)
Other expense
Interest expense		(41,555	)		(7,245	)
Other expense		(41,555	)		(7,245	)
Net loss	$	(586,967	)	$	(396,179	)
Net loss per common share
Basic and diluted	$	(0.03	)	$	(0.02	)
Weighted average shares outstanding
Basic and diluted		22,851,919			19,237,363

See accompanying notes to the financial statements.

4

Diversified Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	Nine Months Ended
	July 31,			July 31,
	2015			2014
Operating revenues
Oil and gas sales	$	518,865		$	68,992
Operating expenses
Exploration costs, including dry holes		16,513			41,801
Lease operating expenses		557,400			206,223
General and administrative		1,348,934			850,909
Depreciation expense		125,304			11,178
Depletion expense		86,389			14,074
Production tax and royalty expense		194,567			-
Accretion expense		22,832			6,000
Total operating expenses		2,351,939			1,130,185
Loss from operations		(1,833,074	)		(1,061,193	)
Other expense
Interest expense		(80,792	)		(50,846	)
Other expense, net		(80,792	)		(50,846	)
Net loss	$	(1,913,866	)	$	(1,112,039	)
Net loss per common share
Basic and diluted	$	(0.08	)	$	(0.06	)
Weighted average shares outstanding
Basic and diluted		22,940,864			18,167,691

See accompanying notes to the financial statements.

5

Diversified Resources, Inc.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	July 31,			July 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash used in operating activities	$	(1,683,121	)	$	(1,299,731	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for oil and gas properties		(32,002	)		-
Cash paid for purchase of property and equipment		(21,273	)		(1,278	)
Net cash used in investing activities		(53,275	)		(1,278	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock		663,720			1,347,000
Proceeds from notes payable		1,000,000			-
Payment on notes payable		(56,517	)		(3,312	)
Net cash provided by financing activities		1,607,203			1,343,688
INCREASE (DECREASE) IN CASH		(129,193	)		42,679
BEGINNING BALANCE		209,054			69,433
ENDING BALANCE	$	79,861		$	112,112
Cash paid for interest	$	29,620		$	21,316
Supplemental schedule of non-cash investing and
financing activities:
Issuance of common stock for Natural Resource Group, Inc. common stock	$	-		$	14,558
Forgiveness of related party notes	$	-		$	14,040
Assumption of liabilities by former officer and shareholder	$	-		$	283,701

See accompanying notes to the financial statements.

6

DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

NOTE 1 – BASIS OF PRESENTATION

The interim condensed consolidated financial statements of Diversified Resources, Inc. (“we”, “us”, “our”, “Diversified”, or the “Company”) are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair presentation of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, interest rates, drilling risks, geological risks, the timing of acquisitions, and our ability to obtain additional capital. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended October 31, 2014 as filed with the Securities and Exchange Commission (“SEC”) on February 13, 2015.  The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

The condensed consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with US GAAP. Accordingly, these condensed consolidated financial statements do not include all of the information and footnotes required by US GAAP for annual consolidated financial statements.

Although, from a legal standpoint, we acquired Natural Resource Group, Inc. (“NRG”) on November 21, 2013, for financial reporting purposes the acquisition of NRG constituted a recapitalization, and the acquisition was accounted for as a reverse merger, whereby NRG was deemed to have acquired us.  

The condensed consolidated financial statements are unaudited, but, in management's opinion, include all adjustments (which, unless otherwise noted, include only normal recurring adjustments) necessary for a fair presentation of such condensed consolidated financial statements.

NOTE 2 – ORGANIZATION AND GOING CONCERN

We incorporated in the State of Nevada on March 19, 2009 to pursue mineral extraction in the United States.

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 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.

NRG was incorporated in Colorado in 2000 but was relatively inactive until December 2010.  In December 2010, NRG acquired oil and gas wells, leases and other properties from Energy Oil and Gas, Inc.

As shown in the accompanying condensed consolidated financial statements, the Company has incurred significant operating losses since inception, has an accumulated deficit of $4,196,199 and has negative working capital of $1,137,099 at July 31, 2015.  As of July 31, 2015, 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 and obtaining additional financing, and 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 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.

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The accompanying condensed consolidated unaudited financial statements include the accounts of Diversified and its wholly owned subsidiaries, NRG and BIYA Operators, Inc. All inter-company accounts and transactions have been eliminated.

7

DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

Cash and cash equivalents

The Company considers all liquid investments with a maturity of three months or less from the date of purchase that are readily convertible into cash to be cash equivalents.

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Estimates of oil and gas reserve quantities provide the basis for the 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.

Revenue Recognition

We recognize oil and gas revenue from interests in producing wells as the oil and 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 July 31, 2015 and 2014 was immaterial.

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 (“DD&A”) 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 undiscounted 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.

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 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

8

DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

sufficient progress assessing the reserves and the economic and operating viability of the project.  Geological and geophysical costs were $16,513 and $41,801 for the nine months ended July 31, 2015 and 2014, respectively, and are included in Exploration Costs in the accompanying financial statements.

Asset Retirement Obligations   Asset retirement obligations (“ARO”) 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 and included in our DD&A 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.

The following table reconciles the asset retirement obligation for nine months ended July 31, 2015 and year ended October 31, 2014:

	2015		2014
Asset retirement obligation as of beginning of period	$	290,312	$	222,375
Liabilities added		-		43,883
Accretion expense on discounted obligation		22,832		24,054
Asset retirement obligation as of end of period	$	313,144	$	290,312

Property and Equipment

Property and equipment consists of production buildings, furniture, fixtures, equipment and vehicles which are recorded at cost and depreciated using the straight-line method over the estimated useful lives of five to fifteen years.

Maintenance and repairs are charged to expense as incurred.

Income Taxes

We account for income taxes in accordance with FASB ASC Topic 740, Income Taxes.  Under this standard, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using the enacted tax rates in effect for the year in which the differences are expected to reverse.  Deferred tax assets are reduced by a valuation allowance when we cannot make the determination that it is more likely than not that some portion or all of the related tax asset will be realized. Interest and penalties on tax deficiencies recognized in accordance with FASB accounting standards are classified as income taxes in accordance with FASB ASC Topic 740-10-50-19. The Company follows FASB ASC 740-10-05 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 on 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.

Contingent Liabilities

The Company records contingent liabilities when the amounts are incurred and reasonably estimable. Otherwise the Company will disclose the matter(s) and provide a range or best estimate of the contingency in the notes to the financial statements. As of July 31, 2015 there were no legal proceedings against the Company. Neither the Company nor any of its officers or directors is involved in any litigation either as plaintiffs or defendants, and have no knowledge of any threatened or pending litigation against them or any of the officers or directors. As of July 31, 2015, there were no contingent liabilities that required disclosure or accrual in the Company’s financial statements.

9

DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

Loss Per Share

The Company computes net loss per share in accordance with FASB ASC Topic 260, “Earnings per Share,” Under the provisions of the standard, basic and diluted net loss per share is computed by dividing the net loss available to common stockholders for the period by the weighted average number of shares of common stock outstanding during the period. During periods when losses occur, common stock equivalents, if any, are not considered in the computation as their effect would be anti-dilutive.

Recent Accounting Pronouncements

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

NOTE 4 – Participation Agreement

In connection with the convertible promissory note described in Note 6, 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. During 2012, $250,000 was advanced to the Company. In consideration for extending this credit arrangement, the lender was assigned a 1% overriding royalty interest in the 4,600 acre field, a 20% modified net profits interest in the existing four producing wells in the Garcia Field and a 20% modified net profits interest in three additional wells to be drilled on the acreage. The Company valued the net profits interest and the overriding royalty interest at $136,599 using 10% present value over the estimated life of the wells. The amount was recorded as a debt discount and is being amortized using the effective interest rate method over the life of the promissory note (3 years).Additionally, the lender has the right, at any point during the period of the note, to convert the remaining principal balance on the note to a working interest.

The modified net profits interest is based on the gross proceeds from the sale of oil, gas and other minerals in the four producing wells in the Garcia Field and three additional wells to be drilled. The 20% is applied to 100% of the Company’s net revenue interest in the wells which cannot be less than 80% and is reduced by any of the following expenditures:

● any overriding royalties or other burden on production in excess of the 80% net revenue interest;

● production, severance and similar taxes assessed by any taxing authority based on volume or value of the production;

● direct costs incurred in producing oil or natural gas, or the operation of the wells excluding administrative, supervisory or other indirect costs;

● costs reasonably incurred to process the production for market;

● costs reasonably incurred in transportation, delivery, storage or marketing the production.

NOTE 5 – Notes Payable – Related Party

In December 2010, the Company entered into a purchase and sale agreement to acquire certain oil and gas assets located in Adams, Broomfield, Huerfano, Las Animas, Morgan and Weld counties, 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 and matures on December 11, 2015.  The balance on the note is $107,070 at July 31, 2015 with interest accrued in the amount of approximately $12,588.

NOTE 6 – Long Term Debt and Note Payable

Convertible Promissory Note—On January 12, 2012 the Company entered into a convertible promissory note bearing interest at 10%, due January 11, 2014 which was extended to January 2016. The note is collateralized by a first priority deed of trust on approximately 4,600 acres of oil and gas leasehold interests in the Garcia Field, together with the existing wells and equipment in the field. The balance at July 31, 2015 was $248,895. The lender has the right to convert the principal to a 10% working interest in the collateral as well as a 10% interest in all wells owned by the Company in the Garcia Field in which the lender does not have the 20% modified net profits interest described in Note 4. In the event the principal is less than $350,000, the conversion percentage shall be reduced proportionately.

10

DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

The Company has the right to prepay the note without penalties or fees after giving the lender ten days’ notice of its intent. If the lender does not elect to convert within 10 days after receiving said notice, the conversion rights terminate.  The Company recorded a discount to the debt of $136,599 and recognized accretion of the discount in the amounts of $0 and $19,516 for the nine months ended July 31, 2015 and 2014 respectively. The ending balance of the debt discount at July 31, 2015 was $0.   The Company reviewed the note for beneficial conversion features and embedded derivatives and determined that neither applied. 

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 approximately $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 will bear interest at 5% a year and will be payable in October 2016.

In May 2012 BIYA entered into a settlement agreement with a previous partner for $1.2 million. The agreement was amended effective April 1, 2015, where the balance due will bear interest at 6% a year and has a fixed monthly payment of $5,500 per month until paid in full. The balance due was $492,208 at July 31, 2015.

Secured Notes—In March, April 2015, June 2015 and July 2015, the Company issued secured notes in the principal amounts of $250,000, $400,000, $200,000 and $150,000 respectively, bearing interest at 12% payable quarterly beginning June 1, 2015 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 note guarantees one year of interest and would be due even upon prepayment of note during the first year. The lenders received two year warrants which entitles the holders to purchase up to 200,000 shares of the Company’s common stock at a price of $0.80 per common share. Based on the number of warrants issued, the Company believes the value of these warrants is immaterial at July, 31 2015. The secured notes had accrued interest payable of approximately $17,500 at July 31, 2015.      

Installment Loan—The Company entered into an installment loan on July 4, 2013 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.

The following summarizes the notes payable at:

	July 31, 2015			October 31, 2014
Convertible promissory note	$	248,895		$	248,895
BIYA note		1,860,000			1,860,000
BIYA settlement		492,208			546,144
Secured notes		1,000,000			-
Other notes		11,169			13,750
		3,612,272			2,668,789
Current portion		(319,633	)		(373,846	)
	$	3,292,639		$	2,294,943

NOTE 7 – INCOME TAXES

No provision was made for federal income tax for the three and nine months ended July 31, 2015 and 2014, since the Company had net operating losses.

NOTE 8 – STOCKHOLDERS’ EQUITY

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. As of July 31, 2015, 23,165,926 shares of common stock and no preferred shares were issued and outstanding. During the nine months ended July 31, 2015, the Company sold 663,720 shares of its common stock to a group of private investors for a cash of $663,720.

NOTE 9 – RELATED PARTY TRANSACTIONS

Natural Resource Group, Inc. has an office lease for office space in Littleton, Colorado, with Spotswood Properties, LLC, a Colorado limited liability company (“Spotswood”), and an affiliate of the president, effective January 1, 2009, for a three-year term. Commencing July 1, 2010 the Company entered into a new lease for office space for a 3 year period ending July 1, 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.

11

DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

Spotswood was paid $10,667 and $26,667 in three and nine months ended July 31, 2015 and 2014, respectively.  The Company has accrued a liability in the amount of $5,333 for accrued rent.  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 Company paid a director and shareholder $48,000 and $152,000 in the three and nine months ended July 31, 2015, respectively and $53,700 and $132,650 in the three and nine months ended July 31, 2014, each, for financial public relations consulting.

The Company paid the President’s brother $18,162 and $57,724 in the three and nine months ended July 31, 2015, respectively and $15,685 and $39,685 in the three and nine months ended July 31, 2014, respectively for landman consulting services. 

NOTE 10 – ACQUISITION

On October 14, 2014 the Company acquired approximately 98% of the outstanding shares of BIYA Operators, Inc. (“BIYA”) an independent oil and gas company, for cash of $174,000, 900,000 restricted shares of common stock having a value of $900,000, a promissory note in the principal amount of $1,860,000 (subject to adjustment for unknown liabilities) and the assumption of liabilities of BIYA in the approximate amount of $2,000,000.  The note will be effective when certain leases covering Indian tribal lands have been issued.  The note will bear interest at 5% a year and will be payable in October 2016. The Company did not incur material costs in acquiring BIYA. The transaction was effective October 1, 2014 and was accounted for as a business combination.

BIYA was incorporated under the laws of New Mexico in September, 2011 to pursue mineral extraction.  BIYA conducts operations in the United States primarily in the Horseshoe Gallop field in San Juan County, New Mexico.

BIYA has oil and gas leases 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. Under the agreement, BIYA is to drill 2 wells by April 2016, April 2017 and April 2018, respectively. After April 2018, BIYA is required to drill one well per year. Per the agreement, if BIYA drills and completes a well, and establishes production from that well, it will own a lease for that well, plus the applicable well spacing unit acreage surrounding that well, ranging from 40 acres to 320 acres, based on the formation drilled, from the date of filing an application for permit to drill and for as long as hydrocarbons are produced in paying quantities. All leases held by BIYA carry a royalty between 12.5% and 20%.

The Company has included the results of BIYA’s operations in its consolidated financial statements beginning on October 1, 2014. Fair values of the assets acquired and liabilities assumed in the acquisition of BIYA are summarized below:

Current assets, including cash and cash equivalents of $98,809	$	242,788
Property, plant and equipment		1,854,900
Oil and gas properties		5,244,755
Bonds and other assets		167,368
Total assets acquired		7,509,811
Current liabilities		(1,624,167	)
Long-term liabilities		(367,460	)
Net assets acquired	$	5,518,184
Bargain purchase gain		(2,584,184	)
Net consideration		2,934,000

The consideration consisted of cash of $174,000, the issuance of a note in the amount of $1,860,000, and the issuance of 900,000 common shares with a fair value of $900,000.

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 purchase 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.

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DIVERSIFIED RESOURCES INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

July 31, 2015

On January 29, 2015, the Company entered into a participation agreement with Palo Petroleum, Inc. (“Palo”), where Palo acquired the right to participate in all of our future operations in the Horseshoe Gallup Field, not related to the existing wells or existing production, but including the drilling of any future wells. Palo also has the right to participate in such future operations as a 40.00% of 8/8 Working Interest owner on a heads-up or non-promoted basis.

In addition, the Company entered into an Area of Mutual Interest Agreement (“AMI”) with Palo relating to all lands in San Juan County, New Mexico outside the Horseshoe Gallup Field. Under this agreement, Palo and we will be entitled to participate in up to 50% in any leasehold or fee mineral interest within the AMI which is acquired by either Palo or us.

NOTE 11 – COMMITMENTS AND CONTINGENCIES

Legal—The Company is not subject to any legal claims.

Environmental—The Company accrues 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.

Concentration – The Company sells 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.

 NOTE 12 – SUBSEQUENT EVENTS

On September 1, 2015, the Company executed a non-binding letter of intent (“LOI”) with Bayou City Energy, L.P. (“BCE”) to jointly form an entity (“DrillCo”) for development drilling on the Company’s San Juan Basin properties in northwestern New Mexico.

The LOI covers BCE’s intent to fund a portion of 55 wells located across the Company’s existing 10,000 gross acre leasehold, as well as any future wells drilled during the ensuing three years (“Expansion Phase”) across an Area of Mutual Interest (“AMI”) in the Four Corner’s Uplift region of the San Juan Basin. The terms of the LOI call for the establishment and funding of an entity formed by the Company and BCE. through which, BCE will fund between 50% and 90% of the wells’ costs in exchange for a preferred return and reversionary economic interests.  The drilling program is delineated into three phases; a “Test Phase”, a “Development Phase” and an “Expansion Phase”. After a preferred return has been reached for BCE in each Phase, the Company’s percentage of net revenues from the wells increases to between 65% and 85%, depending under which Phase the wells are drilled.

Completion of this agreement will depend upon a number of conditions, including, but not limited to: completion of due diligence, approval of the final terms of definitive agreements by BCE’s Investment Committee and the Company, receipt of all necessary regulatory and third party consents and approvals, regulatory and permitting approval of all “Test Phase” wells and the successful fundraise by the Company of no less than $1,000,000 of Series A Convertible Preferred Units.

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ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our condensed consolidated financial statements included as part of this report.

Unless the context otherwise requires, references to the “Company”, “Diversified”, “we”, “us” or “our” mean Diversified Resources, Inc. and its consolidated subsidiaries.

Cautionary Statements Regarding Forward-Looking Statements.  Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions.  Forward-looking statements appear throughout this Form 10-Q with respect to, among other things:  profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations.  Forward-looking statements involve known and unknown risks and uncertainties that could cause actual results to differ materially from those contained in any forward-looking statement.

While we have made assumptions that we believe are reasonable, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change.  All forward-looking statements in the Form 10-Q are qualified in their entirety by the cautionary statement contained in this section.  We do not undertake to update, revise or correct any of the forward-looking information.  These financial statements should be read in conjunction with the financial statements and notes thereto included in our Form 10-K for our fiscal year ended October 31, 2014.

We were incorporated on March 19, 2009 in Nevada.  In 2009, we leased two unpatented mining claims located in Esmeralda County, Nevada.  In January 2011, we staked an additional twenty unpatented mining claims in the same area.  Due to the lack of capital, we terminated the mining lease in November 2013. We have no plans to conduct any work on the unpatented mining claims.

On 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.

NRG was incorporated in Colorado in 2000 but was relatively inactive until December 2010.

In December 2010 NRG acquired oil and gas properties from Energy Oil and Gas, Inc. for 2,500,000 shares of its common stock and a promissory note in the principal amount of $360,000.  As of July 31, 2015, the principal amount of this note was $107,070.

Included as part of the acquisition were:

Garcia Field

● leases covering 4,600 gross (4,600 net) acres,

● four wells which produce natural gas and naturals gas liquids;

● a refrigeration/compression plant which separates natural gas liquids from gas produced from the four wells; and

● one injection well;

The Garcia Field is located in Las Animas County, Colorado, approximately 10 miles from Trinidad, Colorado.  

Denver-Julesburg Basin

● leases covering 1,400 gross (1,400 net) acres,

● three shut-in wells which need to be recompleted; and

● three producing oil and gas wells.

Subsequent to December 2010, leases covering 160 acres in the Garcia Field were sold and leases covering 960 acres in the Garcia Field expired.  In 2013, we acquired a 640 acre lease (100% working interest, 80% net revenue interest) in the D-J Basin. The Denver-Julesburg (“D-J”) Basin is located in Northeastern Colorado.

During the year ending July 31, 2016, we plan to drill one new well at a cost of approximately $800,000.

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Horseshoe - Gallup Field

On October 14, 2014 we acquired approximately 98% of the outstanding shares of BIYA Operating, Inc. (“BIYA”) for cash of $174,000, 900,000 restricted shares of our common stocks having a value of approximately $900,000, a promissory note in the principal amount of approximately $1,860,000 (subject to adjustment for unknown liabilities) and the assumption of liabilities of BIYA in the approximate amount of $2,000,000.  The note will be effective when certain leases covering Indian tribal lands have been issued.  The note will bear interest at 5% a year and will be payable in October 2016.

Included as part of the acquisition were:

● 48 producing oil and gas wells, all of which we operate,

● leases covering approximately 10,000 gross and net acres, and

● miscellaneous equipment.

BIYA has oil and gas leases 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. Under the agreement, BIYA is to drill 2 wells by April 2016, April 2017 and April 2018, respectively. After April 2018, BIYA is required to drill 1 well per year. Per the agreement, if BIYA drills and completes a well, and establishes production from that well, it will own a lease for that well plus the applicable well spacing unit acreage surrounding that well, ranging from 40 acres to 320 acres based on the formation drilled, from the date of filing an application for permit to drill and for as long as hydrocarbons are produced in paying quantities. These leases carry royalties between 12.5% and 20%.

During the year ending July 31, 2016, we plan to:

● rework 50 producing and shut-in wells at a total cost of approximately $400,000

● drill 5 new wells with our portion of the cost being approximately $150,000 per well.

● drill 15 new wells with our portion of the cost being approximately $30,000 per well.

On January 29, 2015, we entered into a participation agreement with Palo Petroleum, Inc. (“Palo”), where Palo acquired the right to participate in all of our future operations in the Horseshoe Gallup Field, not related to the existing wells or existing production, but including the drilling of any future wells. Palo also has the right to participate in such future operations as a 40.00% of 8/8 Working Interest owner on a heads-up or non-promoted basis.

In addition, we entered into an Area of Mutual Interest Agreement (“AMI”) with Palo relating to all lands in San Juan County, New Mexico outside the Horseshoe Gallup Field. Under this agreement, Palo and we will be entitled to participate in up to 50% in any leasehold or fee mineral interest within the AMI which is acquired by either Palo or us.

On September 1, 2015, the Company executed a non-binding letter of intent (“LOI”) with Bayou City Energy, L.P. (“BCE”) to jointly form an entity (“DrillCo”) for development drilling on the Company’s San Juan Basin properties in northwestern New Mexico.

The LOI covers BCE’s intent to fund a portion of 55 wells located across the Company’s existing 10,000 gross acre leasehold, as well as any future wells drilled during the ensuing three years (“Expansion Phase”) across an Area of Mutual Interest (“AMI”) in the Four Corner’s Uplift region of the San Juan Basin. The terms of the LOI call for the establishment and funding of an entity formed by the Company and BCE through which, BCE will fund between 50% and 90% of the wells’ costs in exchange for a preferred return and reversionary economic interests.  The drilling program is delineated into three phases a; “Test Phase”, a “Development Phase” and an “Expansion Phase”. After a preferred return has been reached for BCE in each Phase, the Company’s percentage of net revenues from the wells increases to between 65% and 85%, depending under which Phase the wells are drilled.

Completion of this agreement will depend upon a number of conditions, including, but not limited to: completion of due diligence, approval of the final terms of definitive agreements by BCE’s Investment Committee and the Company, receipt of all necessary regulatory and third party consents and approvals, regulatory and permitting approval of all “Test Phase” wells and the successful fundraise by the Company of no less than $1,000,000 of Series A Convertible Preferred Units.

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Production, Drilling Activity and Oil and Gas Leases

The following table shows our net production of oil, gas and natural gas liquids for the periods indicated:

	Nine Months Ended July 31,
	2015		2014
Production:
Oil (Bbls)		11,418		421
Gas (Mcf)		1,135		2,087
Natural Gas Liquids (gallons)		-		24,867

The following table shows, as of July 31, 2015, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:

	Productive Wells		Developed Acreage		Undeveloped Acreage(1)
Location	Gross	Net	Gross	Net	Gross	Net
New Mexico:
Horseshoe Gallup Field	48	48	4,440	3,560	5,672	3,403
Colorado:
Garcia Field	5	5	200	200	4,400	4,400
D-J Basin	4	3.75	160	160	760	760

(1) Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.

Results of Operations

Material changes of certain items in our statements of operations included in our financial statements for the periods presented are discussed below. 

For the three months ended July 31, 2015 compared to the three months ended July 31, 2014

For the three months ended July 31, 2015 we reported a loss of $586,967 or $(0.03) per share compared to a net loss of $396,179 or $(0.02) per share for the three months ended July 31, 2014. The increase in the net loss of $190,788 principally resulted from an increase of $133,925 in lease operating expenses due to having a higher number of wells being operated, $37,948 in depreciation expense due to additional assets related to the BIYA acquisition and $28,503 in general and administrative expenses due to having more employees and contractors for the full three-month period and higher costs consistent with being a public company.

Oil and gas sales were $161,052 and $46,352 for the three months ended July 31, 2015 and 2014 respectively; an increase of $114,700 (247%).  The increase is principally attributable to the purchase of BIYA in October 2014 and the related revenue for the quarter.

Lease operating expenses were $218,130 and $84,205 for the three months ended July 31, 2015 and 2014 respectively; an increase of $133,925 (159%).  The increase is principally attributable to the purchase of BIYA in October 2014.

General and administrative expenses were $363,790 and $335,287 for the three months ended July 31, 2015 and 2014 respectively; an increase of $28,503 (9%) mainly due to an increase in payroll expenses due to having more employees and contractors for the full three-month period and higher costs consistent with being a public company.

Depreciation expense was $41,768 and $3,820 for the three months ended July 31, 2015 and 2014 respectively; an increase of $37,948 (993%). The increase arises from additional assets related to the BIYA acquisition in October 2014.

Depletion expense was $25,263 and $9,974 for the three months ended July 31, 2015 and 2014 respectively; an increase of $15,289 (153%). The increase arises from additional properties and production related to the BIYA acquisition in October 2014.

Production tax and royalty expense was $49,643 and $0 for the three months ended July 31, 2015 and 2014 respectively. The increase arises from production tax and royalty expense paid on the BIYA production, which was acquired in October 2014. Historically production tax and royalty was immaterial and was not disclosed separately.

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Accretion expense was $7,870 and $2,000 for the three months ended July 31, 2015 and 2014 respectively; an increase of $5,870 (294%).  The increase is a result of the BIYA acquisition in October 2014.

Interest expense was $41,555 and $7,245 for the three months ended July 31, 2015 and 2014 respectively; an increase of $34,310 (474%). The increase is due to increase in debt and interest paid on royalties payable.

For the nine months ended July 31, 2015 compared to the nine months ended July 31, 2014

For the nine months ended July 31, 2015 we reported a loss of $1,913,866 or $(0.09) per share compared to a net loss of $1,112,039 or $(0.06) per share for the nine months ended July 31, 2014. The increase in the net loss of $801,827 principally resulted from an increase of $351,177 in lease operating expenses due to having a higher number of wells being operated and $498,025 in general and administrative expenses due to having more employees and contractors for the full three-month period and higher costs consistent with being a public company.

Oil and gas sales were $518,865 and $68,992 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $449,873 (652%).  The increase is principally attributable to the purchase of the BIYA in October 2014 and the related revenue for the nine months ended July 31, 2015.

Exploration costs were $16,513 and $41,801 for the nine months ended July 31, 2015 and 2014 respectively; a decrease of $25,288 (60%). We did not incur any significant exploration activities during the nine months ended July 31, 2015.

Lease operating expenses were $557,400 and $206,223 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $351,177 (170%).  The increase is principally attributable to the purchase of BIYA in October 2014.

General and administrative expenses were $1,348,934 and $850,909 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $498,025 (59%).  Consulting fees increased by $101,870, due to the increase in equity investment activities and payroll expense an increased by $265,770 due to increase in employee count.

Depreciation expense was $125,304 and $11,178 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $114,126 (1021%). The increase arises from additional assets related to the BIYA acquisition in October 2014.

Depletion expense was $86,389 and $14,074 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $72,315 (514%). The increase arises from additional properties and production related to the BIYA acquisition in October 2014.

Production tax and royalty expense was $194,567 and $0 for the nine months ended July 31, 2015 and 2014 respectively. The increase arises from production tax and royalty expense paid on BIYA production, which was acquired in October 2014. Historically production tax and royalty was immaterial and was not disclosed separately.

Accretion expense was $22,832 and $6,000 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $16,832 (281%).  The increase is a result of BIYA acquisition in October 2014.

Interest expense was $80,792 and $50,846 for the nine months ended July 31, 2015 and 2014 respectively; an increase of $29,946 (59%). The increase arises from an increase in interest bearing loans.

Liquidity and Capital Resources

Our sources and (uses) of funds for the nine months ended July 31, 2015 and 2014 are shown below:

	2015			2014
Cash used in operations	$	(1,683,121	)	$	(1,299,731	)
Purchase of oil and gas properties		(32,002	)		-
Purchase of equipment		(21,273	)		(1,278	)
Sale of common stock		663,720			1,347,000
Proceeds from notes payable		1,000,000			-
Payment on notes payable		(56,517	)		(3,312	)

Between November 1, 2014 and July 31, 2015 we sold 663,720 shares of our common stock to a group of private investors for cash of $663,720.

As of July 31, 2015, operating expenses were approximately $113,000 per month, which amount includes salaries and other corporate overhead, but excludes expenses associated with drilling, completing or reworking wells, lease operating expenses and interest expense.

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Our material future contractual obligations as of July 31, 2015 are summarized as follows:

Description	Total		Less then 1 year		1 – 3 years		Thereafter
Notes Payable	$	3,612,272	$	319,633	$	3,292,639		$	-

Any cash generated by operations, after payment of general, administrative and lease operating expenses, will be used to drill and, if warranted, complete oil/gas/ngl wells, acquire oil and gas leases covering lands which are believed to be favorable for the production of oil, gas, and natural gas liquids, and to fund working capital reserves.  Our capital expenditure plans are subject to periodic revision based upon the availability of funds and expected return on investment.

Trends

The factors that will most significantly affect future operating results will be:

● the sale prices of crude oil;

● the amount of production from oil, gas and gas liquids wells in which we have an interest;

● lease operating expenses;

● the availability of drilling rigs, drill pipe and other supplies and equipment required to drill and complete wells; and

● corporate overhead costs.

Revenues will also be significantly affected by our ability to maintain and increase oil, gas and natural gas liquids production.

Other than the foregoing, we do not know of any trends, events or uncertainties that have had, or are reasonably expected to have, a material impact on our revenues or expenses.

It is expected that our principal source of cash flow will be from the sale of crude oil, natural gas and natural gas liquids which are depleting assets. Cash flow from the sale of oil/gas/ngl production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms. However, price increases heighten the competition for oil prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.

A decline in hydrocarbon prices (i) will reduce cash flow which in turn will reduce the funds available for exploring for and replacing reserves, (ii) will increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of  prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential  reserves in relation to the costs of exploration, (v) may result in marginally productive wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. However, price declines reduce the competition for oil properties and correspondingly reduce the prices paid for leases and prospects.

We plan to generate profits by acquiring, drilling and/or completing productive wells.  However, we plan to obtain the funds required to drill, and if warranted, complete new wells with any net cash generated by operations, through the sale of securities, from loans from third parties or from third parties willing to pay our share of the cost of drilling and completing the wells as partners/participants in the resulting wells.  We do not have any commitments or arrangements from any person to provide us with any additional capital.  We may not be successful in raising the capital needed to drill oil wells.  Any wells which may be drilled may not produce oil and/or gas.

As shown in the accompanying financial statements, the Company has incurred significant operating losses since inception, has an accumulated deficit of $4,196,199 and has negative working capital of $1,137,099 at July 31, 2015.  As of July 31, 2015, 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 and obtaining additional financing, and 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. 

Other than as disclosed above, we do not know of any:

● trends, demands, commitments, events or uncertainties that will result in, or that are reasonably likely to result in, any material increase or decrease in liquidity; or

● significant changes in expected sources and uses of cash.

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Critical Accounting Policies and Estimates

See Note 3 to the condensed consolidated financial statements included as part of this report for a description of our significant accounting policies.

Recent Accounting Pronouncements

We do not believe that any recently issued accounting pronouncements will have a material impact on our financial position, results of operations or cash flows.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Not applicable.

ITEM 4.  CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our

Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q.  Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.  Based on that evaluation, our management concluded that, as of July 31, 2015, our disclosure controls and procedures were not effective due to the following:

1. We did not have the proper segregation of duties with respect to our finance and accounting functions due to limited personnel. During the three months ended July 31, 2015 we had independent contractors that performed nearly all aspects of our financial reporting process, including but not limited to, preparation of underlying accounting records and systems, the ability to post and record journal entries and the preparation of the financial statements.  Accordingly, this created certain incompatible duties and a lack of review over the  financial reporting process that may result in a failure to detect errors in spreadsheets, calculations or assumptions used to compile the financial statements and related disclosures as filed with the SEC.  These control deficiencies could result in a material misstatement of our interim or annual financial statements that would not be prevented or detected; and

2. Our corporate governance activities and processes are not formally documented.

We intend to take appropriate and reasonable steps to make the necessary improvements to remediate these deficiencies. Since the acquisition of Natural Resource Group, Inc. on November 21, 2013, the board, as a whole, has been acting as the audit committee and independent board members constitute the compensation committee.  We have adopted a code of ethics and other procedures and changes in our internal controls in response to the requirements of Sarbanes Oxley § 404.  During the fiscal year ending October 31, 2015, we will continue to implement appropriate changes as they are identified, including changes to remediate the significant deficiencies in our internal controls.  There can be no guarantee that we will be successful in making these changes as they may be considered cost prohibitive.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended July 31, 2015, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

During the nine months ended July 31, 2015 we sold 663,720 shares of our common stock to private investors at a price of $1.00 per share. The $663,720 in proceeds was used for operations. We relied upon the exemption provided by Section 4(a)(2) of the Securities Act of 1933 in connection with the sale of these shares. The persons who acquired these shares were sophisticated investors and were provided full information regarding our business and operations. There was no general solicitation in connection with the offer or sale of these securities. The persons who acquired these shares acquired them for their own accounts. The certificates representing these shares will bear a restricted legend providing that they cannot be sold except pursuant to an effective registration statement or an exemption from registration. No commission was paid to any person in connection with the sale of these shares.

ITEM 6.  EXHIBITS

31.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Paul Laird.
31.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Paul Laird.
32	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for Paul Laird.
101	The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Labels, (v) XBRL Taxonomy Extension Presentation, and (vi) XBRL Taxonomy Extension Definition. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by the specific reference in such filing.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	DIVERSIFIED RESOURCES, INC.
Date: September 14, 2015	By:	/s/ Paul Laird
		Paul Laird, Principal Executive, Financial and Accounting Officer

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