Diversified Resources Inc. - FORM 10-K/A

Attached files

file	filename
EX-99.2 - DIVERSIFIED RESOURCES 10K/A, REPORT, MCCARTNEY - Diversified Resources Inc.	diversifiedexh99_2.htm
EX-99.1 - DIVERSIFIED RESOURCES 10K/A, REPORT, MHA - Diversified Resources Inc.	diversifiedexh99_1.htm
EX-31 - DIVERSIFIED RESOURCES 10K/A, CERTIFICATION 302 - Diversified Resources Inc.	diversifiedexh31.htm
EX-32 - DIVERSIFIED RESOURCES 10K/A, CERTIFICATION 906 - Diversified Resources Inc.	diversifiedexh32.htm
EXCEL - IDEA: XBRL DOCUMENT - Diversified Resources Inc.	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K /A

Amendment #1

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2014

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________________ to _______________________

Commission file number: 333-175183

DIVERSIFIED REOURCES, 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)		(Zip Code)

Registrant's telephone number, including area code: (303) 797-5417

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock		None

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations 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 filing). Yes x No o

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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

	Large accelerated filer	o		Accelerated filer	o
	Non-accelerated filer	o	(Do not check if a smaller reporting company)	Smaller reporting company	x

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was $15,324,872, based upon the closing sale price of the registrant’s common stock of $1.20 on April 30, 2014 as reported on OTC market. Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.

As of February 2, 2015, the Registrant had 23,165,926 issued and outstanding shares of common stock.

Explanatory Note for Amendment #1:

This Amendment #1 to our Annual Report furnishes the XBRL presentation not filed with the previous Form 10K, filed on February 13, 2015. Corrections to a typographical error was made on page 31.

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TABLE OF CONTENTS

PART I

Item 1. Business	4
Item 1A. Risk Factors	13
Item 1B. Unresolved Staff Comments	13
Item 2. Properties	13
Item 3. Legal Proceedings	13
Item 4. Mine Safety Disclosures	13

PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities	13
Item 6. Selected Consolidated Financial Data	13
Item 7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations	14
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	17
Item 8. Financial Statements and Supplementary Data	17
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures	17
Item 9A. Controls and Procedures	17
Item 9B. Other Information	18

PART III

Item 10. Directors, Executive Officers and Corporate Governance	19
Item 11. Executive Compensation	20
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters	21
Item 13. Certain Relationships and Related Transactions, and Director Independence	22
Item 14. Principal Accounting Fees and Services	22
Item 15. Exhibits and Financial Statement Schedules	22

PART IV
Signatures	23

Glossary of Abbreviations and Terms	24

As used in this document, “the Company”, “Diversified”, “we”, “us” and “our” refer to Diversified Resources, Inc. and its consolidated subsidiaries.

Abbreviations or definitions of certain terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Abbreviations and Terms”.

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PART I

Cautionary Statement Concerning Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as “believes”, “expects”, “anticipates”, “intends”, “plans”, “estimates”, “should”, “likely” or similar expressions, indicates a forward-looking statement.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:

	●	The success of our exploration and development efforts;

	●	The price of oil and gas;

	●	The worldwide economic situation;

	●	Any change in interest rates or inflation;

	●	The willingness and ability of third parties to honor their contractual commitments;

	●	Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital;

	●	Our capital costs, as they may be affected by delays or cost overruns;

	●	Our costs of production;

	●	Environmental and other regulations, as the same presently exist or may later be amended;

	●	Our ability to identify, finance and integrate any future acquisitions; and

	●	The volatility of our stock price.

ITEM 1. BUSINESS

Overview

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. According to the lease, the additional mining claims were subject to the lease and we agreed to pay the lessor annual royalty payments. We did not pay royalties of $10,000 and $25,000 which were due in 2012 and 2013 and we terminated the lease in November 2013.

On November 21, 2013 we acquired all of the outstanding shares of Natural Resource Group, Inc. (“NRG”) in exchange for 14,558,150 shares of our common stock.

In connection with the acquisition:

	●	Paul Laird, Duane Bacon, Roger May, and Albert McMullin were appointed as our officers and/or directors;
	●	Philip F. Grey resigned as our officer;
	●	Mr. Grey sold 2,680,033 shares of our common stock to us for nominal consideration. The shares purchased from Mr. Grey were returned to the status of authorized but unissued shares; and
	●	NRG became our wholly owned subsidiary.

Unless otherwise indicated, all references to us include the operations of NRG.

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Overview of Natural Resource Group

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 October 31, 2014, 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;

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.

Garcia Field

As a result of our acquisition of NRG, we have a 100% working interest (80% net revenue interest) in oil and gas leases covering 4,600 acres in the Garcia Field.

The Garcia Field is located in Las Animas County approximately 10 miles from Trinidad, Colorado. The Garcia Field was first discovered in 1940 when the Maldonado #1, produced 500 mcf per day of gas from the Niobrara formation. A stripping plant separated natural gas liquids from the gas and was operational for eight years until the Maldonado #1 was plugged in 1948. Between 1978 and 1982 twenty wells were drilled, tested for initial production and shut-in. Since there was no natural gas transportation line in the area, the wells were never produced. Additionally, until Energy Oil and Gas acquired the field in 2005 no natural gas liquids were produced commercially. In 2003, the entire field was force plugged as required by the state of Colorado, except for three wells which Energy Oil and Gas acquired from the state. Energy Oil and Gas subsequently drilled two additional wells and installed a new separation plant. Four of the five wells we acquired from Energy Oil and Gas are currently producing a combined total of 147 mcf of gas per day. Two gallons of 1500 BTU natural gas liquids can be separated from each mcf of gas. The natural gas liquids are sold to a third party at a price, as of the date of this filing, of $0.71 per gallon.

The fifth well is used to re-inject the gas back into the Apishapa and Niobrara formations. Currently, our wells are not connected to a gathering line which is needed to transport the gas to commercial markets. Kinder Morgan (KM) has a transportation line approximately eight miles north of the field. We believe there is enough capacity in KM’s transportation line to transport gas produced from our wells. In addition, the city of Raton, NM, is in need of gas and has a pipeline approximately 10 miles south of the field that connects to the city of Raton. However, to connect our wells to either of the lines, we will need to install a gathering system at an estimated cost of $1,000,000, which includes a tap fee.

We installed new equipment at our refrigeration/compression plant, which increased the yield of natural gas liquids to 3.5 gallons per mcf.

The gas from our wells has a BTU content of approximately 1,500. It is our belief that there is a productive oil formation in the Garcia Field since, from data acquired throughout the United States, it is apparent that no 1500 BTU gas has ever been produced in an area not associated with oil production.

Denver/Julesburg Basin

As a result of our acquisition of NRG, we have a 100% working interest (80% net revenue interest) in oil and gas leases covering 920 acres in the Denver/Julesburg (“D-J”) Basin and the working interest and net revenue interests in the wells shown below:

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	Working			Net Revenue
Well Name	Interest			Interest
Shannon Roberts 1		75	%		58.50	%
Shannon Roberts 2-3-4		100	%		78.00	%
Lewton F Unit		100	%		84.00	%
UPPR Nichols		100	%		85.00	%

The reservoir rocks in the D-J Basin are Cretaceous sandstones, shales, and limestones deposited under marine conditions in the Western Interior Seaway. The oil and gas is contained within Cretaceous formations in the deepest part of the Basin, where the rocks were subject to enough heat and pressure to generate oil and gas from organic material in the rock. Most of the producing formations are considered “tight,” having low natural permeability.

The D-J Basin was one of the first oil and gas fields where extensive hydraulic fracturing was performed routinely and successfully on thousands of wells.

In 2009, the US Energy Information Administration listed the Wattenberg Field (a primary field within the D-J Basin) as the 10th largest gas field in the United States in terms of remaining proved gas reserves, and 13th in remaining proved oil/condensate reserves.

Major operators in the field include Noble Energy, Anadarko Petroleum Corporation, Continental, Whiting Petroleum, and Encana.

As of January 31, 2015, the three producing wells acquired by NRG from Energy Oil and Gas were collectively producing approximately two bbls of oil and 9.4 mcf of gas per day.

We plan to hydraulically fracture our wells in the D-J Basin at a cost of approximately $50,000 per well, once the moratorium on hydraulic fracturing is lifted by the city of Broomfield, CO. Hydraulic fracturing involves the process of pumping a mixture into a formation to create pores and fractures, thereby improving the porosity of the formation and increasing the flow of oil and gas. The mixture consists primarily of water and sand, with nominal amounts of other ingredients. This mixture is injected into wells at pressures of 4,500-6,000 pounds per square inch.

In 2013 we acquired a 640 acre lease (100% working interest, 80% net revenue interest) in the D-J Basin.

During the twelve months ending December 31, 2015, we plan to:

	●	recomplete the three shut-in wells we acquired from Energy Oil and Gas, at a cost of approximately $50,000 per well;

	●	Drill one vertical well for the cost of approximately $750,000

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’s 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, commenced on April 15, 2008. Under the agreement, BIYA is to drill 3 wells by April, 2016, 2 additional wells by April 2017 and April 2018, each. After April 2018, BIYA is required to drill 1 well per year. Per agreement, if BIYA drills and completes a well, and establishes production from that well, it will own a lease of 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 royalty between 12.5% and 20%.

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During the twelve months ending December 31, 2015, we plan to:

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

	●	drill 2 new well at a cost of approximately $255,000 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 us 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.

Production, Drilling Activity and Oil and Gas Leases

The following table shows our net production of oil and gas, average sales prices and average production costs for the periods indicated:

	Years Ended October 31,
	2014		2013		2012

Production:
Oil (Bbls)		1,827.28		276		417
Gas (Mcf)		3,134		4,500		5,015
Natural Gas Liquids (gallons)		53,360		37,230		20,375

Average sales price:
Oil ($/Bbl1)	$	83.90	$	127,83	$	92.94
Gas ($/Mcf2)	$	4.79	$	9.68	$	3.04
Natural Gas Liquids ($/gal)	$	0.99	$	0.87	$	0.77

Average production
cost per BOE3	$	93.01	$	73.17	$	58.85

1	“Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2	“Mcf” refers to one thousand cubic feet of natural gas.
3	“BOE” refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil. One barrel of natural gas liquids is assumed to equal 0.61 barrel of oil.

Production costs generally include pumping fees, maintenance, repairs, labor, utilities and administrative overhead. Taxes on production, including ad valorem and severance taxes, are not included in production costs.

We are not obligated to provide a fixed and determined quantity of oil or gas to any third party in the future. During the last three fiscal years, we have not had, nor does it now have, any long-term supply or similar agreement with any government or governmental authority.

The following shows our drilling activity for the three years ended October 31, 2014.

	October 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net

Development Wells:
Productive		--		--		1		0.75		1		1
Nonproductive		--		--		--		--		--		--

Productive Wells:
Productive		--		--		--		--		--		--
Nonproductive		--		--		--		--		--		--

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As of January 31, 2015, we were in the process of permitting three well locations in our Garcia Field. The new wells will be drilled to a depth of approximately 2,000 feet for the shallow natural gas liquid wells and up to 5,500 feet for deep wells which will be drilled to determine if commercial reserves of oil exist. Each well will take approximately 7-14 days to drill and complete. The drilling and completion costs for each well is estimated to be $100,000 for the shallow wells and up to $450,000 for the deep wells.

As of January 31, 2015 we were not drilling, we were reworking two oil wells in the Horseshoe Gallup Field for a cost approximately $7,000 per well.

The following table shows, as of January 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.

The following table shows, as of January 31, 2015, the status of our gross acreage:

Location	Held by Production		Not Held by Production

New Mexico
Horseshoe Gallup Field	10,072		--
Colorado:
Garcia Field		4,600		--
D-J Basin		280		640

Acres that are Held by Production remain in force so long as oil or gas is produced from one or more wells on the particular lease. Leased acres that are not Held by Production require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage. At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be Held by Production.

The following table shows the years our leases, which are not Held By Production, will expire, unless a productive oil or gas well is drilled on the lease.

Leased Acres		Expiration of Lease

	640	7/22/2015

Oil and Natural Gas Reserves

In accordance with current SEC rules, the average prices used in computing reserves at October 31, 2014 were $83.96 per bbl of oil, $4.37 per mcf of natural gas and $0.81 per gallon of NGL. These prices are based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each month during fiscal 2014. The benchmark price of $83.96 per bbl of oil at October 31, 2014 versus $86.79 at October 31, 2013, was adjusted by lease for gravity, transportation fees and regional price differentials. The benchmark price of $4.37 per mcf of natural gas at October 31, 2014 versus $4.87 at October 31, 2013, was adjusted by lease for BTU content, transportation fees and regional price differentials. The benchmark price of $0.99 per gallon of NGL at October 31, 2014 versus $0.81 at October 31, 2013, was adjusted by lease for transportation fees and regional price differentials.

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For information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes 13 and 14 to our consolidated financial statements.

The engineering reports with respect to our estimates of proved oil and gas reserves as of October 31, 2014 are based on evaluations prepared by MHA Petroleum Consultants (“MHA”)and McCartney Engineering, LLC (“McCartney”), based in Denver, Colorado and are filed as Exhibit 99.1 and Exhibit 99.2, respectively, to this annual report. Mr. John Seidle, vice president MHA, is responsible for overseeing the preparation of the Horseshoe Gallup field reserve estimates and has a doctorate in mechanical engineering, is a member of the Society of Petroleum Engineers and has over 30 years of experience in the oil and gas industry. Mr. Jack McCartney, manager, is responsible for overseeing the preparation of the Garcia reserve estimates, he is a petroleum engineer, and is a member of the Society of Petroleum Engineers and has over 40 years of experience in the oil and gas industry.

Jubal Terry, our Vice President - Exploration is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Geology and over 35 years of industry experience with positions of increasing responsibility in operations, acquisitions, geology and evaluations. He has worked in the area of geology, exploration and development most of his career and is a member of the Rocky Mountain Association of Geologists. He prepared the reserve report for our Garcia field, the results of which are included in the unaudited standardized measure disclosure note 14 and 15. The Vice President—Exploration reports directly to our President. The reserve estimates are reviewed and approved by the President and certain other members of senior management.

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC. As stated above, we retained MHA and McCartney to prepare estimates of our oil and gas reserves. Management works closely with these firm, and is responsible for providing accurate operating and technical data for purpose of computing our reserves. Our Chief Executive Officer, Chief Financial Officer and Vice President - Exploration with a combined experience of over 70 years in the oil and gas industry, reviews the final reserves estimate and consults with Mr. Seidle and Mr. McCartney.

Numerous uncertainties exist in estimating quantities of proved reserves. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources.

Per the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are made using the 12-month unweighted arithmetic average of the first-day-of the- month price. All prices are held constant throughout the life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.

We have not filed any oil or gas reserve estimates or included any such estimates in reports to any other federal or foreign governmental authority or agency during the year ended October 31, 2014, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Our estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the years ended October 31, 2013 and 2014 are summarized below:

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PROVED RESERVES

	October 31,
	2014		2013

Oil (Bbls):
Proved developed – Producing		299,856		5,379
Proved undeveloped		1,432,256		24,077
Total		1,732,112		29,456

Natural gas (Mcf):
Proved developed – Producing		51,298		68,406
Proved undeveloped		1,257,190		620,828
Total		1,308,488		689,234

NG Liquids (Gallons)
Proved developed – Producing
Proved undeveloped		6,890,814		4,678,103
Total		6,890,814		4,678,103

Future net cash flow (1)	$	62,891,348	$	1,300,676
Future net cash flows discounted at 10%		(31,944,372)		(990,662	)
Standardized measure of discounted future net cash flows (PV – 10 value) (2)	$	30,946,976	$	310,014

Prices used in calculating reserves: (3)
Oil (per Bbl)	$	83.96	$	86.79
Natural gas (per Mcf)	$	4.37	$	4.87
NGL (per Gallon)	$	0.99	$	0.81

(1)	In accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions.
(2)	The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. Our reconciliation of this non- GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.
(3)	These prices reflect adjustment by lease for quality, transportation fees and regional price differentials.

Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company's proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) pronouncements, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, may be materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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Future Operations

We plan to evaluate other undeveloped oil prospects and participate in drilling activities on those prospects which, in management’s opinion, are favorable for the production of oil, gas and natural gas liquids. Initially, we plan to concentrate our activities in the Garcia and Wattenberg fields in Colorado and San Juan basin New Mexico. Our strategy is to acquire prospects in or adjacent to existing fields with further development potential and minimal risk in the same area.

If we believe a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area. We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners. One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil reserves, additional wells may be drilled on the prospect.

We may also:

	●	acquire a working interest in one or more prospects from others and participate with the other working interest owners in drilling and if warranted, completing oil wells on a prospect;
	●	purchase producing oil properties;
	●	enter into farm-in agreements with third parties. A farm-in agreement will obligate us to pay the cost of drilling, and if warranted completing a well, in return for a majority of the working and net revenue interest in the well; or
	●	enter into joint ventures with third party holders of mineral rights.

Our activities will primarily be dependent upon available financing.

Title to properties which may be acquired will be subject to one or more of the following: royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil industry; liens for current taxes not yet due; and other encumbrances. In the case of undeveloped properties, investigation of record title will be made at the time of acquisition. Title reviews will be obtained before commencement of drilling operations.

Although we normally obtain title reports for oil leases we acquires, we have not in the past, and may not in the future, obtain title opinions pertaining to leases. A title report shows the history of a particular oil and gas lease, as shown by the records of the county clerk and recorder, state oil or gas commission, or the Bureau of Land Management, depending on the nature of the lease. In contrast, in a title opinion, an attorney expresses an opinion as to the persons or persons owning interests in a particular oil and gas lease.

Government Regulation

Although the sale of oil is not be regulated, federal, state and local agencies have promulgated extensive rules and regulations applicable to oil exploration, production and related operations. Most states, including Colorado and New Mexico, require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil. These states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil properties, the establishment of maximum rates of production from oil wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of these and other states limit the rate at which oil is produced from wells. The federal and state regulatory burden on the oil industry increases costs of doing business and affects profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.

As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic work, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of properties on which oil and gas activities have taken place.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (‘‘CERCLA’’) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of ‘‘hazardous substances’’ found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury

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and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (‘‘RCRA’’) and comparable state statutes govern the disposal of ‘‘solid waste’’ and ‘‘hazardous waste’’ and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of ‘‘hazardous substance,’’ state laws affecting operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as ‘‘non-hazardous,’’ such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

Competition and Marketing

We are faced with strong competition from many other companies and individuals engaged in the energy business, some of which are very large, well-established energy companies with substantial capabilities and established earnings records. We may be at a competitive disadvantage in acquiring prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs.

Exploration for, and the production of, oil, gas and natural gas liquids are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools. We depend upon independent drilling contractors to furnish rigs, equipment and tools to drill wells. Higher prices for products may result in competition among operators for drilling equipment, tubular goods and drilling crews which may affect our ability expeditiously to drill, complete, recomplete and work-over wells.

The market for oil, gas and natural gas liquids is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted. These factors include the extent of competitive domestic production and imports of oil, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation. In addition, there is always the possibility that new legislation may be enacted which would impose price controls or additional excise taxes upon crude oil. As of October 31, 2014, our oil production was being sold to Suncor and Pacer Energy Marketing. Natural gas sales were made to Kerr McGee and our natural gas liquids were being sold to NGL Supply Co.

The market price for crude oil is significantly affected by policies adopted by the member nations of Organization of Petroleum Exporting Countries (‘‘OPEC’’). Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels. We are unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil.

The market price for natural gas and natural gas liquids can be affected by supply and demand characteristics on a local basis. Customarily there are transportation fees, tap fees and price adjustments paid to pipeline and liquids buying companies. We are unable to predict the future prices we will receive for our production of natural gas, natural gas liquids and its components.

Employees and Offices

As of January 31, 2015, we had five full-time employees and no part-time employees.

Our principal offices are located at 1789 W Littleton Blvd., Littleton, CO 80120. Our offices, consisting of approximately 2200 square feet, are leased on a month-to-month basis at a rate of $2,667 per month. Our Chief Executive Officer, Paul Laird, is a partner in the entity that owns the building.

We are a licensed oil and gas operator in Colorado. We are the operator of our wells in the Garcia Field, the Denver-Julesburg Basin and the Horseshoe Gallup Field.

Access to Company Reports

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). Please call the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers, including Diversified, file electronically with the SEC.

We also maintain an internet website at www.diversifiedresourcesinc.com. In the Investor Relations section, our website contains our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge to any stockholder who requests them. Requests should be directed to investor relations by mail to 1789 W Littleton Blvd, Littleton, CO 80120.

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ITEM 1A. RISK FACTORS

Not applicable.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

See Item 1 of this report.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Since November 2012, our common stock has been quoted on the OTCQB tier of the OTC Markets Group under the symbol “DDRI”. However, our common stock did not begin to trade until July 2013. The following shows the reported high and low prices for our common stock, based on information provided by the OTCQB, for the periods indicated. The over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

Quarter Ended	High		Low
July 31, 2013	$	1.00	$	1.00
October 31, 2013	$	1.20	$	0.70
January 31, 2014	$	1.30	$	0.70
April 30, 2014	$	2.25	$	0.80
July 31, 2014	$	1.50	$	1.10
October 31, 2014	$	2.25	$	0.70

Holders of our common stock are entitled to receive dividends as may be declared by the Board of Directors. Our Board of Directors is not restricted from paying any dividends but is not obligated to declare a dividend. No cash dividends have ever been declared and it is not anticipated that cash dividends will ever be paid. We currently intend to retain any future earnings to finance future growth. Any future determination to pay dividends will be at the discretion of the board of directors and will depend on our financial condition, results of operations, capital requirements and other factors the board of directors considers relevant.

Our Articles of Incorporation authorize our Board of Directors to issue up to 50,000,000 shares of preferred stock. The provisions in the Articles of Incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights which would have priority over any dividends paid with respect to the holders of common stock. The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by management. In addition, our Articles of Incorporation authorize our Board of Directors to issue up to 450,000,000 shares of common stock.

As of January 31, 2015 we had approximately 206 shareholders of record and 23,165,926 outstanding shares of common stock.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.

Results of Operations

We were incorporated in Colorado in 2000, but we were relatively inactive until December 2010.

On November 21, 2013 we acquired 100% of the outstanding shares of Natural Resources Group, Inc. (“NRG”) in exchange for 14,558,150 shares of our common stock.

Although from a legal standpoint, we acquired NRG on November 21, 2013, for financial reporting purposes our acquisition of NRG constituted a recapitalization, and the acquisition was accounted for similar to a reverse merger, whereby NRG was deemed to have acquired us.

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.

Year ended October 31, 2014 compared to the year ended October 31 2013.

For the year ended October 31, 2014 we reported a net income of $726,120 or $ 0.04 per share compared with a net loss of $ 1,170,403 or $ (0.09) per share for the year ended October 31, 2013. The increase of $1,896,523 or 162% principally arises from bargain purchase gain of $2,584,184 on the purchase of BIYA, partially offset by an increase in general and administrative expenses due to having more employees and contractors for the full year period and higher cost consistent with being a public company.

Operating revenues were $161,623 for the year ended October 31, 2014 compared with $96,155 for the year ended October 31, 2013. Operating revenues increased $65,468 or 68%, primarily due to the purchase of BIYA and production for the month of October 2014, the increase in production was partially offset by the decrease in crude prices.

Exploration cost was $41,802 for the year ended October 31, 2014 compared with $69,878 for the year ended October 31, 2013, a decrease of $28,076 or 40% and is a result of a decrease in exploration related activities.

Lease operating expenses were $290,588 for the year ended October 31, 2014 compared with $189,212 for the year ended October 31, 2013. Lease operating expenses increased $101,376 or 54% for the year ended October 31, 2014 compared to the year ended October 31, 2013. The increase related to full year of compression expenses at the Garcia Field in the amount of $18,135, an increase of $33,000 in consulting services related to operating the field and $33,321 in expenses related to BIYA which was purchased in October 2014. The fluctuations are considered normal and in the ordinary course of business.

General and administrative expenses were $1,510,367 for the year ended October 31, 2014 compared with $494,845 for the year ended October 31, 2013, an increase of $1,015,522 or 205%. Consulting fee increased by $175,764, due to increase in equity investment activities, legal and accounting expenses increased by $234,475 due to full year of expense and cost related to being a public company, investor relations expense increased by $90,919 due to full year of expense and cost related to being a public company, payroll expense increased due to full year of expense and increase in employee count and insurance expense increased by $58,864 due to full year of expense and increase in employee count.

Depreciation expense was $27,895 for the year ended October 31, 2014 compared with $7,641 for the year ended October 31, 2013, an increase of $20,254 or 265% and is a result of increased equipment in 2014 compared to 2013 and full of depreciation on the assets added during 2013 and assets acquired through purchase of BIYA.

Depletion expense was $34,475 for the year ended October 31, 2014 compared with $13,800 for the year ended October 31, 2013, an increase of $20,675 or 149% and is primarily related to production from BIYA purchase.

The Company incurred losses on the extinguishment of debt in the amount of $330,638 for the year ended October 31, 2013 compared with $0 for the year ended October 31, 2014. The decrease arose because the Company settled certain obligations using its Common Stock in 2013 and such settlements were not present in 2014.

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The Company incurred losses on the sale of equipment in the amount of $13,158 for the year ended October 31, 2013 compared with $0 for the year ended October 31, 2014. The increase arose because the Company did not dispose of any assets in 2014.

Interest expense was $60,281 for the year ended October 31, 2014 compared with $126,586 for the year ended October 31, 2013, a decrease of $66,305 or 52%. The decrease is directly attributable to the decreased amount of loans outstanding during 2014 compared to 2013.

The Company recorded a bargain purchase gain, net of related taxes, of $2,584,184 on purchase of BIYA in October 2014. See note 11 for further details of the acquisition. No such gain was recorded in 2013.

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

	●	the sale prices of crude oil, natural gas and natural gas liquids;
	●	the ability to transport natural gas produced from our wells;

	●	the amount of production from wells which produce oil, gas and gas liquids in which the Company has an interest;
	●	lease operating expenses;
	●	the availability of drilling rigs, drill pipe and other supplies and equipment required to drill and complete oil wells; and
	●	corporate overhead costs.

Revenues will also be significantly affected by the Company’s 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.

Liquidity and Capital Resources

Our primary source of liquidity since inception has been net cash provided by sales and other issuances of equity and debt securities. Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties. Our future success in developing proved reserves and production will be highly dependent on capital resources available to us.

As shown in the accompanying financial statements, we have incurred significant operating losses since inception aggregating $(2,282,333) and have negative working capital of $958,829 at October 31, 2014. As of October 31, 2014, we had limited financial resources. These factors raise substantial doubt about our ability to continue as a going concern. Our ability to achieve and maintain profitability and positive cash flow is dependent upon its ability to locate profitable oil and gas properties, generate revenue from planned business operations, and control exploration cost. Management plans to fund its future operation by joint venturing, obtaining additional financing, and attaining additional commercial production. However, there is no assurance that we will be able to obtain additional financing from investors or private lenders, or that additional commercial production can be attained.

Our sources and (uses) of funds for the years ended October 31, 2014 and 2013 are summarized below:

	Years Ended
	October 31,			October 31,
	2014			2013
Net cash (used in) operating activities	$	(2,505,800	)	$	(599,311	)
Funds from sale of assets		-			65,583
Purchase of property and equipment		(148,590	)		(19,412	)
Purchases of oil and gas properties		(25,410	)		(240,965	)
Proceeds from the sale of common stock		2,929,646			816,760
Proceeds from notes payable		-			79,965
Payments on notes payable		(110,225	)		(1,508	)
Payments on related party notes payable		-			(32,730	)
Net increase (decrease) in cash	$	139,621		$	68,382

As of January 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, and
	●	lease operating and interest expenses.

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We estimate our capital requirements for the twelve months ending December 31, 2015 are as follows:

●	Drilling, completing, and fracturing wells	$	1,810,000

●	Seismic work	$	120,000

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. The Company’s capital expenditure plans are subject to periodic revision based upon the availability of funds and expected return on investment.

It is expected that the Company’s 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 the Company to finance operations to a greater extent with internally generated funds, may allow the Company 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 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 the Company to allow 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.

The Company plans to generate profits by acquiring, drilling and/or completing productive wells. However, the Company plans 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 the Company’s share of the cost of drilling and completing the wells as partners/participants in the resulting wells. The Company does not have any commitments or arrangements from any person to provide it with any additional capital. The Company may not be successful in raising the capital needed to drill oil wells. Any wells which may be drilled may not produce oil.

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.

Contractual Obligations

Our material future contractual obligations as of October 31, 2014 were as follows:

Total		10/31/15		10/31/2016		10/31/2017		Thereafter

$	2,786,660	$	373,846	$	2,212,295	$	200,519	$	-

Our material future contractual obligations as of October 31, 2013 were as follows:

Total		10/31/14		10/31/2015		10/31/2016		Thereafter

$	444,422	$	323,588	$	111,762	$	4,692	$	4,380

Alternative Capital Resources

Although we have primarily used cash from operating activities and funding from the convertible promissory note and equity raise as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and the sale of assets and/or issuances of common stock through a private placement or public offering of our common stock.

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Critical Accounting Policies

See Notes 1 to the financial statements included as part of this report for a description of our critical accounting policies and a discussion of our ability to continue as a going concern.

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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Risk.

At October 31, 2014, we had not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other similar agreements relating to crude oil and natural gas.

Credit Risk.

Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At October 31, 2014, our largest credit risk associated with any single purchaser was $130,495. We have not experienced any significant credit losses.

Energy Price Risk.

Our most significant market risk is the pricing for natural gas and crude oil. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing countries. Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required if prices declined significantly, even if it is only for a short period of time.

Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Our financial results are more sensitive to movements in oil prices because most of our production and reserves are oil.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the financial statements and accompanying notes included with this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Please see our 8-K reports filed on May 21, 2013, November 22, 2013 and January 29, 2015.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive and 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-K. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in reports filed under the Securities Exchange Act of 1934, such as this Form 10-K, 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 and Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, management concluded that, as of October 31, 2014, our disclosure controls and procedures were not effective, for the same reasons our internal control over financial reporting was not effective.

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Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the Securities and Exchange Commission, internal control over financial reporting is a process designed by, or under the supervision of our Principal Executive and Financial Officer and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our Principal Executive and the Financial Officer evaluated the effectiveness of our internal control over financial reporting as of October 31, 2014 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.

Based on this evaluation, management concluded that our internal control over financial reporting may have significant deficiencies in internal control. Prior to the acquisition of NRG, the former President was the sole corporate officer and director and there were no other employees. In connection with the preparation of our financial statements for the year ended October 31, 2014 certain significant deficiencies in internal control became evident to management that represent material weaknesses, including:

We do not have an audit committee;

We did not have the proper segregation of duties with respect our finance and accounting functions due to limited personnel. During the year ended October 31, 2014 we had independent contractors that performed nearly all aspects of our financial reporting process, including but not limited to, preparation of underlying account records and systems, the ability to posting and recording 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 would likely 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

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

As a result of the aforementioned deficiencies, our Principal Executive and Financial Officer concluded that the design and operation of our disclosure controls and procedures was not effective and that our internal control over financial reporting was not effective.

We intent 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 was no change in our internal control over financial reporting that occurred during the year ended October 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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.

Name	Age	Position

Paul Laird	58	Chief Executive Officer, Principal Financial and Accounting Officer and a Director
Duane Bacon	77	Chief Operating Officer and a Director
Roger May	58	Director
Albert McMullin	57	Director

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.

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. He 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.

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

Name		Reason

Paul Laird		Oil and gas exploration and development experience
Duane Bacon		Oil and gas exploration and development experience
Roger May		Investment banking experience
Albert McMullin		Oil and gas exploration and development experience

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.

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ITEM 11. EXECUTIVE COMPENSATION

The following table summarizes the compensation received by our principal executive and financial officers during the two years ended October 31, 2014.

						Restricted				Other
						Stock		Option		Annual
Name and	Fiscal	Salary		Bonus		Awards		Awards		Compensation
Principal Position	Year		(1)		(2)		(3)		(4)		(5)	Total
		$								$		$
Paul Laird	2014		150,000		--		--		--		445		150,445
Chief Executive Officer	2013		150,000		--		--		--		791		150,791

Duane Bacon	2014		66,000		--		--		--		445		66,445
Chief Operating Officer	2013		66,000		--		--		--		791		66,791

(1)	The dollar value of base salary (cash and non-cash) earned. Amounts reflect payments made by NRG for the periods shown.

(2)	The dollar value of bonus (cash and non-cash) earned.

(3)	The value of the shares of restricted stock issued as compensation for services computed in accordance with ASC 718 on the date of grant.

(4)	The value of all stock options computed in accordance with ASC 718 on the date of grant.

(5)	All other compensation received that could not be properly reported in any other column of the table.

The following shows the amounts we expect to pay to our officers and directors during the twelve months ending December 31, 2015 and the amount of time these persons expect to devote to us.

			Percent of Time
	Projected		to be Devoted to the
Name	Compensation		Company’s Business

Paul Laird	$	150,000		100	%
Duane Bacon	$	66,000		100	%

We have an employment agreement with Paul Laird. Pursuant to the agreement, we will pay Mr. Laird $12,500 per month. The employment agreement with Mr. Laird can be terminated at any time by either party without cause.

We have an employment agreement with Duane Bacon. Pursuant to the agreement, we will pay Mr. Bacon $5,500 per month. The agreement with Mr. Bacon is terminable at any time without cause.

Stock Option and Stock Bonus Plans. We do not have any stock option plans, although we may adopt one or more of such plans in the future.

Long-Term Incentive Plans. We do not provide our officers or employees with pension, stock appreciation rights or long-term incentive plans.

Employee Pension, Profit Sharing or other Retirement Plans. We do not have a defined benefit, pension plan, profit sharing or other retirement plan, although we may adopt one or more of such plans in the future.

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Other Arrangements. In 2011 we granted Paul Laird and Duane Bacon each a 1% overriding royalty on NRG's leases in the Garcia Field. In the discretion of our directors, we may in the future grant overriding royalty interests to other persons.

Compensation of Directors During Year Ended October 31, 2014. During the year ended October 31, 2014, we did not compensate our directors for acting as such.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table shows the beneficial ownership of our common stock as of January 31, 2015 by (i) each person whom we know beneficially owns more than 5% of the outstanding shares of its 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

Paul Laird		3,135,642			13.5	%
1789 W. Littleton Blvd
Littleton, CO 80120

Duane Bacon		979,508	(1)		4.23	%
5982 Heather Way
Longmont, CO 80503

Roger May		412,174			1.8	%
2780 Indiana Street
Golden, CO 80401

Albert McMullin		106,793	(2)		.5	%
4501 Merrie Lane
Belaire, TX 77401

All officers and directors
as a group (four persons).		4,634,117			20.03	%

(1)	Shares are held in the names of Duane and Ruth Bacon.
(2)	Shares are held in the name of partnerships controlled by Mr. McMullin.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

In December 2010 NRG acquired oil and gas properties from Energy Oil and Gas, Inc. for 2,500,000 shares of NRG’s common stock and a promissory note in the principal amount of $360,000. Duane Bacon, one of our officers and directors of, controls Energy Oil and Gas, Inc. The balance due on the note is $107,000 at October 31, 2014.

In connection with our acquisition of NRG, the following officers and directors received shares of our common stock in the amounts shown below.

Name	Number of Shares

Paul Laird		3,135,642
Duane Bacon		979,508
Roger May		412,174	(1)
Albert McMullin		106,793

(1)	Mr. May received 128,498 shares of our common stock for his services in arranging our acquisition of NRG.

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See Item 11 of this report for information concerning overriding royalty interests we granted to Paul Laird and Duane Bacon.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Kingery & Crouse, P.A. served as our independent registered public accountant for the years ended October 31, 2013 and subsequent reviews through the quarter ending July 31, 2014.

The following table shows the aggregate fees billed by Kingery & Crouse to us for the period shown.

	2014		2013

Audit Fees	$	66,000	$	24,000
Audit-Related Fees		--		--
Tax Fees		--		--
All Other Fees	$	2,950		3,640

Accounting fee paid in 2013 included payments to Anton & Chia, LLP, who served as our independent registered public accountant for the year ended October 31, 2012.

Audit fees represent amounts invoiced for professional services rendered for the audit of our annual financial statements and the reviews of the financial statements included in our 10-Q reports. Prior to contracting with Kingery & Crouse to render audit or non-audit services, each engagement was approved by our directors.

In January 2015, as a result of the acquisition of substantially all of the assets and business of our previous registered independent public accounting firm, Kingery & Crouse PA, by Frazier & Deeter, LLC, we dismissed Kingery & Crouse as our registered independent public accounting firm and engaged Frazier & Deeter for October 31, 2014 year end audit.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibit Number		Exhibit Name
3.1		Articles of Incorporation (1)
3.2		Bylaws (1)
10.1		Participation Agreement/Net Profits Interest (2)
10.2		Note Payable – Energy Oil and Gas, Inc. (2)
31		Rule 13a-14(a) Certifications
32		Section 1350 Certifications
99.1		Report of MHA Petroleum Consultants, Independent Petroleum Engineer
99.2		Report of McCartney Engineering, LLC, Independent Petroleum Engineer

(1)	Incorporated by reference to the same exhibit filed with the Company’s registration statement on Form S-1 (File No. 333-175183).
(2)	Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K (filed on November 22, 2013).

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Exchange Act, the Registrant has caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 20th day of February 2014.

	DIVERSIFIED RESOURCES, INC.


	By:	/s/ Paul Laird
		Paul Laird, President

Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date


/s/ Paul Laird	President, Principal Financial Officer, Principal Accounting Officer and a Director	February 20 , 2015
Paul Laird


/s/ Duane Bacon	Director	February 20 , 2015
Duane Bacon


/s/ Roger May	Director	February 20 , 2015
Roger May


/s/ Albert McMullin	Director	February 20 , 2015
Albert McMullin

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Glossary of Abbreviations and Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons.

Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.

BTU. British thermal unit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploitation. The continuing development of a known producing formation in a previously discovered field. To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.

Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or wells. Refers to the total acres or wells in which the Company owns any amount of working interest.

Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf for each Bbl of oil.

MMBtu. One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.

Natural gas liquids ("NGLs"). Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.

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Net production. Oil and gas production that is owned by the Company, less royalties and production due others.

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

Oil. Crude oil or condensate.

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

Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.

Pay zone. A geological deposit in which oil and natural gas is found in commercial quantities.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed nonproducing reserves ("PDNP"). Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves ("PDP"). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.

Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves ("PUD"). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

PV-10. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.

Recompletion. A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Re-entry. Entering an existing well bore to redrill or repair.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Shut in. A well suspended from production or injection but not abandoned.

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Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.

Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K.

Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Wellbore. The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well.

Also called well or borehole.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms	28

Consolidated Balance Sheets	30

Consolidated Statements of Operations	31

Consolidated Statements of Changes in Stockholders’ Equity	32

Consolidated Statements of Cash Flows	33

Notes to Consolidated Financial Statements	34

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

Diversified Resources, Inc.

We have audited the accompanying balance sheet of Diversified Resources, Inc. (the “Company”) as of October 31, 2014, and the related statements of operations, changes in stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of October 31, 2014, and the results of its operations and cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has an accumulated deficit and has incurred significant operating losses and has a working capital deficit. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to this matter are also discussed in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Frazier & Deeter, LLC

Frazier & Deeter, LLC

Tampa, Florida

February 13, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

Diversified Resources, Inc.

We have audited the accompanying balance sheet of Diversified Resources, Inc. (the “Company”) as of October 31, 2013, and the related statement of operations, changes in stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company. as of October 31, 2013, and the results of its operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Kingery & Crouse PA

Kingery & Crouse PA

Certified Public Accountants

Tampa, Florida

May 15, 2014

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Diversified Resources, Inc.

CONSOLIDATED BALANCE SHEETS

	October 31,			October 31,
	2014			2013

ASSETS
CURRENT ASSETS
Cash	$	209,054		$	69,433
Accounts receivable, trade		130,495			32,378
Prepaid expenses		7,948			8,870
Total current assets		347,497			110,681

LONG-LIVED ASSETS
Property and Equipment, net of accumulated depreciation
of $149,957 and $4,111 in 2014 and 2013 respectively		1,904,403			39,392
Bonds and deposits		167,867				-
Oil and gas properties - proved (successful efforts method)
net of accumulated depletion of $100,062 and $56,726 in 2014 and 2013 respectively		3,806,153			2,604,418
Oil and gas properties - proved undeveloped (successful efforts method)		1,209,724			64,126
Oil and gas properties - unproved (successful efforts method)		2,932,730			-

Total assets	$	10,368,374		$	2,818,617

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable	$	221,880		$	185,251
Accounts payable, related party		145,473			130,361
Current portion of instalment loan		373,846			304,071
Accrued interest, related party		4,579			3,872
Accrued expenses		560,548			111,604
Total current liabilities		1,306,326			735,159

LONG TERM LIABILITIES
Long term debt, related party		107,070			107,070
Long term debt, installment loan		2,294,943			13,765
Asset retirement obligation		290,312			222,375

COMMITMENTS AND CONTINGENT LIABILITIES		-			-

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,
22,502,206 and 14,558,150 shares issued and outstanding in 2014 and 2013 respectively		22,502			14,563
Additional paid in capital		8,629,554			4,734,138
Accumulated deficit		(2,282,333	)		(3,008,453	)
Total stockholders' equity		6,369,723			1,740,248

Total liabilities and stockholders' equity	$	10,368,374		$	2,818,617

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

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Diversified Resources Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended

	Years Ended
	October 31,			October 31,
	2014			2013

Operating revenues
Oil and gas sales	$	161,623		$	85,808
Consulting fees		-			10,347
		161,623			96,155

Operating expenses
Exploration costs, including dry holes		41,802			69,878
Lease operating expenses		290,588			189,212
General and administrative		1,510,367			494,845
Depreciation expense		27,895			7,641
Depletion expense		34,475			13,800
Production tax and royalty expense		30,225			-
Accretion expense		24,054			20,800
Total operating expenses		1,959,406			796,176

(Loss) from operations		(1,797,783	)		(700,021	)

Other income (expense)
Loss on debt extinguishment		-			(330,638	)
Loss on disposition of assets		-			(13,158	)
Bargain purchase gain		2,584,184			-
Interest expense		(60,281	)		(126,586	)
Other income (expense), net		2,523,903			(470,382	)

Net income (loss)	$	726,120		$	(1,170,403	)

Net (loss) per common share
Basic and diluted	$	0.04		$	(0.09	)

Weighted average shares outstanding
Basic and diluted		18,792,650			13,684,623

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

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Diversified Resources, Inc.
Consolidated Statement of Stockholders' Equity
Years Ended October 31, 2013 and 2014


	Preferred Stock						Common Stock						Additional
	$.001 Par Value						$.001 Par Value						Paid-in			Accumulated
	Shares			Amount			Shares			Amount			Capital			Deficit			Total

Balance October 31, 2012		208,820		$	49,992			13,093,703		$	13,094		$	3,472,978		$	(1,838,050	)	$	1,698,014

Conversion of preferred stock to common stock		(208,820	)		(49,992	)		208,820			209			49,783			-			-
Conversion of debt to common stock		-			-			395,877			396			395,481			-			395,877
Common stock issued for cash		-			-			859,750			859			815,901			-			816,760
Net (loss) for the year		-			-			-			-			-			(1,170,403	)		(1,170,403	)

Balance October 31, 2013		-			-			14,558,150			14,558			4,734,143			(3,008,453	)		1,740,248

Recapitalization with Natural Resources Group, Inc.		-			-			5,250,000			5,250			(302,980	)		-			(297,730	)
Contribution of shares in connection with the acquisition		-			-			(2,680,033	)		(2,680	)		2,680			-			-
Forgiveness of related party debt and assumption of liabilities by former shareholder		-			-			-			-			297,741			-			297,741
Common stock issued for cash		-			-			4,474,089			4,474			2,925,172			-			2,929,646
Acquisition of BIYA		-			-			900,000			900			972,798			-			973,698
Net income for period		-			-			-			-			-			726,120			726,120

Balance October 31, 2014		-			-			22,502,206		$	22,502		$	8,629,554		$	(2,282,333	)	$	6,369,723

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

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Diversified Resources, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended

	October 31,			October 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:

Net (loss)	$	726,120		$	(1,170,403	)
Adjustments to reconcile net (loss) to net cash
(used in) operating activities:
Bargain purchase gain		(2,584,184	)		-
Depreciation expense		27,895			7,641
Depletion expense		34,475			13,800
Accretion expense		24,054			20,800
Amortization of discount on notes payable		-			75,993
Loss on debt extinguishment		-			330,638
Loss on sale of assets		-			13,158
(Increase) decrease in:
Accounts receivable, trade		34,860			(18,097	)
Prepaid expense		11,924			(3,167	)
Bonds and deposits		21,042			-
Accounts payable		2,731			96,234
Accounts payable - related parties		15,112			38,066
Accrued expenses		(819,829	)		(3,974	)

Net cash (used in) operating activities		(2,505,800	)		(599,311	)

CASH FLOWS FROM INVESTING ACTIVITIES:

Proceeds from sale of assets		-			65,583
Cash paid for oil and gas properties		(25,410	)		(240,965	)
Cash paid for purchase of property and equipment		(148,590	)		(19,412	)

Net cash (used in) investing activities		(174,000	)		(194,794	)

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from sale of common stock		2,929,646			816,760
Payments on related party notes payable		-			(32,730	)
Proceeds from notes payable		-			79,965
Payments on notes payable		(110,225	)		(1,508	)

Net cash provided by financing activities		2,819,421			862,487

INCREASE IN CASH		139,621			68,382

BEGINNING BALANCE		69,433			1,051

ENDING BALANCE	$	209,054		$	69,433

Cash paid for interest	$	25,448		$	-
Cash Paid for Income Taxes	$	-		$	-

Non cash investing and financing activities:
Acquisition of BIYA:
Common stock issued	$	900,000		$	-
Note payable issued	$	1,860,000		$	-
Conversion of preferred stock to common stock	$	-		$	49,992
Conversion of debt to common stock	$	-		$	395,877
Acquisition of vehicle with note	$	-		$	19,965

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

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DIVERSIFIED RESOURCES INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Year Ending October 31, 2014, 2013 and 2012

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.

In November 2013, the Company entered into an agreement to exchange securities with Natural Resource Group, Inc. (“NRG”), an oil and gas exploration company, whereby the shareholders of NRG received 14,558,150 shares of the Company’s 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. The exchange was consummated on November 21, 2013. The transaction was accounted for as a reverse acquisition or recapitalization whereby NRG was considered the accounting acquirer and the Company, the acquire.

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 financial statements, the Company has incurred significant operating losses since inception and has an accumulated deficit of $2,282,333 and has negative working capital of $958,829 at October 31, 2014. As of October 31, 2014, 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 cost. 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 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

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company uses the direct write-off method for bad debts; this method expenses uncollectible accounts in the year they become uncollectible. Any difference between this method and the allowance method is not material. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the direct write-off method. The Company did not record any allowance for uncollectible receivables in 2014 or 2013.

Use of Estimates

The preparation of 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.

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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.

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, 2014 and 2013 was immaterial.

Consulting Fees

During the year ended October 31, 2013, the Company received consulting fees of $10,347. The Company provided Colorado land-man and geologic services to an independent entity. The income was recognized when the services were completed. All amounts have been collected. No such services were performed in 2014.

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.

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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.

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 project. Geological and geophysical costs were $41,802 and $69,878 for the years ended October 31, 2014 and 2013, 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 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.

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.

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The Company did not record any proved property impairment for the years ended October 31, 2014 and 2013.

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, 2014.

Major Customers

Sales to major unaffiliated customers consisted of the following, for the year ended October 31, 2014, Customer A accounted for approximately 54% of revenue, Customer B accounted for approximately 17%, Customer C accounted for approximately 13%, and Customer D accounted for approximately 11%.

Sales to major unaffiliated customers consisted of the following, for the year ended October 31, 2013, Customer A accounted for approximately 30% of revenue, Customer B accounted for approximately 37%, Customer C accounted for approximately 16%, and Customer D accounted for approximately 18%.

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.

Recent Accounting Pronouncements

There were no recently issued or proposed accounting pronouncements which management believes will have a material effect on the Company’s financial statements.

2. Oil and gas properties

Oil and gas properties consist of the following:

	October 31, 2014			October 31, 2013

Proved oil and gas properties	$	3,906,215		$	2,661,144
Proved undeveloped oil and gas leaseholds		1,209,724			64,126
		5,115,939			2,725,270
Less accumulated depletion		(100,062	)		(56,726	)
Net oil and gas properties		5,015,877			2,668,544
Undeveloped oil and gas leaseholds	$	2,932,730		$	-

Total depletion of oil and gas properties amounted to $34,475 and $13,800 for the years ended October 31, 2014 and 2013 respectively.

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3. 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, 2014, $248,895 was due on the note. In consideration for extending this credit arrangement, the lender was assigned a 1% overriding royalty interest in the 4,600 acre field and 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 said 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 (see note 5).

The modified net profits interest is based on the gross proceeds from the sale of oil, gas and other minerals in the 4 producing wells in the Garcia Field and 3 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 lifting oil or natural gas, or the operating or producing such 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.

4. Notes Payable - Affiliates

Notes Payable Affiliates—In 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 our 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). On July 30, 2013, the maturity date of the note was extended to December 11, 2015. The balance on the note is $107,070 at October 31, 2014 and 2013, with interest accrued in the amount of $4,579 and $3,872, respectively.

5. 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 July 17, 2015. The note is collateralized by a first priority deed of trust in 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 October 31, 2014 and 2013 was $248,895. The lender has the right to convert the principal to a working interest 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 3. In the event the principal is less than $350,000, the conversion percentage shall be reduced proportionately. The Company has the right to prepay the note without penalties or fees after giving the lender ten days’ notice of its intent. If lender does 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 $19,516 and $75,993 for the years ended October 31, 2014 and 2013 respectively. The ending balance of the debt discount at October 31, 2014 and 2013 was $0 and $19,513, respectively. The Company reviewed the conversion feature 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 $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 in the amount of $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, which amounted to approximately $7,000 at October 31, 2014, until paid in full. The balance due was $546,144 at October 31, 2014.

Convertible Promissory Note—On May 18, 2012 the Company entered into a $70,000 convertible promissory note bearing interest at 10%, the note was paid in full in June 2014.

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.

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The following summarizes the notes payable:

	2014			2013

Convertible promissory note	$	248,895		$	248,895
Debt Discount, net of amortization		-			(19,516	)
BIYA note		1,860,000			-
BIYA settlement		546,144			-
Convertible promissory note		-			70,000
Installment loan		13,750			18,457
		2,668,789			317,836
Current portion		(373,846	)		(304,071	)
	$	2,294,943		$	13,765

The above debt matures as follows:

	Year ended October 31

2015	$	373,846
2016	$	2,094,424
2017	$	200,519

6. Asset Retirement Obligation

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

	2014		2013

Beginning asset retirement obligation	$	222,375	$	203,889
Liabilities incurred		43,883		-
Liabilities settled		-		-
Accretion expense		24,054		20,800
Revision to estimated cash flows		-		(2,314
Ending asset retirement obligation	$	290,312	$	222,375

7. 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, 2014 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 reserve 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, 2014 and 2013 were:

	2014			2013

Deferred tax assets:
Net operating loss carry forwards	$	1,422,844		$	747,714
Deferred tax liability:		-			-
Property and equipment, geologic and geophysical		(41,945	)		(41,375	)
		1,380,899			706,339
Less valuation allowance		(1,380,899	)		(706,339	)
	$	-		$	-

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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, 2014, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $3.7 million, which will begin expiring in 2030.

Absent the bargain purchase gain, which is not recognized for income tax purposes, that was recognized at the time of acquisition (see Note 11), the Company would have a loss for both financial statement and tax reporting purposes. Accordingly, and because the Company has fully reserved its deferred income tax assets, no provision and/or benefit for income taxes has been recorded in the accompanying statement of operations.

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, 2014 and 2013:

Statutory U.S. federal rate	34	%
State income taxes	5	%
	39	%
Net operating loss	(39	%)
	-	%

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.

8. Stockholder’s Equity

Common Stock—The Company has 450,000,000 shares of $0.001 par value common stock authorized.

2013

The Company issued 395,877 shares of common stock in exchange for settling $65,239 of accounts and notes payable which were valued at their fair value of $395,877 during the year ended October 31, 2013. The difference between the fair value of the shares and the amount of the debt converted of $330,638 was charged to operations during 2013.

The Company issued 859,750 shares of common stock for cash of $816,760.

2014

The Company issued 4,474,089 shares of common stock for cash of $2,929,646.

The Company issued 900,000 shares of common stock with a fair value of $900,000 for the acquisition of BIYA.

Included in the shares issued, the Company issued 2,641,052 shares for $2,326,052 to various partners associated with Palo Petroleum, Inc. (“Palo”), 663,720 of these shares for $663,720 were issued in December 2014. On January 29, 2015, the Company entered into a participation agreement with Palo, where Palo acquired right to participate in all future operations in the Horseshoe Gallup Field which are not related to the Existing Wells or Existing Production, including the drilling of any future wells. Palo shall have 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. The Company does not have sufficient information to calculate the value of participation in the future working interest and the future participation cost will be charged to operations earned by Palo.

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

9. Commitments and Contingent Liabilities

Legal

We may be subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue 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. The Company is not a party to any material legal proceedings as of February 13, 2015.

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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 is unaware of any material environmental issues as of February 13, 2015.

Employment Agreements

The Company has a written employment agreement with its president. Pursuant to his employment agreement, said officer 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 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. Pursuant to the employment agreements, the president will receive a base salary of $150,000 per year. The president may be granted royalties pursuant to the royalty program.

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 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 pursuant to the royalty program.

The Company has no long term lease obligations.

10. Related Parties

The Company executed a 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 the office space for a 3 year period ending July 1, 2013. 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 $26,000 and $32,000 in fiscal years 2014 and 2013, respectively.

The Company paid $60,642 and $23,822, in fiscal years 2014 and 2013 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 $178,650 and $60,730 to a director for financial public relations consulting in fiscal years 2014 and 2013, respectively.

11. 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 oil and gas company 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 during on September 2011 to pursue mineral extraction. BIYA conducts operations in the United States primarily in the Horseshoe Gallop field in San Juan County of New Mexico.

BIYA’s 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 three wells by April, 2016, two additional wells by April 2017 and April 2018, each. 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 of 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%.

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The Company has included the results of BIYA’s operations in its consolidated financial statements beginning on October 1, 2014. The following table summarizes the revenue and cost of sales contributed by BIYA:

Fair values of the assets acquired and liabilities assumed in 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, 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 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.

The unaudited results of operations had the acquisition been made at the beginning of the respective years would have been as follows:

	October 31		October 31,
	2014		2013

Revenues	$	1,583,796	$	2,383,733
Net income (loss)	$	714,031	$	(1,397,550	)
Net income (loss) per share	$	0.04	$	(0.10	)

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

Capitalized costs relating to oil and gas producing activities:

	October 31, 2014			October 31, 2013

Proved oil and gas properties	$	3,906,215		$	2,661,144
Proved undeveloped oil and gas leaseholds		1,209,724			64,126
		5,115,939			2,725,270
Less accumulated depletion		(100,062	)		(56,726	)
Net oil and gas properties		5,015,877			2,668,544
Undeveloped oil and gas leasholds	$	21,932,730		$	-

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

	2014		2013

Acquisition of properties:
Proved	$	2,634,245	$	-
Proved undeveloped		3,251,669		64,126
Development costs		7,833		176,839
Exploration costs		41,802		69,878
Total	$	5,935,549	$	310,843

Acquisition cost of proved and proved undeveloped properties acquired in 2014 include properties of BIYA, see Note 11 above for details of the acquisition cost.

13. 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):

	2014			2013

Operating Revenues	$	161,623		$	85,808
Costs & expenses:
Exploration		41,802			69,878
Lease operating expenses		290,588			189,212
Depletion		36,066			13,800
Total costs & expenses		368,456			272,890
Income (loss) before income taxes		(206,833	)		(187,082	)
Income tax (expense) benefit		80,665			72,962
Results of operations for oil and gas producing activities	$	(126,168	)	$	(114,120	)

14. Supplementary Oil and Gas Information (Unaudited)

The following supplemental information regarding the oil and gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission ("SEC") and FASB ASC 932, Disclosures About Oil and Gas Producing Activities.

Estimated net quantities of reserves of oil and gas for the years ended October 31, 2014 and 2013:

					Gallons
	Oil (Bbl)		Gas (Mcf)		NG Liquid

Developed at October 31, 2013		5,379		68,406		-
Proved undeveloped at October 31, 2013		24,077		620,828		4,678,103
Balance, October 31, 2013		29,456		689,234		4,678,103

Developed at October 31, 2014		299,856		51,298		-
Proved undeveloped at October 31, 2014		1,432,256		1,257,190		6,890,814
Balance, October 31, 2014		1,732,112		1,308,488		6,890,814

Notable changes in our reserves are summarized as follows:

We increased our proved developed reserves by 293,600 Bbls through purchase of BIYA.

Proved undeveloped reserves increased due to the acquisition of BIYA, which caused an increase in the barrels of oil of 1,408,000. Increase in MCF of 636,362 and gallons of 2,212,711 incurred due to revisions to Garcia field.

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15. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following is based on natural gas and oil reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will likely differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in these calculations; (3) selection of a 10% discount rate, as required under the accounting codification, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by applying the 12-month average pricing of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Future cash inflows were reduced by estimated future development and production costs based upon year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory rates to future pretax net cash flows and the utilization of net operating loss carry-forwards.

Management does not rely solely upon the following information to make investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable, as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Information with respect to the Company’s Standardized Measure is as follows:

	2014			2013

Future cash inflows	$	158,337,002		$	9,295,085
Future production costs		(36,046,933	)		(2,987,829	)
Future development costs		(19,189,499	)		(4,175,000	)
Future income tax expense		(40,209,222	)		(831,580	)
Future net cash flows		62,891,348			1,300,676
10% annual discount for estimated timing of cash flows		(31,944,372	)		(990,662	)
Standardized measure of discounted future net cash flows	$	30,946,976		$	310,014

There have been significant fluctuations in the posted prices of oil and natural gas during the last two years. Prices actually received from purchasers of the Company’s oil and gas is adjusted from posted prices for location differentials, quality differentials, and BTU content.

The following table presents the prices used to prepare the reserve estimates, based upon the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the respective reporting period presented:

	Oil (Bbl)		Gas (Mcf)		NG Liquid

October 31, 2013 (Average)	$	86.79	$	4.87	$	0.81
October 31, 2014 (Average)	$	83.96	$	4.37	$	0.99

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Principal changes in the Standardized Measure for the years ended October 31, 2014 and 2013 were as follows:

	2014			2013

Standardized measure, beginning of year	$	310,014		$	80,397
Purchase of reserves in place		24,653,719			-
Purchase of proved undeveloped reserves		118,243,820			725,657
Sale and transfers, net of production costs		128,965			103,404
Net changes in prices and production costs		(31,375,014	)		(726,938	)
Extensions, discoveries, and improved recovery		-			135,610
Changes in estimated future development costs		(15,014,499	)		(696,875	)
Development costs incurred during the period		7,833			176,839
Revision of quantity estimates		4,307,700			110,446
Accretion of discount		(30,953,709	)		(124,658)
Net change in income taxes		(39,377,642	)		226,504
Changes in timing and other		15,790			299,628
Standardized measure, end of year	$	30,946,976		$	310,014

Diversified Resources Inc. - FORM 10-K/A - February 20, 2015

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Diversified Resources Inc. Reports