Diversified Resources 8-K/A Completion of Acquisition or Disposition of Assets

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K /A

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (date of earliest event reported):   November 21, 2013

DIVERSIFIED RESOURCES, INC.

(Name of Small Business Issuer in its charter)

Nevada	None	98-0687026
(State of incorporation)	(Commission File No.)	(IRS Employer Identification No.)

1789 W. Littleton Blvd.

Littleton, CO 80120

(Address of principal executive offices, including Zip Code)

Registrant’s telephone number, including area code:  303-797-5417

37 Mayfair Rd. SW

Calgary, Alberta,Canada T2V 1Y8

 (Former name or former address if changed since last report)

Check appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below)

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-14(c) under the Exchange Act (17 CFR 240.13e-4(c))

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Forward-Looking Statements

This report contains "forward-looking statements," as that term is used in federal securities laws, concerning the Company’s financial condition, results of operations and business.  These statements can be found by looking for words such as "believes," "expects," "anticipates," "estimates" or similar expressions used in this report.

These forward-looking statements are based on current expectations about future events. The forward-looking statements include statements that reflect management’s beliefs, plans, objectives, goals, expectations, anticipations and intentions with respect to the Company’s financial condition, results of operations, future performance and business, including statements relating to the Company’s business strategy and current and future development plans.

The potential risks and uncertainties that could cause the Company’s actual financial condition, results of operations and future performance to differ materially from those expressed or implied in this report include:

● the sale prices of crude oil;

● the amount of production from oil wells in which the Company has an interest;

● lease operating expenses;

● international conflict or acts of terrorism; and

● general economic conditions.

Although management believes that the expectations reflected in the forward-looking statements are reasonable, management cannot guarantee future results, level of activity, performance or achievements. Many factors discussed in this report, some of which are beyond the Company’s control, will be important in determining the Company’s future performance. Consequently, actual results may differ materially from those that might be anticipated from the forward-looking statements. In light of these and other uncertainties, investors should not regard the inclusion of a forward-looking statement in this report as a representation by the Company that its plans and objectives will be achieved, and investors should not place undue reliance on such forward-looking statements. The Company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Item 2.01.   Completion of Acquisition or Deposition of Assets.

On November 21, 2013 Diversified Resources, Inc. (“Diversified”) acquired all of the outstanding shares of Natural Resource Group, Inc. (the “Company”) in exchange for 14,558,151 shares of the Diversified’s common stock (the “Acquisition”).

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In connection with the Acquisition:

● Paul Laird , Duane Bacon, Roger May, and Albert McMullin were appointed officers and/or directors of Diversified;

● Philip F. Grey resigned as an officer of Diversified, (but remained as a director until his resignation on April 24, 2014) ;

● Mr. Grey sold 2,680,033 shares of Diversified’s common stock to the Company for nominal consideration.  The shares purchased from Mr. Grey were returned to the status of authorized but unissued shares;

● Mr. Grey agreed to assume all of Diversified’sliabilities (which were approximately $58,000) as of November 21, 2013, the date of the acquisition of Natural Resource Group.

● the former shareholders of the Company now own 85% of Diversified; and

● the Company became a wholly owned subsidiary of Diversified.

Overview of Natural Resource Group

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

In December 2010 the Company acquired oil and gas properties from Energy Oil and Gas, Inc. for 2,500,000 shares of the Company’s common stock and a promissory note in the principal amount of $360,000.  As of April 30, 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.

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Subsequent to December 2010 leases, covering 160 acres in the Garcia Field were sold and leases covering 960 acres in the Garcia Field expired.

The Company is the operator of its wells in the Garcia Field and the Denver- Julesburg Basin.

Garcia Field

The Company has a 100% working interest (81.25% 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 acquired from Energy Oil and Gas are currently producing a combined total of 110 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 report, of $1.15 per gallon.

The fifth well is used to re-inject the gas back into the Apishapa and Niobrara formations since, as of the date of this report, the Company’s wells were still 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.  The Company believes there is enough capacity in KM’s transportation line to transport gas produced from the Company’s wells.  However, to connect the Company’s wells to the KM line, the Company will need to install an eight mile long gathering system at an estimated cost of $1,000,000, which includes a tap fee

In 2012 the Company installed new equipment at its refrigeration/compression plant.  The Company expects that the new equipment will increase the yield of natural gas liquids to 3.5 gallons per mcf.

In 2012 the Company drilled a shallow (1,600 foot) well in the field.  As of the date of this report, the well was in the process of completion.

The gas from the Company’s wells has a BTU content of approximately 1,500.  It is the Company’s 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.

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As of April 30, 2014 , the Company was in the process of permitting three well locations.  The new wells will be drilled to a depth of approximately 2,000 feet for the shallow natural gas liquid wells and up  to 7,000 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 $75,000 for the shallow wells and up to $400,000 for the deep wells.

Participation Agreement

During the year ended October 31, 2012, the Company borrowed $250,000 from an unrelated third party.  In consideration for making the loan, the lender was assigned a 1% overriding royalty interest in the Garcia field, as well as a net profits interest in the Company’s four producing wells in the field and the three additional wells the Company plans to drill in the field.

The net profits interest is equal to 20% of the gross proceeds from the sale of oil, gas or natural gas liquids from the four producing wells and the three additional wells to be drilled in the Garcia field,  reduced by 20% of the following expenditures:

● any overriding royalties or other burden on production, not to exceed a 20% of gross production;

● production, severance and similar taxes assessed on production;

● costs reasonably incurred to process the production; and

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

Denver/Julesburg Basin

The Company has 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 and net revenue interests in the wells shown below :

	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.

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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 April 30, 2014 the producing wells acquired from Energy Oil and Gas were collectively producing approximately five bbls of oil and 32 mcf of gas per day.

The Company plans to hydraulically fracture its wells in the D-J Basin at a cost of approximately $35,000 per well.  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 the Company acquired a 640 acre lease (100% working interest, 80% net revenue interest) in the D-J Basin.

During the twelve months ending December 31, 2014, the Company plans to:

● recomplete the three shut-in wells acquired from Energy Oil and Gas, at a cost of approximately $130,000 per well;

● drill up to eight additional wells to the Sussex formation (5,700 feet) in the D-J Basin. The cost to drill, and if warranted complete, each well will be approximately $350,000; and

● drill at least one well in the D-J Basin to the Codell/Niobrara formations (7,800 feet).  The cost to drill, and if warranted complete, the well will be approximately $800,000.

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

	Years Ended October 31,
	2013		2012		2011
Production:
Oil (Bbls)		276		417		206
Gas (Mcf)		4,500		5,015		4,571
Natural Gas Liquids(gallons)		37,230		20,375		28,359

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Average sales price:
Oil ($/Bbl1)	$	86.79	$	92.94	$	91.57
Gas ($/Mcf2)	$	4.87	$	3.04	$	4.76
Nat.GasLiquids  ($/gal)	$	0.81	$	0.77	$	1.36
Average production
cost per BOE3	$	39.25	$	58.85	$	37.05

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.The Company is 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, the Company has not had, nor does not now have, any long-term supply or similar agreement with any government or governmental authority.

The following shows drilling activity for the three years ended October 31, 2013.

	October 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive
		1		0.75		1		1		--		--
Nonproductive		--		--		--		--		--		--
Productive Wells:
Productive		--		--		--		--		--		--
Nonproductive		--		--		--		--		--		--

As of April 30, 2014 the Company was not drilling or reworking any oil or gas wells, and one well in the Garcia Field was awaiting completion.

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The following table shows, as of April 30, 2014 , the Company 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
Colorado:
Garcia Field		5		5		200		200		4,400		4,400
D-J Basin		4		3		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 April 30, 2014 , the status of the Company’s gross acreage:

Location	Held by Production		Not Held by Production
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 the Company’s 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

Proved Reserves

Below are estimates of the Company’s net proved reserves as of October 31, 2013 , net to the Company’s interest. All of the Company’s proved reserves are located in Colorado.

Estimates of volumes of proved reserves at October 31, 2013 are presented in barrels (Bbls) for oil and, for natural gas, in millions of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.

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	Oil		Gas		NGL
	(Bbls)		(Mcf)		Gallons
Proved Developed:
Producing		5,379		68,406		-0-
Non-Producing
Proved Undeveloped		24,077		689,234		4,678,103

‘‘Bbl’’ refers to one stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons. ‘‘Mcf’’ refers to one thousand cubic feet. A BOE (i.e., barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil. Below are estimates of the Company’s present value of estimated future net revenues from proved reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions. The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the twelve months period ended October 31, 2013 . The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year.

Future cash inflows	$	9,295,085
Deductions (including estimated taxes)		(7,994,409	)
Future net cash flow		1,300,676
Discount to present value		(990,662	)
Discounted future net cash flow	$	310,014

Gustavson Associates, LLC prepared the estimates of the Company’s proved reserves, future production and income attributable to the Company’s leasehold interests in the Garcia Field as of October 31, 2013 . Gustavson Associates is an independent petroleum engineering firm that provides petroleum consulting services to the oil and gas industry. The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by engineers employed at Gustavson Associates.

Letha C. Lencioni was the technical person primarily responsible for overseeing the preparation of the reserve report for the Garcia Field.  Ms. Lencioni earned a Bachelor’s Degree in Petroleum Engineering in 1980 from Tulsa University and has more than 30 years of practical experience in the estimation and evaluation of petroleum reserves.  Gustavson Associates has more than 30 years of practical experience in the estimation and evaluation of petroleum reserves.

McCartney Engineering, LLC prepared the estimates of the Company’s proved reserves, future production and income attributable to the Company’s leasehold interests in the D-J Basis as of October 31, 2013 . McCartney Engineering is an independent petroleum engineering firm that provides petroleum consulting services to the oil and gas industry. The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by engineers employed at McCartney Engineering.

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Jack A. McCartney was the technical person primarily responsible for overseeing the preparation of the reserve report for the Wattenberg Field.  Mr. McCartney earned a Bachelor’s Degree in Petroleum Engineering from Colorado School of Mines in 1965 and a Master’s Degree in Engineering in 1971 from Colorado School of Mines.  McCartney Engineering has more than 40 years of practical experience in the estimation and evaluation of petroleum reserves.

Paul Laird, the Company’s Chief Executive Officer, oversaw the preparation of the reserve estimates by McCartney Engineering, LLC and Gustavson Associates, LLC.  Mr. Laird has over 30 years’ experience in oil and gas exploration and development.  The Company does not have a reserve committee and does not have any specific internal controls regarding the estimates of reserves.

The Company’s proved reserves include only those amounts which the Company reasonably expects to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology. Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.

Proved reserves were estimated by performance methods, the volumetric method, analogy, or a combination of methods utilizing present economic conditions and limited to those proved reserves economically recoverable. The performance methods include decline curve analysis that utilize extrapolations of historical production and pressure data available through October 31, 2013 in those cases where such data were considered to be definitive.

Forecasts for future production rates are based on historical performance from wells currently on production in the region with an economic cut-off for production based upon the projected net revenue being equal to the projected operating expenses. No further reserves or valuation were given to any wells beyond their economic cut-off. Where no production decline trends have been established due to the limited historical production records from wells on the properties, surrounding wells historical production records were used and extrapolated to wells of the property. Where applicable, the actual calculated present decline rate of any well was used to determine future production volumes to be economically recovered. The calculated present rate of decline was then used to determine the present economic life of the production from the reservoir.

For wells currently on production, forecasts of future production rates were based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to economic depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

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Proved developed non-producing and undeveloped reserves were estimated primarily by the performance and historical extrapolation methods. Test data and other related information were used to estimate the anticipated initial production rates from those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at a date determined to be reasonable.

In general, the volume of production from the Company’s oil and gas properties declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, proved reserves will decline as reserves are produced. Accordingly, volumes generated from future activities are highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.

Future Operations

The Company plans 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, the Company plans to concentrate its activities in the Garcia Field and the D-J Basin in Colorado. The Company’s strategy is to acquire prospects in or adjacent to existing fields with further development potential and minimal risk in the same area. The extent of the Company’s activities will primarily be dependent upon available capital.

If the Company believes a geographical area indicates geological and economic potential, it will attempt to acquire leases or other interests in the area. The Company may then attempt to sell portions of its 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.

The Company 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 the Company 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.

The Company’s 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.

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Although the Company normally obtains title reports for oil leases it acquires, the Company has not in the past obtained, 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 will 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, require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil. Colorado and other 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 Colorado 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, the Company is unable to predict the future cost or impact of complying with those laws.

As with the oil and natural gas industry in general, the Company’s 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 acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from the Company’s operations; and require the reclamation of certain lands.

The permits required for many of the Company’s 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, the Company is in substantial compliance with current applicable environmental laws and regulations, and has 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 the Company, 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

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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 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

The Company will be 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. The Company may be at a competitive disadvantage in acquiring prospects since it 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. The Company will 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 the 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 the Company’s 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 April 30, 2014 , the Company’s oil production was being sold to Suncor.  Natural gas sales were made to Kerr McGee and the Company’s natural gas liquids were being sold to Donovan Resources.

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. The Company is 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. The Company is unable to predict the future prices they will receive for their production of natural gas, natural gas liquids and its components.

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Although as of April 30, 2014 the Company was selling its crude oil to one customer and its natural gas liquids to another customer, the Company does not believe that the loss of either of these customers would have a material effect on its operations since there is a ready market for crude oil and natural gas liquids.

However, natural gas cannot be produced unless it is connected to a pipeline.

The Company’s gas wells in the Garcia field are not connected to a pipeline.  If and when the Company is able to connect its gas wells in the Garcia field to a pipeline, it will be dependent on the owner of the line to transport the Company’s gas.

The Company’s wells in the D-J Basin are connected to a pipeline and as of January 31, 2014 the wells were collectively producing approximately 32 mcf of gas per day.  However, if the pipe line was not available to transport the Company’s gas, the Company would have to shut in its gas wells until the Company could connect its gas wells to another pipeline  The pipeline presently transporting gas produced from the Company’s wells may be unavailable for a variety of reasons, including equipment failure and over capacity.

The inability of the Company to transport gas produced from its wells may have a material adverse effect on the Company’s operations, depending upon the quantities of oil produced in comparison to the quantities of gas which could be produced if a pipeline was available.

General

As of April 30, 2014 , the Company had four full-time employees and no part-time employees.

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

The Company is a licensed oil and gas operator in Colorado.

RISK FACTORS

Investors should be aware that an investment in the Company’s securities involves certain risks, including those described below, which could adversely affect the value of the Company’s common stock.  The Company does not make, nor has it authorized any other person to make, any representation about the future market value of the Company’s common stock.  In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in the Company’s securities.

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The Company may suffer losses in future periods.  The Company suffered net losses of $(1,170,403) and $(842,219) respectively, during the two years ended October 31, 2013.  The Company had negative working capital in the amount of $(624,478) at October 31, 2013 .

The Company’s failure to obtain capital may restrict operations.  The Company may need additional capital to fund operating losses and to expand business.  The Company does not know what the terms of any future capital raising may be but any future sale of equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the price investors pay for the shares of common stock.  The Company’s failure to obtain the capital which is required may result in the slower implementation of the Company’s business plan.  There can be no assurance that the Company will be able to obtain the capital needed.

Drilling.  Energy exploration is not an exact science, and involves a high degree of risk.  The primary risk lies in the drilling of dry holes or drilling and completing wells  that, though productive, do not produce oil/gas/natural gas liquids in sufficient amounts to return the amounts expended and produce a profit.  Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids, malfunctioning of separation plants and systems and other conditions are involved in drilling and completing wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented.  In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs.  Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil, gas or gas liquids from the well.

Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than with development drilling.  Exploratory drilling itself can involve varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs.  While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil, gas and natural gas liquids than in completely unproven areas, exploratory efforts are nevertheless high risk activities.

Although the completion of a well is, to a certain extent, less risky than drilling, the process of completing a well is nevertheless associated with considerable risk.  In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce sufficient oil in order to repay the investment in the well.  As a result, there is considerable economic risk associated with the Company’s activities.

Economic Factors in Oil, Gas and Natural Gas Liquids Exploration.  The acquisition, exploration and development of energy properties, and the production and sale of oil, natural gas and natural gas liquids are subject to many factors which are outside the Company’s control.  These factors include, among others, general economic conditions, proximity to pipelines, oil import quotas, supply, demand, and price of other fuels and the regulation of production, refining, transportation, pricing, marketing and taxation by Federal, state, and local governmental authorities.

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Title Uncertainties.  Interests that the Company may acquire in properties may be subject to royalty and overriding royalty interests, liens incident to operating agreements, liens for current taxes and other burdens and encumbrances, easements and other restrictions, any of which may subject the Company to future undetermined expenses.  The Company does not intend to purchase title insurance, title memos, or title certificates for any leasehold interests it acquires.  It is possible that at some point the Company will have to undertake title work involving substantial costs.  In addition, it is possible that the Company may suffer title failures resulting in significant losses.

Uninsured Risks.   The drilling of wells involves hazards such as blowouts, unusual or unexpected formations, pressures or other conditions which could result in substantial losses or liabilities to third parties.  The Company intends to acquire adequate insurance, or to be named as an insured under coverage acquired by others (e.g., the driller or operator), the Company may not be insured against all such losses because such insurance may not be available, premium costs may be deemed unduly high, or for other reasons.  Accordingly, uninsured liabilities to third parties could result in the loss of funds or property.

Government Regulation.    The Company’s operations are affected from time to time and in varying degrees by political developments and Federal and state laws and regulations regarding the development, production and sale of crude oil, natural gas and gas liquids.  These regulations require permits for drilling of wells and also cover the spacing of wells, the prevention of waste, completion technologies and other matters.  Rates of production of oil and gas have for many years been subject to Federal and state conservation laws and regulations and the petroleum industry is subject to Federal tax laws.  In addition, the production of oil, natural gas and natural gas liquids may be interrupted or terminated by governmental authorities due to ecological, environmental and other considerations.  Compliance with these regulations may require a significant capital commitment by and expense to the Company and may delay or otherwise adversely affect proposed operations.

From time to time legislation has been proposed relating to various conservation and other measures designed to decrease dependence on foreign oil.  No prediction can be made as to what additional legislation may be proposed or enacted.  Oil producers may face increasingly stringent regulation in the years ahead and a general hostility towards the oil and gas industry on the part of a portion of the public and of some public officials.  Future regulation will probably be determined by a number of economic and political factors beyond the Company’s control or the oil and gas industry.

Environmental Laws.  The Company’s activities will be subject to existing federal and state laws and regulations governing environmental quality and pollution control.  Compliance with environmental requirements and reclamation laws imposed by Federal, state, and local governmental authorities may necessitate significant capital outlays and may materially affect earnings.  It is impossible to predict the impact of environmental legislation and regulations (including regulations restricting access and surface use) on operations in the future although compliance may necessitate significant capital outlays, materially affect earning power or cause material changes in the Company’s intended business.  In addition, the Company may be exposed to potential liability for pollution and other damages.

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Disclosure requirements pertaining to penny stocks may reduce the level of trading activity in the Company’s securities and investors may find it difficult to sell their shares.  Trades of Diversified’s common stock are subject to Rule 15g-9 of the Securities and Exchange Commission, which rule imposes certain requirements on broker/dealers who sell securities subject to the rule to persons other than established customers and accredited investors.  For transactions covered by the rule, brokers/dealers must make a special suitability determination for purchasers of the securities and receive the purchaser's written agreement to the transaction prior to sale.  The Securities and Exchange Commission also has rules that regulate broker/dealer practices in connection with transactions in "penny stocks".  Penny stocks generally are equity securities with a price of less than $5.00 (other than securities registered on certain national securities exchanges or quoted on the NASDAQ system, provided that current price and volume information with respect to transactions in that security is provided by the exchange or system).  The penny stock rules require a broker/ dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document prepared by the Commission that provides information about penny stocks and the nature and level of risks in the penny stock market.  The broker/dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker/dealer and its salesperson in the transaction, and monthly account statements showing the market value of each penny stock held in the customer's account.  The bid and offer quotations, and the broker/dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation.

MARKET FOR THE COMPANY’S COMMON STOCK.

There has never been a market for the Company’s common stock and, as of the date of this report, all of the Company’s common stock was owned by Diversified.

Since November 2012, Diversified’s common stock has been quoted on the OTCQB tier of the OTC Markets Group under the symbol “DDRI.” However, Diversified’s common stock did not begin to trade until July 2013. The following shows the reported high and low prices for Diversified’s common stock, based on information provided by the OTCQB, for the periods shown . 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
October 31, 2013	$	1.20	$	0.70
January 31, 2014	$	0.70	$	1.30

Holders of Diversified’s common stock are entitled to receive dividends as may be declared by the Board of Directors.  Diversified’s 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.  Diversified currently intends 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 Diversified’s financial condition, results of operations, capital requirements and other factors the board of directors considers relevant.

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Diversified’s Articles of Incorporation authorize the 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 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.

As of the date of this report, Diversified had approximately 120 shareholders of record and 17,128,117 outstanding shares of common stock, which amounts reflect the acquisition of the Company by Diversified.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATION

The following discussion should be read in conjunction with the Company’s financial statements included as part of this report.

The Company was incorporated in Colorado in 2000, but was relatively inactive until December 2010.

On November 21, 2013 Diversified acquired 100% of the outstanding shares of the Company in exchange for 14,558,151 shares of Diversified’s common stock.

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

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, 2013 compared to the year ended October 31 2012.

For the year ended October 31, 2013 we reported a net loss of $(1,170,403) or $ (0.09) per share compared with a net loss of $ (842,219) or $ (0.06) per share for the year ended October 31, 2012.  The increase in the net loss of $ 328,184 (39%) principally arises from the other income (expense) category in the statement of operations, primarily the loss on extinguishment of debt in the amount of $330,638.

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Operating revenues were $96,155 for the year ended October 31, 2013 compared with $79,104 for the year ended October 31, 2012.  Operating revenues increased $17,051 (22%) for the year ended October 31, 2013 compared to the year ended October 31, 2012.  Of that increase, our oil and gas revenues increased $6,704 (8%) and consulting fees of $10,347 accounted for the increase. The increase on oil and gas revenues is primarily attributable to increased prices for the oil and gas sold. The Company has, and will, provide consulting services for other entities; however, it is not considered a normal recurring business and not the primary focus of the Company’s business.

Lease operating expenses were $189,212 for the year ended October 31, 2013 compared with $117,357 for the year ended October 31, 2012.  Lease operating expenses increased $71,855 (61%) for the year ended October 31, 2013 compared to the year ended October 31, 2012.  The primary increase was at the Garcia Field in the amount of $55,0844 in additional compression expenses combined with costs in the amount of $16,771at the Garcia Field and the DJ area.  Increased compression expenses arose because the Company added additional compression facilities at the Garcia Field not present in 2012. The fluctuations are considered normal in the ordinary course of business.

Depreciation expense was $7,641 for the year ended October 31, 2013 compared with $1,148 for the year ended October 31, 2012, an increase of $6,493 (566%) and is a result of increased equipment in 2013 compared to 2012.

Depletion expense was $13,800 for the year ended October 31, 2013 compared with $25,155 for the year ended October 31, 2012, a decrease of $11,355 (45%) and is a primarily a function of decreased production combined with changes in estimated reserves for the calculation.    The fluctuations are considered normal in the ordinary course of business.

Impairments and abandonments were $0 for the year ended October 31, 2013 compared with $120,798 for the year ended October 31, 2012, a decrease of $120,798 because the Company did not incur impairments or abandon any properties in 2013.

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, 2012. The increase arose because the Company settled certain obligations using its Common Stock in 2013 and such settlements were not present in 2012.

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, 2012. The increase arose because the Company did not dispose of any assets in 2012.

Interest expense was $126,586 for the year ended October 31, 2013 compared with $70,644 for the year ended October 31, 2012, an increase of $55,942 (79%).  The increase is directly attributable to the increased amount of loans outstanding during 2013 compared to 2012.

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;

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● 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.

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, the Company has incurred significant operating losses since inception aggregating $3,008,453 and has negative working capital of $624,478 at October 31, 2013.  As of October 31, 2013, 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 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 the Company 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, 2013 and 2012 are summarized below:

	Years Ended
	October 31,			October 31,
	2013			2012
Net cash (used in) operating activities	$	(642,311	)	$	(451,168	)
Funds from sale of assets		65,583			-
Purchase of property and equipment		(19,412	)		(3,122	)
Purchases of oil and gas properties		(240,965	)		(251,581	)
Proceeds from the sale of common stock		859,760			350,000
Proceeds from notes payable		79,965			320,000
Payments on notes payable		(1,508	)		(1,105	)
Payments on related party notes payable		(32,730	)		(28,957	)
Net increase (decrease) in cash	$	68,382		$	(65,933	)

As of April 30, 2014 , operating expenses were approximately $41,400 per month, which amount includes salaries and other corporate overhead, but excludes :

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● expenses associated with drilling, completing or reworking wells, and

● lease operating and interest expenses.

See Notes 4 and 5 to the October 31, 2013 financial statements, included as part of this report, for information concerning the Company’s outstanding loans.

The Company estimates its capital requirements for the twelve months ending December 31, 2014 are as follows:

●	Drilling, completing, and fracturing wells	$	1,740,000
●	Install gathering line (1)	$	150,000
●	Seismic work	$	120,000

(1) If installed, the line will transport gas from the new wells the Company plans to drill and complete in the Garcia field to the Company’s refrigeration/compression plant.

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

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.

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Other than as disclosed above, the Company does 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

The Company’s material future contractual obligations as of October 31, 2013 were as follows:

	Total		10/31/14		10/31/2015		10/31/2016		Thereafter
10/31/13	$	444,422	$	323,588	$	111,762	$	4,692	$	4,380
04/30/14	$	442,076	$	321,242	$	111,762	$	4,692	$	4,380

Critical Accounting Policies and New Accounting Pronouncements

See Note 1 to the financial statements included as part of this report for a description of the Company’s critical accounting policies and the potential impact of the adoption of any new accounting pronouncements.

MANAGEMENT

Diversified’s 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	57	Chief Executive Officer, Principal Financial and Accounting Officer and a Director
Duane Bacon	76	Chief Operating Officer and a Director

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Name	Age	Position
Roger May	57	Director
Albert McMullin	56	Director

On November 21, 2013 Diversified acquired all of the outstanding shares of the Company in exchange for 14,558,151 shares of the Diversified’s common stock.  In connection with this transaction, Paul Laird, Duane Bacon, Roger May and Albert McMullin were appointed officers and/or directors of Diversified.

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

Paul Laird was appointed as our Chief Executive Officer and a director of Diversified on November 21, 2013.  Since 1997 Mr. Laird has been the Chief Executive Officer and a Director of the Company.  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 the Chief Operating Officer and a director of Diversified on November 21, 2013.   Since December 2010, Mr. Bacon has been the Chief Operating Officer of NRG.  Between 2000 and December 2010 Mr. Bacon was the President of Energy Oil and Gas, Inc. a private exploration and production company located in Longmont, Colorado.

Roger May was appointed a director of Diversified on November 21, 2013.   Between 2010 and 2013, Mr. May was a director of Natural Resource Group.   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 had over 25 years of experience in the financial industry with Rausher Pierce and Schnieder Securities.

Albert McMullin was appointed a director of Diversified on November 21, 2013.  He has been a director of NRG since 2011.  Since 2010 he has been the 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

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The Board of Directors serves as the Company’s audit and compensation committee.

Mr. McMullin, is independent, as that term is defined in Section 803 A(2) of the NYSE MKT Company Guide.   The Company does not have a financial expert.

The Company has not adopted a code of ethics applicable to its principal executive, financial and accounting officers and persons performing similar functions.

Executive Compensation

The following table summarizes the compensation received by the Company’s principal executive and financial officers during the two years ended October 31, 2013.

							Restricted				Other
							Stock		Option		Annual
Name and	Fiscal		Salary		Bonus		Awards		Awards		Compensation
Principal Position	Year			(1)		(2)		(3)		(4)		(5)	Total
				$								$		$
Paul Laird		2013		150,000		--		--		--		445		150,445
Chief Executive Officer		2012		150,000		--		--		--		791		150,791
Duane Bacon		2013		66,000		--		--		--		445		66,445
Chief Operating Officer		2012		66,000		--		--		--		791		66,791

(1)	The dollar value of base salary (cash and non-cash) earned.
(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 the Company expects to pay to its officers and directors during the twelve months ending October 31, 2014 and the amount of time these persons expect to devote to the Company.

			Percent of Time
	Projected		to be Devoted to the
Name	Compensation		Company’s Business
Paul Laird	$	150,000		100	%
Duane Bacon	$	66,000		100	%

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On January 1, 2011 the Company entered into an employment agreement with Paul Laird.  The employment agreement provides that the Company will pay Mr. Laird a monthly salary of $12,500 during the term of the agreement.  The Employment Agreement may be terminated at any time by either the Company or Mr. Laird.

On January 1st of each year Mr. Laird will receive an annual cost of living increase equal to that received by employees of the Federal Government for the most recent year that data is available.

If during the term of the Agreement the Company has three consecutive months of positive cash flow to such an extent that the Company would still be in positive cash flow if Mr. Laird’s salary was increased by 50%, Mr. Laird will receive an increase in his salary equal to his current salary multiplied by 50%.

If Mr. Laird resigns or is terminated within a period beginning six months prior, and ending six months after a change in control, Mr. Laird will receive a payment from the Company equal to twelve months of his then current salary.

If during the term of this Agreement Mr. Laird’s employment is terminated for any reason other than cause, death, or permanent disability, then the Company will pay Mr. Laird an amount equal to four months of his base salary then in effect.

For purposes of the employment agreement:

● a change in control means either (i) a change in more than 32% of the members of the Board of Directors; or (ii) any entity, individual, or group of related entities or individuals obtains 40% or more ownership in the Company.

● cause means:

(i)         the commission, conviction of, or a plea of "guilty" or "no contest" by Mr. Laird to a felony under the laws of the United States or any state if such felony is work-related, materially impairs Mr. Laird’s ability to perform services for the Company, or results in a material loss to the Company or material damage to the reputation of the Company;

(ii)          Mr. Laird’s theft of the Company’s funds or property;

● permanent disability means Mr. Laird’s inability to perform the essential functions of his position with or without reasonable accommodation for a period of 90 consecutive days due to any physical or mental impairment.

On December 29, 2010 the Company entered into an employment agreement with Duane Bacon.  The employment agreement provides that the Company will pay Mr. Bacon a monthly salary of $5,500 during the term of the agreement.  The Employment Agreement may be terminated at any time by either the Company or Mr. Bacon.

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On January 1st of each year Mr. Bacon will receive an annual cost of living increase equal to that received by employees of the Federal Government for the most recent year that data is available.

If during the term of the Agreement the Company has three consecutive months of positive cash flow to such an extent that the Company would still be in positive cash flow if Mr. Bacon’s salary was increased by 50%, Mr. Bacon will receive an increase in his salary equal to his current salary multiplied by 50%.

Upon the sale of any of the Company’s assets, any sale of the Company’s capital stock, or the acquisition or merger of the Company, the Company will pay Mr. Bacon 1.5% of the proceeds from the sale of the assets or capital stock, or 1.5% of the value of the acquisition or merger.

Upon the acquisition by the Company of any producing oil and gas properties, Mr. Bacon will receive 0.75% of the price paid for the properties.

If Mr. Bacon resigns or is terminated within a period beginning six months prior, and ending six months after a change in control, Mr. Bacon will receive a payment from the Company equal to twelve months of his then current salary.

If during the term of this Agreement Mr. Bacon’s employment is terminated for any reason other than cause, death, or permanent disability, then the Company will pay Mr. Bacon an amount equal to four months of his base salary then in effect.

For purposes of the employment agreement:

● a change in control means either (i) a change in more than 32% of the members of the Board of Directors; or (ii) any entity, individual, or group of related entities or individuals obtains 40% or more ownership in the Company.

● cause means:

(i)         the commission, conviction of, or a plea of "guilty" or "no contest" by Mr. Bacon to a felony under the laws of the United States or any state if such felony is work-related, materially impairs Mr. Bacon’s ability to perform services for the Company, or results in a material loss to the Company or material damage to the reputation of the Company;

(ii)       Mr. Bacon’s theft of the Company’s funds or property;

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● permanent disability means Mr. Bacon’s inability to perform the essential functions of his position with or without reasonable accommodation for a period of 90 consecutive days due to any physical or mental impairment.

Stock Option and Stock Bonus Plans. The Company does not have any stock option plans although the Company may adopt one or more of such plans in the future.

Long-Term Incentive Plans. The Company does not provide its officers or employees with pension, stock appreciation rights or long-term incentive plans.

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

Other Arrangements.  The Company has granted Paul Laird and Duane Bacon each a 1% overriding royalty on the Company’s leases in the Garcia Field.  In the discretion of the Company’s directors, the Company may in the future grant overriding royalty interests to other persons.

Compensation of Directors During Year Ended October 31, 2013. During the year ended October 31, 2013, the Company did not compensate its directors for acting as such.

Related Party Transactions

In December 2010 the Company acquired oil and gas properties from Energy Oil and Gas, Inc. for 2,500,000 shares of the Company’s common stock and a promissory note in the principal amount of $360,000.  Duane Bacon, an officer and director of the Company, controls Energy Oil and Gas, Inc.

In connection with the acquisition of the Company by Diversified, the following officers and directors received shares of Diversified’s common stock in the amounts shown below.

Name	Number of  Shares
Paul Laird	3,135,642
Duane Bacon	2,020,531
Roger May	412,174 (1)
Albert McMullin	106,793

(1) Mr. May received 128,498 shares of Diversified’s common stock for his services in arranging the acquisition of the Company by Diversified.

Philip F. Grey, a former officer and director of the Company, agreed to assume all of the Company’s liabilities (which were approximately $58,000) as of November 21, 2013, the date of the acquisition of Natural Resource Group.

The Company paid $23,822, $43,116 and $63,074 during the fiscal years ended October 31, 2013, 2012 and 2011, respectively, to Paul Laird’s brother for land-man fees and expense reimbursements for performing contract land services for the Company.

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The Company paid $60,730 to Roger May for investor relations consulting in fiscal 2013.

Paul Laird has a 50% interest in a partnership which leases office space to the Company.  The Company paid rent of $32,000 to the partnership in each of the three years ended October 31, 2013.

As discussed above under the heading “Other Arrangements”, the Company has granted Paul Laird and Duane Bacon  overriding royalties on some of the Company’s leases.

PRINCIPAL SHAREHOLDERS

The following table shows the beneficial ownership of Diversified’s common stock, as of April 30, 2014 , and after giving effect to the acquisition of the Company, by (i) each person whom Diversified knows beneficially owns more than 5% of the outstanding shares of its common stock, (ii) each of Diversified’s officers, (iii) each of Diversified’s 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 and 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			18.3	%
1789 w. Littleton Blvd
Littleton, CO  80120
Duane Bacon		2,020,531	(1)		11.8	%
5982 Heather Way
Longmont, CO  80503
Roger May		540,672			3.2	%
2780 Indiana Street
Golden, CO  80401

28

Name and Address	Number of Shares			Percentage
of Beneficial Owner	Beneficially Owned			of Class
Albert McMullin		106,793	(2)		.06	%
4501 Merrie Lane
Belaire, TX  77401
Frank Grey		50,000			.03	%
2114 Ridge Plaza Drive
Castle Rock, CO  80108
All officers and directors
as a group (five persons).		5,853,638			34	%

(1) Shares are held in the name of Energy Oil and Gas, a company controlled by Mr. Bacon.

(2) Shares are held in the name of partnerships controlled by Mr. McMullin.

RECENT SALES OF UNREGISTERED SECURITIES

The following lists all sales of the Company’s common stock during the three years ended October 31, 2013.

On October 18, 2010, the Company sold 208,820 shares of its Series A preferred stock to 1 person for $50,000 in cash.

On December 22, 2010, the Company issued 2,500,000 shares of its common stock to Energy Oil and Gas, Inc. in exchange for certain oil and gas assets valued at $2,500,000.

Between February 27, 2011, and September 6, 2011 the Company sold 660,000 shares of its common stock to twelve persons for $660,000 in cash.

During the year ended October 31, 2012, the Company sold 350,000 shares of its common stock to eleven persons for $350,000 in cash.

In May and June 2013, the Company issued 395,877 shares of its common stock to one person to settle $65,240 of accounts payable.

During the year ended October 31, 2013, the Company sold 895,750 shares of its common stock to 25 persons for $859,760 in cash.

In May 2013, the Company’s Series A preferred stock (held by 1 person) was converted into 208,820 shares of the Company’s common stock.

Subsequent to October 31, 2013, Diversified sold 743,750 shares of its common stock to nine  persons for $340,000 .

The Company relied upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933 with respect to the sale and issuance of the shares described above.  The purchasers of these securities were sophisticated investors who were provided full information regarding the Company’s business and operations.  There was no general solicitation in connection with the offer or sale of these shares.  The purchasers acquired the shares for their own accounts.  The shares cannot be sold unless pursuant to an effective registration statement or an exemption from registration.

29

DESCRIPTION OF SECURITIES

Common Stock

Diversified is authorized to issue 450,000,000 shares of common stock. Holders of common stock are each entitled to cast one vote for each share held of record on all matters presented to shareholders. Cumulative voting is not allowed; hence, the holders of a majority of Diversified’s outstanding shares of common stock can elect all directors.

                   Holders of common stock are entitled to receive such dividends as may be declared by the Board out of funds legally available and, in the event of liquidation, to share pro rata in any distribution of the Company’s assets after payment of liabilities.  Diversified’s directors are not obligated to declare a dividend. It is not anticipated that dividends will be paid in the foreseeable future.

                  Holders of common stock do not have preemptive rights to subscribe to any additional shares which may be issued in the future.  There are no conversion, redemption, sinking fund or similar provisions regarding the common stock.  All outstanding shares of common stock are fully paid and nonassessable.

Preferred Stock

Diversified is authorized to issue 50,000,000 shares of preferred stock. Shares of preferred stock may be issued from time to time in one or more series as may be determined by the Board of Directors.  The voting powers and preferences, the relative rights of each such series and the qualifications, limitations and restrictions of each series will be established by the Board of Directors. Diversified’s directors may 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 Diversified’s 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 transactions such as mergers or tender offers if these transactions are not favored by management.  As of the date of this prospectus Diversified had not issued any shares of preferred stock.

Transfer Agent and Registrar

                   Diversified’s transfer agent is:

Transhare

4626 S. Broadway

Englewood, CO  80113

Phone: 303-662-1112

Fax: 303-662-1113

LEGAL PROCEEDINGS

Neither the Company nor Diversified is involved in any legal proceedings and neither the Company nor Diversified know of any legal proceedings which are threatened or contemplated.

30

INDEMNIFICATION

The Company’s Bylaws authorize indemnification of a director, officer, employee or agent against expenses incurred by him in connection with any action, suit, or proceeding to which he is named a party by reason of his having acted or served in such capacity, except for liabilities arising from his own misconduct or negligence in performance of his duty.  In addition, even a director, officer, employee, or agent found liable for misconduct or negligence in the performance of his duty may obtain such indemnification if, in view of all the circumstances in the case, a court of competent jurisdiction determines such person is fairly and reasonably entitled to indemnification.  Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to the Company’s directors, officers, or controlling persons pursuant to these provisions, the Company has been informed that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Act and is therefore unenforceable.

31

GLOSSARY OF OIL AND GAS TERMS

DEVELOPED ACREAGE. The number of acres that are allocated or assignable to productive wells or wells capable of production.

DISPOSAL WELL. A well employed for the reinjection of salt water produced with oil into an underground formation.

HELD BY PRODUCTION. A provision in an oil, gas and mineral lease that perpetuates an entity's right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas.

INJECTION WELL. A well employed for the injection into an underground formation of water, gas or other fluid to maintain underground pressures which would otherwise be reduced by the production of oil or gas.

LANDOWNER'S ROYALTY. A percentage share of production, or the value derived from production, which is granted to the lessor or landowner in the oil and gas lease, and which is free of the costs of drilling, completing, and operating an oil or gas well.

LEASE. Full or partial interests in an oil and gas lease, authorizing the owner thereof to drill for, reduce to possession and produce oil and gas upon payment of rentals, bonuses and/or royalties. Oil and gas leases are generally acquired from private landowners and federal and state governments. The term of an oil and gas lease typically ranges from three to ten years and requires annual lease rental payments of $1.00 to $2.00 per acre. If a producing oil or gas well is drilled on the lease prior to the expiration of the lease, the lease will generally remain in effect until the oil or gas production from the well ends. The owner of the lease is required to pay the owner of the leased property a royalty which is usually between 12.5% and 16.6% of the gross amount received from the sale of the oil or gas produced from the well.

LEASE OPERATING EXPENSES. The expenses of producing oil or gas from a formation, consisting of the costs incurred to operate and maintain wells and related equipment and facilities, including labor costs, repair and maintenance, supplies, insurance, production, severance and other production excise taxes.

NET ACRES OR WELLS. A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions.

NET REVENUE INTEREST. A percentage share of production, or the value derived from production, from an oil or gas well and which is free of the costs of drilling, completing and operating the well.

OVERRIDING ROYALTY. A percentage share of production, or the value derived from production, which is free of all costs of drilling, completing and operating an oil or gas well, and is created by the lessee or working interest owner and paid by the lessee or working interest owner to the owner of the overriding royalty.

32

PRODUCING PROPERTY. A property (or interest therein) producing oil or gas in commercial quantities or that is shut-in but capable of producing oil or gas in commercial quantities. Interests in a property may include working interests, production payments, royalty interests and other non-working interests.

PROSPECT. An area in which a party owns or intends to acquire one or more oil and gas interests, which is geographically defined on the basis of geological data and which is reasonably anticipated to contain at least one reservoir of oil, gas or other hydrocarbons.

PROVED RESERVES. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).

SHUT-IN WELL. A well which is capable of producing oil or gas but which is temporarily not producing due to mechanical problems or a lack of market for the well's oil or gas.

UNDEVELOPED ACREAGE. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. Undeveloped acreage should not be confused with undrilled acreage which is "Held by Production" under the terms of a lease.

WORKING INTEREST. A percentage of ownership in an oil and gas lease granting its owner the right to explore, drill and produce oil and gas from a tract of property. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well. After royalties are paid, the working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of the working interest owned.

AVAILABLE INFORMATION

Diversified is subject to the requirements of the Securities and Exchange Act of 1934 and is required to file reports and other information with the Securities and Exchange Commission.  Copies of any such reports and other information filed by Diversified can be read and copied at the Commission’s Public Reference Room a t 100 F Street, N.E., Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the Commission at 1-800-SEC-0330.  The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding public companies.  The address of the site is http://www.sec.gov.

33

NATURAL RESOURCE GROUP, INC.

FINANCIAL STATEMENTS

FOR THE YEARS ENDED OCTOBER 31, 2013 and 2012

34

TABLE OF CONTENTS

	Page
Reports of Independent Registered Public Accounting Firms	F-1 & 2
Financial Statements:
Balance Sheets	F-3
Statements of Operations	F-4
Statement of Changes in Stockholders’ Equity	F-5
Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

35

To the Board of Directors and Stockholders of

Natural Resources Group, Inc.

Littleton, Colorado

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying balance sheet of Natural Resources Group, Inc. as of October 31, 2013, 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 Natural Resources Group, Inc. as of October 31, 2013, and the results of its operations and its 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 incurred significant losses from operations.  This factor raises 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/ Kingery & Crouse, P.A.

Certified Public Accountants

Tampa, Florida

May 15, 2014

F - 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Natural Resources Group, Inc.

Littleton, Colorado

We have audited the balance sheet of Natural Resources Group, Inc. (the "Company") as of October 31, 2012, and the related statements of operations, 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 the 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. An audit 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 audits provide a reasonable basis for our opinion.

In our opinion, the financial statements present fairly, in all material respects, the financial position of Natural Resources Group, Inc. as of October 31, 2012, and the results of their operations and their 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, the Company has losses from continuing operations and has a working capital deficit. These factors raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ MaloneBailey, LLP

www.malone-bailey.com

Houston, Texas

November 21, 2013

F - 2

Natural Resource Group, Inc.

BALANCE SHEETS

	October 31,			October 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash	$	69,433		$	1,051
Accounts receivable, trade		32,378			14,281
Prepaid expenses		8,870			5,703
Total current assets		110,681			21,035
LONG-LIVED ASSETS
Property and Equipment, net of accumulated depreciation
of $4,111 and $1,494		39,392			2,632
Oil and gas properties - proved (successful efforts method)
net of accumulated depletion of $56,726 and $41,567		2,604,418			2,607,585
Oil and gas properties - proved undeveloped (successful efforts method)		64,126			-
Total assets	$	2,818,617		$	2,631,252
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	185,251		$	89,017
Accounts payable, related party		130,361			92,295
Current portion of instalment loan		4,692			-
Notes payable		299,379			-
Accrued interest		2,411			4,605
Accrued interest, related party		3,872			8,233
Accrued expenses		109,193			172,013
Total current liabilities		735,159			366,163
LONG TERM LIABILITIES
Long term debt, related party		107,070			139,800
Long term debt, installment loan		13,765			-
Long term debt, other		-			223,386
Asset retirement obligation		222,375			203,889
COMMITMENTS AND CONTINGENT LIABILITIES		-			-
STOCKHOLDERS' EQUITY
Preferred stock, $0.2394 par value  20,000,000 shares authorized:
Series A Convertible, 1,044,101 shares authorized
-0- and 208,820 shares issued and outstanding in 2013 and 2012 respectively		-			49,992
Common stock, $0.0001 par value, 80,000,000 shares authorized,
14,558,151 and 13,093,704 shares issued and outstanding in 2013 and 2012 respectively		1,456			1,309
Additional paid in capital		4,747,245			3,484,763
Accumulated deficit		(3,008,453	)		(1,838,050	)
Total stockholders' equity		1,740,248			1,698,014
Total liabilities and stockholders' equity	$	2,818,617		$	2,631,252

See accompanying notes to the financial statements.

F - 3

Natural Resource Group, Inc.
STATEMENTS OF OPERATIONS
	Years Ended
	October 31,			October 31,
	2013			2012
Operating revenues
Oil and gas sales	$	85,808		$	79,104
Consulting fees		10,347			-
		96,155			79,104
Operating expenses
Exploration costs, including dry holes		69,878			69,718
Lease operating expenses		189,212			117,357
General and administrative		494,845			497,258
Depreciation expense		7,641			1,148
Depletion expense		13,800			25,155
Accretion expense		20,800			19,245
Impairment and abandonments		-			120,798
Total operating expenses		796,176			850,679
(Loss) from operations		(700,021	)		(771,575	)
Other income (expense)
Loss on debt extinguishment		(330,638	)		-
Loss on disposition of assets		(13,158	)		-
Interest expense		(126,586	)		(70,644	)
Other income (expense), net		(470,382	)		(70,644	)
Net (loss)	$	(1,170,403	)	$	(842,219	)
Net (loss) per common share
Basic and diluted	$	(0.09	)	$	(0.06	)
Weighted average shares outstanding
Basic and diluted		13,684,623			12,966,006

See accompanying notes to the financial statements.

F - 4

Natural Resource Group, Inc.

STATEMENT OF STOCKHOLDERS' EQUITY

	Preferred Stock $.2394 Par Value						Common Stock $.0001 Par Value				Additional Paid-in			Accumulated
	Shares			Amount			Shares		Amount		Capital			Deficit			Total
Balance October 31, 2011		208,820		$	49,992			12,743,704	$	1,274	$	3,134,798		$	(995,831	)	$	2,190,233
Common stock issued for cash		-			-			350,000		35		349,965			-			350,000
Net (loss) for the year		-			-			-		-		-			(842,219	)		(842,219	)
Balance October 31, 2012		208,820			49,992			13,093,704		1,309		3,484,763			(1,838,050	)		1,698,014
Conversion of preferred stock to common		(208,820	)		(49,992	)		208,820		21		49,971			-			-
Conversion of debt for common stock		-			-			395,877		40		395,837			-			395,877
Common stock issued for cash								859,750		86		859,674			-			859,760
Common stock issuance costs												(43,000	)		-			(43,000	)
Net loss for period															(1,170,403	)		(1,170,403	)
Balance October 31, 2013		-		$	-			14,558,151	$	1,456	$	4,747,245		$	(3,008,453	)	$	1,740,248

See accompanying notes to the financial statements.

F - 5

STATEMENTS OF CASH FLOWS

	Years Ended
	October 31,			October 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)	$	(1,170,403	)	$	(842,219	)
Adjustments to reconcile net (loss) to net cash (used in) operating activities:
Impairment and abandonments		-			120,798
Depreciation expense		7,641			1,148
Depletion expense		13,800			25,155
Accretion expense		20,800			19,245
Amortization of discount on notes payable		75,993			41,090
Loss on debt extinguishment		330,638			-
Loss on sale of assets		13,158			-
(Increase) decrease in assets:
Accounts receivable, trade		(18,097	)		(5,552	)
Prepaid expense		(3,167	)		(5,703	)
Increase (decrease) in liabilities:
Accounts payable		96,234			75,125
Accounts payable - related parties		38,066			51,384
Accrued expenses		(46,974	)		68,361
Net cash (used in) operating activities		(642,311	)		(451,168	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		65,583			-
Cash paid for oil and gas properties		(240,965	)		(251,581	)
Cash paid for purchase of property and equipment		(19,412	)		(3,122	)
Net cash (used in) investing activities		(194,794	)		(254,703	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock		859,760			350,000
Payments on related party notes payable		(32,730	)		(28,957	)
Proceeds from notes payable		79,965			320,000
Payments on notes payable		(1,508	)		(1,105	)
Net cash provided by financing activities		905,487			639,938
INCREASE (DECREASE) IN CASH		68,382			(65,933	)
BEGINNING BALANCE		1,051			66,984
ENDING BALANCE	$	69,433		$	1,051
Cash paid for income taxes	$	-		$	-
Cash paid for interest	$	-		$	16,232
Supplemental schedule of non-cash investing and
financing activities:
Assignment of net profits interest in note payable agreement	$	-		$	136,599
Conversion of preferred stock to common stock	$	49,992		$	-
Conversion of debt for common stock	$	395,877		$	-
Acquisition of vehicle with note	$	19,965		$	-

See accompanying notes to the financial statements.

F - 6

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

1.  Business Description and Summary of Significant Accounting Policies

Organization

Natural Resource Group, Inc. (or the "Company") was incorporated under the laws of Colorado on October 17, 2000. The Company was inactive until May 2010 when it commenced operations as an oil and gas exploration company operating primarily in Colorado. The Company was considered to be in the development stage until December 2010 when it acquired 4 producing oil and gas wells and approximately 4,600 acres in the Garcia field located in south eastern Colorado together with three producing oil and gas wells in the Denver Julesburg Basin.

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 aggregating $3,008,453 and has negative working capital of $624,478 at October 31, 2013.  As of October 31, 2013, 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 operation 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 specific identification method. The Company did not record any allowance for uncollectible receivables in 2013 or 2012.

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.

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.

F - 7

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

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 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 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 and gas is sold. Revenue from the purchase, transportation, and sale of natural gas is recognized upon completion of the sale and when transported volumes are delivered. We recognize revenue related to gas balancing agreements based on the sales method. Our net imbalance position at October 31, 2013 and 2012 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.

Accounting for Oil and Gas Activities

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

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

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

F - 8

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

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 $69,878 and $69,718 for the years ended October 31, 2013 and 2012, 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 and included in our DD&A expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset.

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.

F - 9

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

Impairment of Long Lived Assets

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

The Company recorded proved property impairment in the amount of $-0- in the year ended October 31, 2013. The Company recorded abandonments of unproved property of $120,800 in the year ended October 31, 2012.

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.

Major Customers

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%.

For the year ended October 31, 2012, Customer A accounted for approximately 19% of revenue, Customer B accounted for approximately 26% and Customer C accounted for approximately 55%.

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 accounting pronouncements which management believes will have a material effect on the Company’s financial statements.

F - 10

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

2. Oil and gas properties

Oil and gas properties consist of the following:

	October 31, 2013			October 31, 2012
Proved oil and gas properties	$	177,132		$	158,781
Wells in progress		120,133			101,064
Proved undeveloped oil and gas leaseholds		2,363,879			2,389,307
		2,661,144			2,649,152
Less accumulated depletion		(56,726	)		(41,567	)
Net oil and gas properties		2,604,418			2,607,585
Undeveloped oil and gas leasholds	$	64,126		$	-

Total depletion of oil and gas properties amounted to $13,800 and $25,155 for the years ended October 31, 2013 and 2012 respectively.  The Company recorded an abandonment of $ 0 and $120,798, respectively, for the years ended October 31, 2013 and 2012 related to the abandonment of certain leaseholds during the year.

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 maker of the promissory note 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, 2013, 248,895 had been advanced to the Company. In consideration of making the promissory note, 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

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.  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, 2013 with interest accrued in the amount of $3,872.

F - 11

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

5.  Long-term Debt

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, 2014.  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 terms provide for an initial draw of $150,000 with the potential for two subsequent draws of $100,000 each. The Company has drawn $250,000 on the facility and the balance at October 31, 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 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 $75,993 and$41,090 for the years ended October 31, 2013 and 2012 respectively. The ending balance of the debt discount at October 31, 2013 was $19,513.   The company reviewed the conversion feature for beneficial conversion features and embedded derivatives, and determined that neither applied.

Convertible Promissory Note—On May 18, 2012 the Company entered into a $70,000 convertible promissory note bearing interest at 10%, due May 31, 2014. The note is collateralized by a second priority deed of trust on all the wells, equipment and approximately 4,600 acres of oil and gas leasehold interests in the Garcia Field. The lender has the right to convert the principal balance to a 2% working interest in the collateral or 70,000 shares of the Company’s $0.0001 par value common stock. In the event the principal is less than $70,000, the conversion 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 reviewed the conversion feature for beneficial conversion features and embedded derivatives, and determined that neither applied.

Installment Loan—the Company entered into an installment loan on July 4, 2013 bearing interest of 5.39%. The loan is payable in monthly installments of $464 over 48 months commencing August 4, 2013.  The loan is collateralized by a vehicle.

The following summarizes the notes payable:

	2013			2012
Convertible promissory note	$	248,895		$	248,895
Debt Discount, net of amortization		(19,516	)		(95,509	)
Convertible promissory note		70,000			70,000
Installment loan		18,457			-
		317,836			223,386
Current portion		(304,071	)		-
	$	13,765		$	223,386

6.  Asset Retirement Obligation

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

	2013			2012
Beginning asset retirement obligation	$	203,889		$	184,644
Liabilities incurred		-			-
Liabilities settled					-
Accretion expense		20,800			19,245
Revision to estimated cash flows		(2,314	)		-
Ending asset retirement obligation	$	222,375		$	203,889

F - 12

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

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, 2013 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 38.95% 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, 2013 and 2012 were:

	2013			2012
Deferred tax assets:
Net operating loss carry forwards	$	747,714		$	716,600
Deferred tax liability:
Property and equipment, geologic  and geophysical		(41,375	)		(56,200	)
		706,339			660,400
Less valuation allowance		(706,339	)		(660,400	)
	$	-		$	-

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, 2013, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $1,967,200, which will begin expiring in 2030.

The following table shows the reconciliation of the Company’s effective tax rate to the expected federal tax rate for the years ended October 31, 2013 and 2012:

Statutory U.S. federal rate	34	%
State income taxes	5	%
	39	%
Net operating loss	-39	%
	0	%

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 for the last 3 fiscal years are subject to audit by taxing authorities.

8.  Stockholder’s Equity

Series A Convertible Preferred Stock—On October 1, 2010 we designated 1,044,101 shares of the 20,000,000 $0.2394 preferred shares as Series A and issued 208,820 shares on October 18, 2010 in exchange for $50,000. The shares are convertible to our $0.0001 par value common stock on a one to one basis. If, 36 months after October 1, 2010, the Series A Preferred Shares have not been converted to Common Shares, each share of the Series A Preferred Stock will automatically be converted to Common Stock. The Series A Preferred has preference to the holders of shares of any class or series of stock of the Company ranking junior to the Series A Preferred Stock and shall be entitled to receive, when, as and if declared by the Board of Directors out of funds legally available for the purpose, in amount per share to be determined by the Board of Directors. No dividends of any kind shall be mandatory. The holders of the Series A Preferred Stock shall be entitled to one vote per share on all matters submitted to a vote of the stockholders of the Company. The Series A Preferred Stock is entitled to one vote per share at all elections of directors. Voting shall not be cumulative and the holder may not cast all of such votes for a single director, but must distribute them among the number to vote for.  The preferred stock was converted to 208,820 shares of $0.0001 par value common stock on May 20, 2013.

F - 13

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

Common Stock—The Company has 80,000,000 shares of $0.0001 par value common stock authorized.

The Company issued 350,000 shares of Common Stock during the year ended October 31, 2012 in exchange for cash in the amount of $350,000.

The Company issued 859,750 shares of Common Stock in exchange for cash in the amount of $859,760. In addition, 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.

9.  Commitments and Contingent Liabilities

Legal

We are 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 the date hereof.

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 the date hereof.

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 compensation in the aggregate amount of $150,000 per annum.  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 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%; 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. The Operations Manager may be granted royalties pursuant to the royalty program.

The Company has no long term lease obligations.

F - 14

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

10.  Related Parties

The Company executed an office lease for office space in Littleton, Colorado, with Spotswood Properties, LLC, a Colorado limited liability company (“Spotswood”), and an affiliate of the president, effective January 1, 2009, for a three-year term. Commencing July 1, 2010 the Company entered into a new lease for 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 $32,000 and $32,000 in fiscal years 2013 and 2012, respectively.

The Company paid $23,822 and $43,116, in fiscal years 2013 and 2012respectively, 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 $60,730 to a director for financial public relations consulting in fiscal 2013.

The Company paid $7,072 to a shareholder for financial consulting in fiscal 2012.

11.  Subsequent Events

In November 2013, the Company entered into an agreement to exchange securities with Diversified Resources, Inc.  whereby the shareholders of the Company received 14,558,151 shares of Diversified Resources, Inc.’s $0.001 par value common shares.  The exchange was consummated in November 21, 2013.

Subsequent to October 31, 2013, the Company sold 743,750 shares of common stock for cash of $340,000.

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

Capitalized costs relating to oil and gas producing activities:

	October 31, 2013			October 31, 2012
Proved oil and gas properties	$	177,132		$	158,781
Wells in progress		120,133			101,064
Proved undeveloped oil and gas leaseholds		2,363,879			2,389,307
		2,661,144			2,649,152
Less accumulated depletion		(56,726	)		(41,567	)
Net oil and gas properties		2,604,418			2,607,585
Undeveloped oil and gas leasholds	$	64,126		$	-

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

	2013		2012
Acquisition of properties:
Proved	$	-	$	-
Proved undeveloped		64,126		-
Development costs		176,839		250,991
Exploration costs		69,878		69,718
Total	$	310,843	$	320,709

F - 15

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

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):

	2013			2012
Operating Revenues	$	85,808		$	79,104
Costs & expenses:
Exploration		69,878			69,718
Lease operating expenses		189,212			117,357
Depletion		13,800			25,155
Total costs & expenses		272,890			212,230
Income (loss) before income taxes		(187,082	)		(133,126	)
Income tax (expense) benefit		72,962			51,919
Results of operations	$	(114,120	)	$	(81,207	)

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, 2013 and 2012:

					Gallons
	Oil (Bbl)		Gas (Mcf)		NG Liquid
Developed at October 31, 2012		5,334		28,667		-
Proved undeveloped at October 31, 2012		-		560,372		5,724,418
Balance, October 31, 2012		5,334		589,039		5,724,418
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

Notable changes in our reserves are summarized as follows:

We increased our proved developed  reserves by 1,387 Bbls and 14,961 Mcf by reentering a well in an existing lease in the DJ area.

Increase in proved undeveloped  reserves arises from the acquisition of a lease in the DJ area which caused an  increase in the barrels of oil of 24,077 and 18,873 Mcf of natural gas.

Our estimated quantity of gallons of NG liquids decreased because of revisions in estimated recoveries.

F - 16

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

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:

	2013			2012
Future cash inflows	$	9,295,085		$	6,703,766
Future production costs		(2,987,829	)		(1,674,164	)
Future development costs		(4,175,000	)		(3,478,125	)
Future income tax expense		(831,580	)		(605,076	)
Future net cash flows		1,300,676			946,401
10% annual discount for estimated timing of cash flows		(990,662	)		(866,004	)
Standardized measure of discounted future net cash flows		310,014			80,397

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. Estimates of the Company’s reserves are based on realized prices.

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, 2012 (Average)	$	92.94	$	3.04	$	0.77
October 31, 2013 (Average)	$	86.79	$	4.87	$	0.81

F - 17

NATURAL RESOURCE GROUP, INC

Notes to Financial Statements

October 31, 2013 and 2012

Principal changes in the Standardized Measure for the years ended October 31, 2013 and 2012 were as follows:

	2013			2012
Standardized measure, beginning of year	$	80,397		$	2,579,407
Purchase of reserves in place		-			-
Purchase of proved undeveloped reserves		725,657			-
Sale and transfers, net of production costs		103,404			38,253
Net changes in prices and production costs		(726,938	)		(2,990,267	)
Extensions, discoveries, and improved recovery		135,610			-
Changes in estimated future development costs		(696,875	)		(192,936	)
Development costs incurred during the period		176,839			250,991
Revision of quantity estimates		110,446			(163,262	)
Accretion of discount		(124,658	)		422,854
Net change in income taxes		226,504			1,597,729
Changes in timing and other		299,628			(1,462,372	)
Standardized measure, end of year	$	310,014		$	80,397

F - 18

NATURAL RESOURCE GROUP, INC.

PRO FORMA FINANCIAL STATEMENTS

F - 19

Diversified Resources, Inc.

UNAUDITED PRO FORMA BALANCE SHEET

			October, 31
	October 31,		2013								2013
	2013		Natural								October 31,
	Diversified		Resource								2013
	Resources, Inc.		Group, Inc.		Notes			Adjustments			Pro Forma
ASSETS
CURRENT ASSETS
Cash	$	-	$	69,433							$	69,433
Accounts receivable, trade		-		32,378								32,378
Prepaid expenses		-		8,870								8,870
Total current assets		-		110,681								110,681
LONG-LIVED ASSETS
Property and Equipment, net of accumulated depreciation of $4,111 and $1,494		-		39,392								39,392
Oil and gas properties - proved (successful efforts method)												-
net of accumulated depletion of $56,726 and $41,567		-		2,604,418								2,604,418
Oil and gas properties - proved undeveloped (successful efforts method)		-		64,126								64,126
	$	-	$	2,818,617							$	2,818,617
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	8,928	$	185,251		(3	)	$	(8,928	)	$	185,251
Accounts payable, related party				130,361								130,361
Current portion of instalment loan				4,692								4,692
Notes payable				299,379								299,379
Shareholder loan		14,010		-		(3	)		(14,010	)		-
Accrued interest				2,411								2,411
Accrued interest, related party				3,872								3,872
Accrued expenses				109,193								109,193
Mineral lease payable		274,792		-		(3	)		(274,792	)		-
Total current liabilities		297,730		735,159								735,159
LONG TERM LIABILITIES
Long term debt, related party		-		107,070								107,070
Long term debt, installment loan		-		13,765								13,765
Asset retirement obligation		-		222,375								222,375

F - 20

Diversified Resources, Inc.

UNAUDITED PRO FORMA BALANCE SHEET

(Continued)

				October, 31
	October 31,			2013									2013
	2013			Natural									October 31,
	Diversified			Resource									2013
	Resources, Inc.			Group, Inc.			Notes			Adjustments			Pro Forma
STOCKHOLDERS' EQUITY
Preferred stock		-			-									-
Common stock		5,250			1,456			(1	)		(1,456	)		17,430
								(1	)		(2,378	)
								(2	)		14,558
Additional paid in capital		74,750			4,747,245			(3	)		297,730			4,731,271
								(1	)		3,834
								(2	)		(392,288	)
Deficit accumulated in the development stage		(377,730	)		-			(2	)		377,730			-
Accumulated (deficit)					(3,008,453	)								(3,008,453	)
		(297,730	)		1,740,248									1,740,248
	$	-		$	2,818,617								$	2,818,617

See the accompanying summary and notes.

F - 21

Diversified Resources, Inc.
UNAUDITED PRO FORMA STATEMENTS OF OPERATIONS
For the Fiscal Year Ended October 31 , 2013
				Natural
	Diversified			Resource			Pro forma
	Resources, Inc.			Group, Inc.			Adjustments	Pro Forma
Operating revenues	$	-		$	96,155			$	96,155
Operating expenses
Exploration costs, including dry holes					69,878				69,878
Lease operating expenses					189,212				189,212
General and administrative		86,581			494,845				581,426
Depreciation expense					7,641				7,641
Depletion expense					13,800				13,800
Accretion expense					20,800				20,800
Total operating expenses		86,581			796,176				882,757
(Loss) from operations		(86,581	)		(700,021	)			(786,602	)
Other income (expense)
Loss on debt extinguishment		-			(330,638	)			(330,638	)
Loss on disposition of assets		-			(13,158	)			(13,158	)
Interest expense		-			(126,586	)			(126,586	)
Other income (expense), net		-			(470,382	)			(470,382	)
(Loss) before income taxes		(86,581	)		(1,170,403	)			(1,256,984	)
Income taxes
Current		-			-				-
Deferred		-			-				-
		-			-				-
Net Income  (loss)	$	(86,581	)	$	(1,170,403	)		$	(1,256,984	)
Net (loss) per common share
Basic and diluted								$	(0.07	)
Weighted average shares outstanding
Basic and diluted									17,430,117

See the accompanying summary and notes.

F - 22

Diversified Resources, Inc.

PRO FORMA SUMMARY AND ADJUSTMENTS TO THE BALANCE SHEET AND STATEMENTS OF OPERATIONS

For the Fiscal Year Ended October 31 , 2013

Summary

The accompanying pro forma financial statements include the balance sheet as of October 31, 2013, and the statement of operations for the year then ended.

These financial statements reflect the acquisition by Diversified Resources, Inc. (“DRI”) of Natural Resources Group, Inc. (“NRG”).

In November 2013, DRI entered into an agreement to exchange securities with NRG, an oil and gas exploration company, whereby the shareholders of NRG received 14,558,151 shares of DRI’s $0.001 par value common shares. The President of DRI also returned 2,680,033 shares of DRI’s common stock to DRI for nominal consideration.  The shares purchased from the President were returned to the status of authorized but unissued shares. Additionally, a former officer and director of DRI assumed all of the debts of DRI at the date of the exchange. The exchange was consummated on November 20, 2013.

The transaction was accounted for as a reverse acquisition whereby NRG is was considered to be the accounting acquirer.

Pro forma adjustments

1.	Issuance of Common Shares:
	To reflect the issuance of 14,558,150 shares of Diversified Resources, Inc.. (“DRI”) in exchange for 100% of the outstanding shares of Natural Resources Group, Inc. “(NRG”) and the cancellation of 2,680,033 DRI common shares.
2.	To reclassify the par value of common shares and eliminate the accumulated deficit of DRI at October 31, 2013.
3.	To reflect the assumption of liabilities of DRI by the DRI president in connection with the stock purchase agreement. A former officer and director of DRI agreed to assume all of DRI's liabilities (which were approximately $58,000) as of November 21, 2013, the date of the acquisition of NRG. Notwithstanding the above, former officer and director did not assume any liabilities of NRG. The actual liabilities assumed by the former officer and director differ from the liabilities shown on pro forma balance sheet as of October 31, 2013 due to the mineral lease being recorded for financial reporting purposes in the amount of $274,792 in accordance with ASC Topic 840, the application of which, characterized the lease as an operating lease. Accordingly, the lease obligation was recorded at the average annual amortization of total lease payments over the life of the lease. The actual mineral lease obligation assumed by the former officer and director was $35,000, a difference of $239,792.

F - 23

Item 3.02.   Unregistered Sales of Equity Securities

The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 with respect to the shares issued to the shareholders of Natural Resource Group.  See Item 2.01 of this report.

In December 2010, the Company issued a promissory note in the principal amount of $360,000.  The note bears interest at 10% per year and has a maturity date of December 11, 2015.

On January 12, 2012 the Company issued a promissory note bearing interest at 10% per year and due on July 17, 2014.  The note is collateralized by a first priority deed of trust covering approximately 4,600 acres of oil and gas leasehold interests in the Garcia oil and gas field, together with existing wells and equipment in the field. The lender has the right to convert the principal of the note into a 10% working interest in the collateral, as well as a 10% working interest in all wells owned by the Company in the Garcia Field in which the lender does not have a net profits interest.

On May 18, 2012 the Company issued a $70,000 promissory note bearing interest at 10% and due on May 31, 2014. The note is collateralized by a second priority deed of trust on all wells and equipment, as well as approximately 4,600 acres of oil and gas leasehold interests, in the Garcia oil and gas field. The lender has the right to convert the principal of the note into a 2% working interest in the collateral or 70,000 shares of the Company’s common stock.

The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 with respect to the issuance of the notes described above.

Item 5.01.   Changes in Control of Registrant

See Item 2.01 of this report.

Item 5.02.   Departure of Directors or Principal Officers; Election of Directors; Appointment of Principal Officers

See Item 2.01 of this report.

Item 5.06.   Change in Shell Company Status

See Item 2.01 of this report.

Item 5.07.   Submission of Matters to a Vote of Security Holders

On November 21, 2013 a shareholder owning 3,000,000 shares of the Company’s common stock (approximately 57% of the Company’s outstanding shares) approved, by written consent, the Plan of Share Exchange with Natural Resource Group, Inc.

Information regarding the specific terms of the share exchange can be found in the Item 2 of this report.

36

Item 9.01.   Financial Statements and Exhibits

a) Attached

b) Attached

c) Exhibits

Exhibit Number	Description
2	Agreement to Exchange Securities between Natural Resource Group, Inc. and Diversified Resources, Inc. *
3.1	Articles of Incorporation *
3.2	Bylaws *
10.1	Participation Agreement/Net Profits Interest (1) *
10.2	Note Payable – Energy Oil and Gas, Inc. *
10.3	Convertible Promissory Note - $350,000 (1) *
10.3.1	Extension to Note Payable ($350,000)
10.4	Convertible Promissory Note - $70,000 (1) *
10.5	Employment Agreement – Paul Laird
10.6	Employment Agreement – Duane Bacon
99.1	Reserve Report – Garcia Field
99.2	Reserve Report – D-J Basin

* Previously filed.

(1) Certain exhibits and schedules to these agreements have been omitted.  The Company agrees to supplementally provide the Commission, upon request, with any omitted schedule or exhibit.

37

SIGNATURES

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

Date: May 19, 2014	DIVERSIFIED RESOURCES, INC.
	By:	/s/ Paul Laird
		Paul Laird, President

38