Attached files
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
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)
[] Written communications pursuant to Rule 425 under the Securities Act (17 CFR
230.425)
[] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR
240.14a-12)
[] Pre-commencement communications pursuant to Rule 14d-2(b) under the
Exchange Act (17 CFR 240.14d-2(b))
[] Pre-commencement communications pursuant to Rule 13e-14(c) under the
Exchange Act (17 CFR 240.13e-4(c))
1
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:
o the sale prices of crude oil;
o the amount of production from oil wells in which the Company has an
interest;
o lease operating expenses;
o international conflict or acts of terrorism; and
o 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 14,558,150 shares of the Diversified's common stock (the
"Acquisition").
2
In connection with the Acquisition:
o Paul Laird , Duane Bacon, Roger May, and Albert McMullin were
appointed officers and/or directors of Diversified;
o Philip F. Grey resigned as an officer of Diversified;
o Mr. Grey sold 2,680,033 shares of the Company'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;
o the former shareholders of the Company now own 85% of Diversified; and
o 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 July 31, 2013, the
principal amount of this note was $78,000.
Included as part of the acquisition were:
Garcia Field
o leases covering 4,600 gross (4,600 net) acres,
o four wells which produce natural gas and naturals gas liquids;
o a refrigeration/compression plant which separates natural gas liquids
from gas produced from the four wells; and
o one injection well;
Denver-Julesburg Basin
o leases covering 1,400 gross (1,400 net) acres,
o three shut-in wells which need to be recompleted; and
o three producing oil and gas wells.
Subsequent to December 2010 leases, covering 160 acres in the Garcia Field
were sold and leases covering 960 acres in the Garcia Field expired.
The Company is the operator of its wells in the Garcia Field and the
Denver-Julesberg Basin.
3
Garcia Field
The Company has a 100% working interest (80% net revenue interest) in oil
and gas leases covering 4,600 acres in the Garcia Field.
The Garcia Field is located in Las Animas County approximately 10 miles
from Trinidad, Colorado. The Garcia Field was first discovered in 1940 when the
Maldonado #1, produced 500 mcf per day of gas from the Niobrara formation. A
stripping plant separated natural gas liquids from the gas and was operational
for eight years until the Maldonado #1 was plugged in 1948. Between 1978 and
1982 twenty wells were drilled, tested for initial production and shut-in. Since
there was no natural gas transportation line in the area, the wells were never
produced. Additionally, until Energy Oil and Gas acquired the field in 2005 no
natural gas liquids were produced commercially. In 2003, the entire field was
force plugged as required by the state of Colorado, except for three wells which
Energy Oil and Gas acquired from the state. Energy Oil and Gas subsequently
drilled two additional wells and installed a new separation plant. Four of the
five wells 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.
As of the date of this report, 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.
4
Denver/Julesburg Basin
The Company has a 100% working interest (80% net revenue interest) in oil
and gas leases covering 1400 acres in the Denver/Julesburg ("D-J") Basin.
The reservoir rocks in the D-J Basin are Cretaceous sandstones, shales, and
limestones deposited under marine conditions in the Western Interior Seaway. The
oil and gas is contained within Cretaceous formations in the deepest part of the
Basin, where the rocks were subject to enough heat and pressure to generate oil
and gas from organic material in the rock. Most of the producing formations are
considered "tight," having low natural permeability.
The D-J Basin was one of the first oil and gas fields where extensive
hydraulic fracturing was performed routinely and successfully on thousands of
wells.
In 2009, the US Energy Information Administration listed the Wattenberg
Field (a primary field within the D-J Basin) as the 10th largest gas field in
the United States in terms of remaining proved gas reserves, and 13th in
remaining proved oil/condensate reserves.
Major operators in the field include Noble Energy, Anadarko Petroleum
Corporation, Continental, Whiting Petroleum, and Encana.
As of October 31, 2013 the three 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 October 31, 2014, the Company plans to:
o recomplete the three shut-in wells acquired from Energy Oil and Gas,
at a cost of approximately $130,000 per well;
o 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
o 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 $800,000.
5
The following table shows net production of oil and gas, average sales
prices and average production costs for the periods indicated:
Nine Months
Ended Years Ended October 31,
-----------------------------------
July 31, 2013 2012 2011 2010
------------- ---- ---- ----
Production:
Oil (Bbls) 205 417 206 --
Gas (Mcf) 2,330 5,015 4,571 --
Natural Gas Liquids
(gallons) 21,937 20,375 28,359 --
Average sales price:
Oil ($/Bbl(1)) $ 86.20 $ 92.94 $ 91.57
Gas ($/Mcf(2)) $ 3.42 $ 3.04 $ 4.76 --
Nat.Gas Liquids ($/gal) $ 0.81 $ 0.77 $ 1.36
Average production
cost per BOE(3) $ 189.85 $ 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.
6
October 31,
2013 2012 2011
------------ ----------------- --------------
Gross Net Gross Net Gross Net
Development Wells:
Productive
-- -- 1 1 -- --
Nonproductive -- -- -- -- -- --
Productive Wells:
Productive -- -- -- -- -- --
Nonproductive -- -- -- -- -- --
As of October 31, 2013 the Company was not drilling, completing or
reworking any oil or gas wells.
The following table shows, as of October 31, 2013, 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 3 3160 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 October 31, 2013, 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.
7
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,
2012, 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, 2012 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.
Oil Gas NGL
(Bbls) (Mcf) Gallons
------ ----- -------
Proved Developed:
Producing 5,334 28,667 --
Non-Producing -- -- --
Proved Undeveloped -- 560,372 5,724,418
"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, 2012. 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 $ 6,703,766
Deductions (including estimated taxes) $ 5,757,365
Future net cash flow $ 946,401
Discounted future net cash flow $ 80,397
8
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, 2012. 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, 2012. 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.
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, 2012 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
9
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.
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 and
Wattenberg fields 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.
10
The Company may also:
o 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;
o purchase producing oil properties;
o 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
o 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.
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
11
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 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
12
and imports of oil, the availability of other sources of energy, fluctuations in
seasonal supply and demand, and governmental regulation. In addition, there is
always the possibility that new legislation may be enacted which would impose
price controls or additional excise taxes upon crude oil. As of October 31,
2013, 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.
Employees and Offices
As of October 31, 2013, the Company had 4 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.
The Company may suffer losses in future periods. The Company suffered net
losses of $(842,219) and $(934,380), respectively, during the two years ended
October 31, 2012 and a net loss of $(1,033,393) during the nine months ended
July 31, 2013. The Company had negative working capital in the amount of
$502,568 at July 31, 2013.
13
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.
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
14
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.
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
15
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 three months ended October 31, 2013.
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
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.
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
16
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 14,558,150 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 in the Company's Statement of Operations for the year
ended October 31, 2012 and the nine months ended July 31, 2013, as compared to
the same periods in the prior year, are discussed below:
October 31, 2012
Increase (I)
Item or Decrease (D) Reason
---- --------------- ------
Operating revenues D Decrease in consulting revenue
of $65,698 offset by an increase
in oil and gas revenues of
$3,584.
General and administrative
Expenses D Decrease in officer compensation
offset by increases in
consulting and other fees.
Abandonments D The Company abandoned properties
in fiscal 2012.
17
July 31, 2013
Increase (I)
Item or Decrease (D) Reason
---- --------------- ------
Operating revenues D Decreased oil and gas production
Operating expenses I Increased lease operating
expenses as a result of new
activity in the Garcia Field.
Loss on debt
extinguishment I Isolated transaction during the
current nine month period.
Loss on disposition
of assets I Sale of equipment originally
purchased for the Garcia Field
which did not perform up to
expectations and was sold at a
loss.
Interest expense I Increase in
outstanding debt during the
current nine month period.
During the nine months ended July 31, 2013, the Company produced 205 bbls
of oil, 21,937 gallons of natural gas liquids, and 2,330 mcf of natural gas.
The factors that will most significantly affect future operating results
will be:
o the sale prices of crude oil;
o the amount of production from oil, gas and gas liquids wells in which
the Company has an interest;
o lease operating expenses;
o the availability of drilling rigs, drill pipe and other supplies and
equipment required to drill and complete oil wells; and
o corporate overhead costs.
Revenues will also be significantly affected by the Company's ability to
maintain and increase oil, gas and natural gas liquids production.
Other than the foregoing the Company does not know of any trends, events or
uncertainties that have had, or are reasonably expected to have, a material
impact on revenues or expenses.
18
Liquidity and Capital Resources
The Company's sources and (uses) of funds for the two years ended October
31, 2012 and 2011 are shown below:
Year Ended Year Ended
October 31, 2012 October 31, 2011
---------------- ----------------
Cash used in operations $(451,168) $(422,371)
Drilling and completion costs $(251,581) $ (2,710)
Purchase of furniture and equipment $ (3,122) $ --
Sale of common stock $ 350,000 $ 635,000
Loans (net of repayments) $ 289,938 $(191,243)
The Company's sources and (uses) of funds for the nine months ended July
31, 2013 and July 31, 2012 are shown below:
Nine Months Ended Nine Months Ended
July 31, 2013 July 31, 2012
----------------- -----------------
Cash used in operations $(494,756) $(361,385)
Purchase of oil and gas properties $ (39,237) $(241,629)
Purchase of equipment $ (61,319)
Sale of equipment $ 24,700 --
Sale of common stock $ 742,013 $350,000
Loans (net of repayments) $ 18,521 $289,938
As of October 31, 2013, operating expenses were approximately $41,000 per
month, which amount includes salaries and other corporate overhead, but excludes
lease operating, exploration, depreciation and interest expenses.
See Notes 4 and 5 to the October 31, 2012 financial statements, and Notes 2
and 3 to the July 31, 2013 financial statements, included as part of this
report, for information concerning the Company's outstanding loans.
19
The Company estimates its capital requirements for the twelve months ending
October 31, 2014 are as follows:
o Drilling, completing, and fracturing wells $ 1,740,000
o Install gathering line (1) $ 150,000
o 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.
20
Other than as disclosed above, the Company does not know of any:
o 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
o Significant changes in expected sources and uses of cash.
Contractual Obligations
The Company's material future contractual obligations as of October 31,
2012 were as follows:
Description Total 2014 2015 2016 Thereafter
----------- ----- ---- ---- ---- ----------
Repayment of loans $458,696 $318,890 -- $139,800 --
The Company's material future contractual obligations as of July 31, 2013
were as follows:
Description Total 2014 2015 2016 Thereafter
----------- ----- ---- ---- ---- ----------
Repayment of loans $417,216 $318,642 $ 82,659 $4,918 $10,997
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
Roger May 57 Director
Albert McMullin 56 Director
Philip F. Grey 60 Director
On November 21, 2013 Diversified acquired all of the outstanding shares of
the Company in exchange for 14,558,150 shares of the Diversified's common stock.
21
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 the 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 2000, Mr. Bacon has been the President
of Energy Oil and Gas, Inc. a private exploration and production company located
in Longmont, Colorado.
Roger May was appointed a director of Diversified on November 21, 2013.
Between 2010 and 2013, Mr. May was a director of Natural Resource Group.
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 a senior
vp foucing on enhance oil recovery in California and Texas. He has over 35 years
of experience in the energy field and has worked for Exxon, Atlantic Richfield
and United Gas Pipeline. He has built several oil companies which he
successfully monetized.
Philip F. Grey has been a director of Diversified since July 24, 2012.
Between July 24, 2012 and November 21, 2013, Mr. Grey was Diversified's only
officer. Since 2010, Mr. Grey has been employed as a consultant by Securities
Logistics Legal Group. From March 2008 to 2010, Mr. Grey was employed at
Velocity Capital Advisors, a company he founded, to act as an introducing broker
for futures, commodities and forex business. Prior to 2008, Mr. Grey was Vice
President of Institutional Sales for Accuvest, Inc., a futures and commodities
firm located in southern California.
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
Philip F. Grey Investment banking experience
Philip F. Grey and Albert McMullin are the members of the Company's
compensation committee. The Board of Directors serves as the Company's audit
committee.
22
Mr. McMullin, and Mr. Grey are independent, as that term is defined in
Section 803 A(2) of the NYSE MKT Company Guide. Mr. Grey acts as the Company's
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%
The Company has an employment agreement with Paul Laird. Pursuant to the
agreement, the Company will pay Mr. Laird $12,500 per month. The employment
agreement with Mr. Laird can be terminated at any time by either party without
cause.
23
The Company has an employment agreement with Duane Bacon. Pursuant to the
agreement, the Company will pay Mr. Bacon $5,500 per month. The agreement with
Mr. Bacon is terminable at any time without cause.
Stock Option and Stock Bonus Plans. 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 Arrangement's. 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.
PRINCIPAL SHAREHOLDERS
The following table shows the beneficial ownership of Diversified's common
stock, as of November 21, 2013, and after giving effect to the acquisition of
the Company, by (i) each person whom Diversified knows beneficially owns more
24
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
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.
25
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 nine months ended July 31, 2013, the Company sold 785,000 shares
of its common stock to 22 persons for $785,000 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 July 31, 2013, the Company sold 74,750 shares of its common
stock to four persons for $74,750.
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.
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.
26
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.
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.
27
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
28
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.
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 at 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.
29
DIVERSIFIED RESOURCES, INC.
Financial Statements
NATURAL RESOURCE GROUP, INC.
FINANCIAL STATEMENTS
FOR THE YEAR ENDED OCTOBER 31, 2013 AND 2012
TABLE OF CONTENTS
Page
-----
Report of Independent Registered Public Accounting Firm F-1
Consolidated Financial Statements
Balance Sheets F-2
Statements of Operations F-3
Statement of Changes in Stockholders' Equity F-4
Statements of Cash Flows F-5
Notes to Consolidated Financial Statements F-6
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 sheets of Natural Resources Group, Inc. (the
"Company") as of October 31, 2012 and 2011, and the related statements of
operations, stockholders' equity, and cash flows for each of the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on the financial
statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the 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 2011, and the results of their operations and their cash flows for
each of the years 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-1
Natural Resource Group, Inc.
BALANCE SHEETS
October 31, October 31,
2012 2011
------------ ------------
ASSETS
CURRENT ASSETS
Cash $ 1,051 $ 66,984
Accounts receivable, trade 14,281 8,729
Prepaid expenses 5,703 -
------------ ------------
Total current assets 21,035 75,713
------------ ------------
LONG-LIVED ASSETS
Property and Equipment, net of
accumulated depreciation
of $1,494 and $346 2,632 658
Oil and gas properties - proved
(successful efforts method)
net of accumulated depletion
of $41,567 and $16,412 2,607,585 2,518,558
Oil and gas properties - unproved
(successful efforts method) - 120,000
------------ ------------
Total assets
$ 2,631,252 $ 2,714,929
============ ============
LIABILITIES AND STOCKHOLDERS'
EQUITY
CURRENT LIABILITIES
Accounts payable $ 89,017 $ 13,892
Accounts payable, related party 92,295 47,628
Accrued interest 4,605 -
Accrued interest, related party 8,233 1,516
Accrued expenses 172,013 108,259
------------ ------------
Total current liabilities 366,163 171,295
------------ ------------
LONG TERM LIABILITIES
Long term debt, related party 139,800 168,757
Long term debt 223,386 -
Asset retirement obligation 203,889 184,644
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
208,820 shares issued and
outstanding 49,992 49,992
Common stock, $0.0001 par value,
80,000,000 shares authorized, -
13,093,704 and 12,743,704 shares
issued and outstanding 1,309 1,274
Additional paid in capital 3,484,763 3,134,798
Accumulated deficit (1,838,050) (995,831)
------------ ------------
Total stockholders' equity
1,698,014 2,190,233
------------ ------------
Total liabilities and
stockholders' equity $2,631,252 $2,714,929
============ ============
See accompanying notes to the financial statements.
F-2
Natural Resource Group, Inc.
STATEMENTS OF OPERATIONS
Years Ended
October 31, October 31,
2012 2011
------------------- --------------------
Operating revenues
Oil and gas sales $ 79,104 $ 75,520
Consulting fees - 65,698
------------------- --------------------
79,104 141,218
Operating expenses
Exploration costs, including
dry holes 69,718 57,600
Lease operating expenses 117,357 105,600
General and administrative 497,258 855,992
Depreciation expense 1,148 200
Depletion expense 25,155 16,412
Accretion expense 19,245 14,497
Abandonments 120,798 -
------------------- --------------------
Total operating expenses
850,679 1,050,301
------------------- --------------------
(Loss) from operations (771,575) (909,083)
------------------- --------------------
Other income (expense)
Interest expense (70,644) (25,297)
------------------- --------------------
Other income (expense), net (70,644) (25,297)
------------------- --------------------
Net (loss) $ (842,219) $ (934,380)
=================== ====================
Net (loss) per common share
Basic and diluted $ (0.06) $ (0.08)
=================== ====================
Weighted average shares outstanding
Basic and diluted 12,966,006 12,006,485
=================== ====================
See accompanying notes to the financial statements.
F-3
Natural Resource Group, Inc.
STATEMENTS OF CASH FLOWS
Years Ended
October 31, October 31,
2012 2011
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) (842,219) (934,380)
Adjustments to reconcile net (loss) to net
cash
(used in) operating activities:
Abandonments 120,798 -
Depreciation expense 1,148 200
Depletion expense 25,155 16,412
Accretion expense 19,245 14,497
Amortization of discount on
notes payable 41,090 -
Assignment of net profits
interest - 377,887
(Increase) decrease in assets:
Accounts receivable,
trade (5,552) (8,729)
Prepaid expense (5,703) -
Increase (decrease) in
liabilities:
Accounts payable 75,125 13,892
Accounts payable -
related parties 51,384 (5,409)
Accrued expenses 68,361 103,259
------------ ------------
Net cash (used in) operating
activities (451,168) (422,371)
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for oil and gas properties (251,581) (2,710)
Cash paid for purchase of fixed assets (3,122) -
------------ ------------
Net cash (used in) investing
activities (254,703) (2,710)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock 350,000 635,000
Payments on related party notes payable (28,957) (191,243)
Proceeds from notes payable 320,000 -
Payments on notes payable (1,105) -
------------ ------------
Net cash provided by financing
activities 639,938 443,757
------------ ------------
INCREASE (DECREASE) IN CASH (65,933) 18,676
BEGINNING BALANCE 66,984 48,308
------------ ------------
ENDING BALANCE 1,051 66,984
============ ============
Cash paid for income taxes - -
============ ============
Cash paid for interest
16,232 23,781
============ ============
F-4
Supplemental schedule of non-cash investing and
financing activities:
Assignment of net profits interest
in note payable agreement 136,599 -
Assumption of asset retirement
obligation - 170,147
Issuance of note payable for oil
and gas properties - 360,000
Issuance of common stock for oil and
gas properties - 2,500,000
=========== ============
See accompanying notes to the financial statements.
F-5
Natural Resource Group, Inc.
STATEMENT OF STOCKHOLDERS' EQUITY
(Unaudited)
Preferred Stock Common Stock Additional
$.2394 Par Value $.0001 Par Value Paid-in Accumulated
Shares Amount Shares Amount Capital Deficit Total
--------- ---------------------- ----------- ----------- ----------- -----------
Balance November 1, 2010 208,820 $ 49,992 9,583,704 $ 958 $ 114 $ (61,451) $ (10,387)
Common stock issued
for assets 2,500,000 250 2,499,750 2,500,000
Common stock issued
for cash 660,000 66 659,934 660,000
Less common stock
issuance costs (25,000) (25,000)
Net (loss) for the year - - - - - (934,380) (934,380)
--------- ---------- ---------- ----------- ----------- ----------- -----------
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
========= ====================== =========== =========== =========== ===========
See accompanying notes to the unaudited financial statements.
F-6
NATURAL RESOURCE GROUP, INC
Notes to Financial Statements
October 31, 2012 and 2011
F-7
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 $1,838,050 and has
negative working capital of $345,128 at October 31, 2012. As of October 31,
2012, the Company has limited financial resources until such time that it is
able to generate positive cash flow from operations. 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 they 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 2012 or 2011.
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.
F-7
Concentration of Credit Risk
Financial instruments that potentially subject the Company to
concentrations of credit risk consist primarily of cash equivalents. The Company
places its cash equivalents with a high credit quality financial institution.
The Company periodically maintains cash balances at a commercial bank in excess
of the Federal Deposit Insurance Corporation insurance limit of $250,000.
Stock-based compensation
ASC 718, "Compensation-Stock Compensation" requires recognition in the
financial statements of the cost of employee services received in exchange for
an award of equity instruments over the period the employee is required to
perform the services in exchange for the award (presumptively the vesting
period). We measure the cost of employee services received in exchange for an
award based on the grant-date fair value of the award.
We account for non-employee share-based awards based upon ASC 505-50,
"Equity-Based Payments to Non-Employees." ASC 505-50 requires the costs of goods
and services received in exchange for an award of equity instruments to be
recognized using the fair value of the goods and services or the fair value of
the equity award, whichever is more reliably measurable. The fair value of the
equity award is determined on the measurement date, which is the earlier of the
date that a performance commitment is reached or the date that performance is
complete. Generally, our awards do not entail performance commitments. When an
award vests over time such that performance occurs over multiple reporting
periods, we estimate the fair value of the award as of the end of each reporting
period and recognize an appropriate portion of the cost based on the fair value
on that date. When the award vests, we adjust the cost previously recognized so
that the cost ultimately recognized is equivalent to the fair value on the
vesting date, which is presumed to be the date performance is complete.
We recognize the cost associated with share-based awards that have a graded
vesting schedule on a straight-line basis over the requisite service period of
the entire award.
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, 2012 and
2011 was immaterial.
Consulting Fees
During the year ended October 31, 2011, the Company received Consulting
Fees of $65,698. The Company provided Colorado landman services to a foreign
entity with operations in Colorado. 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.
F-8
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 DD&A 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 is calculated using the unit-of-production method. The reserve base
used to calculate depreciation, depletion and amortization for leasehold
acquisition costs and the cost to acquire proved properties is the sum of proved
developed reserves and proved undeveloped reserves. With respect to lease and
well equipment costs, which include development costs and successful exploration
drilling costs, the reserve base includes only proved developed reserves.
Estimated future dismantlement, restoration and abandonment costs, net of
salvage values, are taken into account.
Proved Property Impairment We review individually significant proved oil
and gas properties and other long-lived assets for impairment at least annually
at year-end, or quarterly when events and circumstances indicate a decline in
the recoverability of the carrying values of such properties, such as a negative
revision of reserves estimates or sustained decrease in commodity prices. We
estimate future cash flows expected in connection with the properties and
compare such future cash flows to the carrying amount of the properties to
determine if the carrying amount is recoverable. When the carrying amount of a
property exceeds its estimated undiscounted future cash flows, the carrying
amount is reduced to estimated fair value. Fair value may be estimated using
comparable market data, a discounted cash flow method, or a combination of the
two. In the discounted cash flow method, estimated future cash flows are based
on management's expectations for the future and include estimates of future oil
and gas production, commodity prices based on published forward commodity price
curves as of the date of the estimate, operating and development costs, and a
risk-adjusted discount rate.
Unproved Property Impairment Our unproved properties consist of leasehold
costs and allocated value to probable and possible reserves from acquisitions.
We assess individually significant unproved properties for impairment on a
quarterly basis and recognize a loss at the time of impairment by providing an
impairment allowance. In determining whether a significant unproved property is
impaired we consider numerous factors including, but not limited to, current
exploration plans, favorable or unfavorable exploration activity on the property
being evaluated and/or adjacent properties, our geologists' evaluation of the
property, and the remaining months in the lease term for the property. During
the year ended October 31, 2012, the company recorded an impairment charge of
$120,798 for the abandonment of a lease.
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 $69,718 and $57,600 for the years ended October 31, 2012 and 2011,
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
F-9
of operations. Subsequent adjustments in the cost estimate are reflected in the
liability and the amounts continue to be amortized over the useful life of the
related long-lived asset.
Net Income (Loss) per Common Share
Basic earnings (loss) per share are calculated by dividing net income
(loss) by the weighted average number of common shares outstanding for the
period. Diluted earnings (loss) per share are calculated by dividing net income
(loss) by the weighted average number of common shares and dilutive common stock
equivalents outstanding. During the periods when they are anti-dilutive, common
stock equivalents, if any, are not considered in the computation.
Property and Equipment
Property and equipment consists of production buildings, furniture, fixtures,
equipment and vehicles which are recorded at cost and depreciated using the
straight-line method over the estimated useful lives of five to fifteen years.
Maintenance and repairs are charged to expense as incurred.
Impairment of Long Lived Assets
The long-lived assets of the Company consist primarily of proved oil and
gas properties and undeveloped leaseholds. The Company reviews the carrying
values of its oil and gas properties and undeveloped leaseholds annually or
whenever events or changes in circumstances indicate that such carrying values
may not be recoverable. If, upon review, the sum of the undiscounted pretax cash
flows is less than the carrying value of the asset group, the carrying value is
written down to estimated fair value. Individual assets are grouped for
impairment purposes at the lowest level for which there are identifiable cash
flows that are largely independent of the cash flows of other groups of assets,
generally on a field-by-field basis. The fair value of impaired assets is
determined based on quoted market prices in active markets, if available, or
upon the present values of expected future cash flows. The impairment analysis
performed by the Company may utilize Level 3 inputs.
The Company recorded no proved property impairment in the years ended
October 31, 2012 and 2011. The Company recorded abandonments of unproved
property of $120,798 and $0 in the years ended October 31, 2012 and 2011,
respectively.
Income Taxes
Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized when items of income and
expense are recognized in the financial statements in different periods than
when recognized in the applicable tax return. Deferred tax assets arise when
expenses are recognized in the financial statements before the tax return or
when income items are recognized in the tax return prior to the financial
statements. Deferred tax assets also arise when operating losses or tax credits
are available to offset tax payments due in future years. Deferred tax
liabilities arise when income items are recognized in the financial statements
before the tax returns or when expenses are recognized in the tax return prior
to the financial statements. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the date when the change in the
tax rate was enacted.
We routinely assess the realizability of our deferred tax assets. If we
conclude that it is more likely than not that some portion or all of the
deferred tax assets will not be realized under accounting standards, the tax
asset is reduced by a valuation allowance. In addition we routinely assess
uncertain tax positions, and accrue for tax positions that are not
more-likely-than-not to be sustained upon examination by taxing authorities.
Major Customers
Sales to major unaffiliated customers consisted of the following. For the
year ended October 31, 2012, Customer A accounted for approximately 19% of
revenue, Customer B accounted for approximately 26% and
F-10
Customer C accounted for approximately 55%. For the year ended October 31, 2011,
Customer A accounted for approximately 19% of revenue, Customer B accounted for
approximately 14%, Customer C accounted for approximately 17%, and Customer D
accounted for approximately 44%.
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
The Company adopted Accounting Standards Update No. 2011-05 ("ASC No.
2011-05"), an update to ASC Topic 220, Comprehensive Income, effective January
1, 2012. The update amended current guidance to require companies to present
total comprehensive income either in a single, continuous statement of
comprehensive income or in two separate, but consecutive, statements. Under the
single-statement approach, entities must include the components of net income, a
total for net income, the components of other comprehensive income ("OCI") and a
total for comprehensive income. Under the two-statement approach, entities must
report an income statement and, immediately following, a statement of OCI. ASC
No. 2011-05 required retrospective application. The Company also adopted ASC No.
2011-12, which defers until further notice ASC No. 2011-05's requirement that
items that are reclassified from other comprehensive income to net income be
presented on the face of the financial statements. The Company has elected to
use the two-statement approach. The adoption of these updates affected
presentation only, and had no impact on the Company's financial position,
results of operation or cash flows.
In January 2013, the Financial Accounting Standards Board ("FASB") issued
ASC Update No. 2013-01 ("ASC No. 2013-01"), The objective of ASC No. 2013-01 is
to clarify that the scope of Accounting Standards Update No. 2011-11,
Disclosures about Offsetting Assets and Liabilities ("ASC No. 2011-11"), would
apply to derivatives including bifurcated embedded derivatives, repurchase
agreements and reverse repurchase agreements, and securities borrowing and
securities lending transactions that are either offset or are subject to a
master netting arrangement or similar agreement. ASC No. 2011-11, issued in
December 2011, requires that entities disclose both gross and net information
about instruments and transactions eligible for offset in the statement of
financial position as well as instruments and transactions subject to an
agreement similar to a master netting arrangement. In addition, the standard
requires disclosure of collateral received and posted in connection with master
netting agreements or similar arrangements. The amendments are effective for
annual reporting periods beginning on or after January 1, 2013, and interim
periods within those annual periods. The disclosures required by the amendments
are required to be applied retrospectively for all comparative periods
presented. The Company does not believe the adoption of this update will have a
material impact on the Company's consolidated financial statements.
In July 2013, FASB issued ASU No. 2013-11, Income Taxes (Topic 740):
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss
Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU
is effective for interim and annual periods beginning after December 15, 2013.
This update standardizes the presentation of an unrecognized tax benefit when a
net operating loss carryforward, a similar tax loss, or a tax credit
carryforward exists. Management does not anticipate that the accounting
pronouncement will have any material future effect on our consolidated financial
statements.
There were various other updates recently issued, most of which represented
technical corrections to the accounting literature or application to specific
industries, and are not expected to have a material impact on the Company's
financial position, results of operations or cash flows.
F-11
2. Oil and gas properties
Oil and gas properties consist of the following:
10/31/2012 10/31/2011
-------------- ------------
Proved oil and gas properties $ 158,781 $ 158,781
Wells in progress 101,064 -
Proved undeveloped oil and gas leaseholds 2,389,307 2,376,189
------------- ------------
2,649,152 2,534,970
Less accumulated depletion (41,567) (16,412)
-------------- ------------
Net oil and gas properties $2,607,585 $2,518,558
============== ============
Total depletion of oil and gas properties amounted to $25,155 and $16,412
for the years ended October 31, 2012 and 2011. The Company recorded an
impairment charge of $120,798 and $0, respectively, for the years ended October
31, 2012 and 2011 related to the abandonment of certain leaseholds during the
year.
3. Participation Agreement
In connection with the convertible promissory note described in note 4, 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, 2012,
$250,000 was 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 (2 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:
o any overriding royalties or other burden on production in excess of the 80%
net revenue interest;
o production, severance and similar taxes assessed by any taxing authority
based on volume or value of the production;
o costs reasonably incurred to process the production for market that occurs
outside the lease;
o costs reasonably incurred in transportation, delivery, storage or marketing
the production occurring outside the lease.
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. The note was in default at October 31, 2012 and the default was cured in
fiscal 2013. On July 30, 2013, the maturity date of the note was extended to
December 11, 2015. The balance on the note was $139,800 at October 31, 2012 with
interest accrued in the amount of $8,233.
F-12
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 and 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, 2012
is $248,895. The lender has the right to convert the principal to 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 20%
modified net profits interest described in note 3. In the event the principal
amount owed at the time of conversion is less than $350,000, the working
interest received upon conversion will 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 not elect to convert
within 10 days after receiving the notice, the conversion rights terminate. The
Company recorded a discount to the debt of $136,599 and recognized accretion of
the discount in the amount of $41,090 during the year ended October 31, 2012.
The ending balance of the debt discount at October 31, 2012 was $95,509. 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 not elect to convert within 10 days after receiving
the notice, the conversion rights terminate. The Company reviewed the conversion
feature for beneficial conversion features and embedded derivatives, and
determined that neither applied.
6. Asset Retirement Obligation
The following table reflects a reconciliation of the Company's asset retirement
obligation liability:
2012 2011
---- ----
Beginning asset retirement obligation $184,644 $ -
Liabilities incurred - 170,147
Liabilities settled - -
Accretion expense 19,245 14,497
Revision to estimated cash flows - -
-------- --------
Ending asset retirementobligation $203,889 $184,644
======== ========
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,
2012 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.
F-13
The provision for income taxes consists of:
October 31, October 31,
2012 2011
--------------- ---------------
Current $ 328,500 $364,400
Deferred 21,100 750
------------- ---------
$ 349,600 $ 365,150
============= ==========
The tax effects of temporary differences that gave rise to the deferred tax
liabilities and deferred tax assets as of October 31, 2012 and 2011 were:
October 31, October
2012 31, 2011
------------- ----------
Deferred tax assets:
Net operating loss carry forwards $ 716,600 $ 388,200
Deferred tax liability:
Property and equipment (56,200) (500)
------------- ---------
660,400 387,700
Less valuation allowance (660,400) (387,700)
------------- ---------
$ - $ -
============= =========
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, 2012,
the Company had a net operating loss carry forward for regular income tax
reporting purposes of approximately $1,838,050, 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, 2012
and 2011:
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.
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 stock 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
the 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
F-14
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 voted for.
Common Stock--The Company has 80,000,000 shares of $0.0001 par value common
stock authorized.
The Company issued 9,583,704 shares of Common Stock to its founders on May
1, 2010 in consideration of $1,064.
The Company issued 2,500,000 shares of Common Stock to an unrelated
corporation in exchange for certain oil and gas assets valued at $2,500,000 on
December 22, 2010.
The Company issued 660,000 shares at various times between February 27,
2011 to September 6, 2011 in exchange for cash in the amount of $660,000.
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.
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 a defendant in a cause of action against it for amounts
owing a supplier. Said case was settled in June 2013 (see subsequent events note
12).
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.
Employment Agreements
The Company has written employment agreements with its President and
General Counsel. Pursuant to their employment agreements, said officers devote
such time as each deems necessary to perform their 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, and the General Counsel will receive
$84,000 per annum. Both the President and the General Counsel will be granted
royalties pursuant to the royalty program, and was assigned a 1% of 8/8ths
overriding royalty interest in the Company's existing Garcia Field assets. The
value of the overriding royalty interest was estimated at $377,887 as of October
31, 2011 and has been recorded in general and administrative expenses. The
agreement specifies that at each time one of the following events occurs, the
President is to receive an incentive bonus, which will be paid in cash:
o When the Company receives an outside investment equal to or greater than
$100,000, the Company will tender 2% of the investment value.
F-15
o In the event of a sale of some or all of the Company's assets, the
President will receive compensation in the amount of 1.5% of the proceeds
from the sale.
o In the event the Company acquires producing assets, the President is to
receive a cash payment of 1% of the value of the acquisition.
The General Counsel's agreement 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 agreement specifies that at each time one of the following
events occurs, the General Counsel is to receive an incentive bonus:
o When the Company receives an outside investment equal to or greater than
$100,000, the Company will tender 1.5% of the investment value.
o In the event of a sale of some or all of the Company's assets, the General
Counsel will receive compensation in the amount of 1.5% of the proceeds
from the sale.
o In the event the Company acquires producing assets, the General Counsel is
to receive a cash payment of 1% of the value of the acquisition.
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 will be granted royalties pursuant to the
royalty program, and was assigned a 1% of 8/8ths overriding royalty interest in
the Company's existing Garcia Field assets.
The Company has no long term lease obligations.
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
the office space for a 3 year period ending July 1, 2013. The lease provides for
the payment of $2,667 per month plus utilities and other incidentals. The
president of the Company owns 50% of Spotswood. 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 2012
and 2011, respectively.
In fiscal 2011 the Board of Directors granted a 1% overriding royalty
interest to certain officers and directors in all of the oil and gas assets held
at that time. The overriding royalty interest was valued at $377,887 and charged
to operations. The valuation represents the estimated present value of the
future revenues of the producing wells discounted at 10%.
The Company paid $43,116, $63,074, and $0 in fiscal years 2012, 2011 and
2010 respectively, to the President's brother for land-man fees and expense
reimbursements in connection with performing contract land services for the
Company.
F-16
11. Acquisition of Proved Oil and Gas Properties
In December 2011, the Company acquired 4 producing oil and gas wells,
compression and separating equipment and approximately 4,600 acres in the Garcia
field located in south eastern Colorado together with 4 producing oil and gas
wells in Adams County Colorado and 2 producing oil and gas wells in the
Wattenburg Field and 1 shut-in oil and gas well in Morgan County, Colorado.
The acquisition of working interest was accounted for under the purchase method
of accounting. Under the purchase method of accounting, the purchase price is
allocated to the assets acquired and liabilities assumed based on their
estimated fair values. Of the $2,860,000 of purchase price, $2,740,000 was
allocated to proved properties and $120,000 was allocated to unproved leasehold
costs. The leasehold costs were abandoned and impaired in 2012.
12. Subsequent Events
The Company settled the litigation on amounts due to a supplier, described
in note 9, in June, 2013 paying $12,500.
The Company issued 785,000 shares of its $0.0001 par value Common Stock in
consideration of $785,000 during the period from November 1, 2012 to July 22,
2013.
In May and June 2013, the Company issued 395,877shares of its $0.0001 par
value Common Stock in consideration of cancellation of $65,240 of accounts
payable.
In May 2013, the $0.2394 par value Class A Preferred Stock was converted
from 208,820 shares of preferred to 208,820 shares of $0.0001 par value Common
Stock.
In October 2013, the Company sold 74,750 shares of its common stock for
cash of $74,750.
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.
In November 2013, the Company entered into an agreement to exchange securities
with Diversified Resources, Inc. whereby the shareholders of the Company
received 14,558,158 shares of Diversified Resources, Inc.'s $0.001 par value
common shares. The exchange was consummated in November 2013.
13. Disclosures about Oil and Gas Producing Activities (Unaudited)
Capitalized costs relating to oil and gas producing activities:
10/31/2012 10/31/2011
------------- -----------
Property acquisition costs:
Proved developed properties $ 158,781 $ 158,781
Proved undeveloped properties 2,389,307 2,376,189
Undeveloped oil and gas leaseholds - 120,000
Development costs 101,064 -
------------- -----------
2,649,152 2,654,970
------------- -----------
Less accumulated depletion (41,567) (16,412)
------------- -----------
Total $ 2,607,585 $ 2,638,558
============= ===========
F-17
Costs incurred in connection with crude oil and natural gas acquisition,
exploration and development are as follows:
10/31/2012 10/31/2011
-------------- -----------
Acquisition of properties:
$
Proved $ - 2,740,000
Unproved - 120,000
Development costs 250,991 -
Exploration costs 69,718 57,600
-------- ---------
Total $ 320,709 $2,917,600
========= ==========
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):
10/31/2012 10/31/2011
---------- ----------
Operating Revenues $79,104 $75,520
--------- -------
Costs & expenses:
Exploration 69,718 57,600
Lease operating expenses 117,357 105,600
Depletion 25,155 16,412
--------- -------
Total costs & expenses 212,230 179,612
--------- -------
Income (loss) before income taxes (133,126) (104,092)
--------- -------
Income tax (expense) benefit 51,919 40,596
--------- -------
Results of operations $ (81,207) $(63,496)
========= ========
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, 2012 and 2011:
Gallons
Oil (Bbl) Gas (Mcf) NG Liquid
----------- ---------- ----------
Balance, October 31, 2010 - - -
Revision of previous estimates - - -
Purchase of reserves in place 6,532 701,496 5,522,505
Extensions, discoveries, and
other additions - - -
Sale of reserves in place - - -
Production (206) (4,571) (28,359)
-------- -------- ---------
Balance, October 31, 2011 6,326 696,925 5,494,146
Revision of previous estimates (575) (102,871) 250,647
Purchase of reserves in place - - -
Extensions, discoveries, and
other additions - - -
Sale of reserves in place - - -
Production (417) (5,015) (20,375)
-------- -------- ---------
Balance, October 31, 2012 5,334 589,039 5,724,418
======== ======== =========
F-18
Developed at October 31, 2011 6,326 59,676 -
Proved undeveloped at October
31, 2011 - 637,249 5,494,146
--------- --------- ----------
Balance, October 31, 2011 6,326 696,925 5,494,146
========= ========= ==========
Developed at October 31, 2012 5,334 28,667 -
Undeveloped at October 31, 2012 - 560,372 5,724,418
--------- --------- ----------
Balance, October 31, 2012 5,334 589,039 5,724,418
========= ========= ==========
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:
10/31/2012 10/31/2011
------------- -----------
Future cash inflows $ 6,703,766 $11,348,741
Future production costs (1,674,164) (1,521,494)
Future development costs (3,478,125) (3,443,000)
Future income tax expense (605,076) (2,489,857)
------------ -----------
Future net cash flows 946,401 3,894,390
10% annual discount for estimated timing
of cash flows (866,004) (1,314,983)
------------ -----------
Standardized measure of discounted
future net cash flows $ 80,397 $ 2,579,407
============ ===========
F-19
There have been significant fluctuations in the posted prices of oil and
natural gas during the last three years. Prices actually received from
purchasers of the Company's oil and gas are 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, 2011 (Average) $ 91.57 $ 4.76 $ 1.36
October 31, 2012 (Average) $ 92.94 $ 3.04 $ 0.77
Principal changes in the Standardized Measure for the years ended October 31,
2012 and 2011 were as follows:
10/31/2012 10/31/2011
----------- ----------
Standardized measure, beginning of year $ 2,579,407 $ -
Purchase of reserves in place - 4,198,457
Sale and transfers, net of production costs 38,253 30,080
Net changes in prices and production costs (2,990,267) -
Extensions, discoveries, and improved recovery - -
Changes in estimated future development costs (192,936) -
Development costs incurred during the period 250,991 -
Revision of quantity estimates (163,262) -
Accretion of discount 422,854 -
Net change in income taxes 1,597,729 (1,649,130)
Changes in timing and other (1,462,372) -
------------- -----------
Standardized measure, end of year $ 80,397 $ 2,579,407
============= ===========
F-20
NATURAL RESOURCE GROUP, INC.
FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED JULY 31, 2013 AND 2012
F-21
Natural Resource Group, Inc.
Notes to Financial Statements
July 31, 2013 and 2012
Balance Sheet as of July 31, 2013 (unaudited) F-1 Statements Operations for the
Nine Months Ended July 31, 2013 and 2012 (unaudited) F-2 Statements of Cash
Flows for the Nine Months Ended July 31, 2013 and 2012 (unaudited) F-3 Notes to
Unaudited Financial Statements F-4
F-22
Natural Resource Group, Inc.
BALANCE SHEETS
(Unaudited)
July 31, 2013 October 31, 2012
------------- ----------------
ASSETS
CURRENT ASSETS
Cash $ 190,973 $ 1,051
Accounts receivable, trade 17,813 14,281
Prepaid expenses 4,770 5,703
---------- ----------
Total current assets 213,556 21,035
---------- ----------
Property and Equipment, net of accumulated
depreciation of $3,723 and $1,494 2,542 2,632
Oil and gas properties - proved (successful
efforts method) net of accumulated depletion
of $70,867 and $47,567 2,623,522 2,607,585
Total assets $ 2,839,620 $ 2,631,252
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 86,212 $ 89,017
Accounts payable, related party 145,937 92,295
Accrued interest 2,367 4,605
Accrued interest, related party 12,813 8,233
Notes payable 281,932 -
Accrued expenses 186,863 172,013
---------- ----------
Total current liabilities 716,124 366,163
---------- ----------
LONG TERM LIABILITIES
Notes payable, related party 78,000 139,800
Long term debt 21,700 223,386
Asset retirement obligation 221,289 203,889
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 - 49,992
Common stock, $0.0001 par value, 80,000,000
shares authorized, 14,483,401 and 13,093,704
shares issued and outstanding 1,448 1,309
Additional paid in capital 4,672,502 3,484,763
Accumulated deficit (2,871,443) (1,838,050)
---------- ----------
Total stockholders' equity 1,802,507 1,698,014
---------- ----------
Total liabilities and stockholders'
equity $ 2,839,620 $ 2,631,252
=========== ===========
See accompanying notes to the unaudited financial statements.
F-23
Natural Resource Group, Inc.
STATEMENTS OF OPERATIONS
(Unaudited)
Nine Months Ended
July 31, July 31,
2013 2012
------------ ---------
Operating revenues
Oil and gas sales $ 44,573 $ 77,403
Operating expenses
Exploration costs, including dry holes 49,520 26,846
Lease operating expenses 155,542 73,890
General and administrative 372,460 398,377
Depreciation expense 2,229 333
Depletion expense 23,300 24,614
Accretion expense 17,400 17,400
---------------- -----------------
Total operating expenses 620,451 541,460
---------------- -----------------
(Loss) from operations (575,878) (464,057)
---------------- -----------------
Other income (expense)
Loss on debt extinguishment (330,638) -
Loss on disposition of assets (34,480) -
Interest expense (92,397) (44,937)
---------------- -----------------
Other income (expense), net (457,515) (44,937)
---------------- -----------------
Net (loss) $ (1,033,393) $ (508,994)
================ =================
Net (loss) per common share
Basic and diluted $ (0.08) $ (0.04)
================ =================
Weighted average shares outstanding
Basic and diluted 13,412,898 12,923,129
================ =================
See accompanying notes to the unaudited financial statements.
F-24
Natural Resource Group, Inc.
STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
July 31, 2013 July 31, 2012
-------------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) $ (1,033,393) $ (508,994)
Adjustments to reconcile net (loss)
to net cash (used in) operating activities:
Depreciation expense 2,229 333
Depletion expense 23,300 24,614
Accretion expense 17,400 17,400
Loss on debt extinguishment 330,638 -
Loss on sale of assets 34,480 -
Amortization of discount on notes payable 59,925 26,752
(Increase) decrease in assets:
Accounts receivable, trade (3,533) 1,501
Prepaid expense 933 (8,801)
Increase (decrease) in liabilities:
Accounts payable 2,431 40,848
Accounts payable - related parties 139,850 68,771
Accrued expenses (69,016) (23,809)
------------ ----------
Net cash (used in) operating activities (494,756) (361,385)
------------ ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for properties (39,237) (241,629)
Cash paid for purchase of fixed assets (61,319) -
Proceeds from sale of fixed assets 24,700 -
------------ ----------
Net cash (used in) investing activities (75,856) (241,629)
------------ ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock,
net of issuance costs 742,013 350,000
Proceeds from notes payable 81,700 320,000
Payments on notes payable (61,800) (1,105)
Payments on notes payable, related party (1,379) (28,957)
------------ ----------
Net cash provided by financing activities 760,534 639,938
------------ ----------
INCREASE (DECREASE) IN CASH 189,922 36,924
BEGINNING BALANCE 1,051 66,984
------------ ----------
ENDING BALANCE $ 190,973 $ 103,908
============ ==========
Cash paid for income taxes - -
============ ==========
Cash paid for interest $ 16,232 $ 14,951
============ ==========
F-25
Supplemental schedule of non-cash investing and
financing activities:
Issuance of common stock in exchange for
cancellation of payables $ 65,240 $ -
Conversion of preferred stock to common stock $ 49,992 $ -
Assignment of Net Profits Interest $ - $ 136,599
See accompanying notes to the financial statements.
F-26
Natural Resource Group, Inc.
Notes to Financial Statements
July 31, 2013 and 2012
The accompanying unaudited consolidated financial statements have been prepared
in accordance with accounting principles generally accepted in the US (US GAAP)
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. Accordingly, they do not include all of the
information and notes required by US GAAP for complete financial statements. The
accompanying consolidated financial statements at July 31, 2013 and October 31,
2012 and for the three and nine months ended July 31, 2013 and 2012 contain all
normally recurring adjustments considered necessary for a fair presentation of
our financial position, results of operations, cash flows and stockholders'
equity for such periods. Operating results for the nine months ended July 31,
2013 are not necessarily indicative of the results that may be expected for the
year ending October 31, 2013.
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 in the development stage until December
2011 when it acquired 8 producing oil and gas wells and 1 shut in well,
compression and separating equipment, approximately 6,800 acres in the Garcia
Field located in South Eastern Colorado and 640 acres of undeveloped oil and gas
leases in Huerfano County Colorado. Of the producing wells acquired 4 are
located in the Wattenburg Field in North East Colorado, 2 wells and the 1 shut
in well are located in Morgan County Colorado and 4 wells are located in the
Garcia Field.
The Company does not have an interest in any unconsolidated entities nor does it
have any unconsolidated special purpose entities.
Going Concern
As shown in the accompanying financial statements, we have incurred significant
operating losses since inception aggregating $2,871,443 and have negative
working capital in the amount of $502,568 at July 31, 2013. We have limited
financial resources until such time as we are able to generate positive cash
flow from operations. These factors raise substantial doubt about our ability to
continue as a going concern. Our ability to achieve and maintain profitability
and positive cash flow is dependent upon our ability to locate profitable oil
and gas properties, generate revenue from our planned business operations, and
control exploration cost. Management plans to fund its future operation by joint
venturing, obtaining additional financing, and attaining additional commercial
production. However, there is no assurance that we will be able to obtain
additional financing from investors or private lenders, or that additional
commercial production can be attained.
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
2. 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 a maturity date of
March 1, 2011. The promissory note is collateralized by the property and
equipment transferred and was subsequently subrogated to a convertible
promissory note on January 12, 2012. The balance due on the note is $78,000 at
July 31, 2013 with interest accrued in the amount of $12,813. The loan matures
on December 11, 2015.
3. Notes Payable
Convertible Promissory Note--On January 12, 2012 the Company entered into a
convertible promissory note bearing interest at 10%, due January 11, 2014 and 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
F-27
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 July 31, 2013 is
$247,516. The lender has the right to convert the principal to 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 20%
modified net profits interest. In the event the principal amount owed at the
time of conversion is less than $350,000, the working interest received upon
conversion will 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 not elect to convert within 10 days after receiving
the notice, the conversion rights terminate. The Company recognized debt
discount amortization of $59,925 and $26,752 during the nine months ended July
31, 2013 and 2012, respectively. The note has unamortized debt discount in the
amount of $35,584 as of July 31, 2013.
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 $0.001 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 not elect to convert within 10 days after receiving the
notice, the conversion rights terminate.
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 as of July 31, 2013:
Convertible promissory note $ 247,516
Debt discount, net of amortization (35,584)
Note payable, affiliate 78,000
Convertible promissory note 70,000
Installment loan 21,700
------------
381,632
Current portion (281,932)
------------
Long-term debt $ 99,700
============
4. Asset Retirement Obligation
The following table reflects a reconciliation of the Company's asset retirement
obligation liability for the period from October 31, 2012 through July 31, 2013:
Beginning asset retirement obligation $ 203,889
Liabilities incurred -
Liabilities settled -
Accretion expense 17,400
Revision to estimated cash flows -
-----------
Ending asset retirement obligation $ 221,289
===========
5. Stockholder's Equity
The Company issued 785,000 shares of Common Stock during the nine months ended
July 31, 2013 in exchange for cash in the amount of $785,000.
F-28
In May and June 2013, the Company issued 395,877 shares of Common Stock in
consideration of the cancellation of $65,240 of accounts payable. The Company
recorded a loss on extinguishment of debt on these transactions in the amount of
$330,638 for the nine months ended July 31, 2013.
In May 2013, the $0.2394 par value Class A Preferred stock was converted from
208,820 shares of preferred stock to 208,820 shares of Common Stock.
In October 2013, the Company sold 74,750 shares of its Common Stock for cash of
$74,750.
6. 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.
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.
7. 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 14,558,158 shares of Diversified Resources, Inc.'s $0.001 par
value common shares. The exchange was consummated in November 2013.
F-29
NATURAL RESOURCE GROUP, INC.
PRO FORMA FINANCIAL STATEMENTS
F-30
Diversified Resources, Inc.
UNAUDITED PRO FORMA BALANCE SHEET
July 31, 2013
Natural Adjusted
Diversified Resource Pro Forma Pro Forma
Resources, Inc. Group, Inc. Notes Adjustments Totals
-------------- ----------- ----- ----------- ---------
ASSETS
CURRENT ASSETS
Cash $ 1,671 $ 190,973 2 $ (1,671) $ 190,973
Accounts receivable, trade - 17,813 - 17,813
Prepaid expenses - 4,770 - 4,770
---------- ---------- ---------- ----------
Total current assets 1,671 213,556 (1,671) 213,556
---------- ---------- ---------- ----------
Property and Equipment, net of accumulated
depreciation of $3,723 and $1,494 2,542 - 2,542
Oil and gas properties - proved (successful
efforts method) net of accumulated
depletion of $70,867 and $47,567 - 2,623,522 - $2,623,522
---------- ---------- ---------- ----------
Total assets $ 1,671 $2,839,620 $ (1,671) $2,839,620
========== ========== ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 230,533 $ 86,212 1 (230,533) $ 86,212
Accounts payable, related parties 14,000 145,937 1 (14,000) 145,937
Notes payable, related party - 281,932 - 281,932
Accrued expenses - 186,863 - 186,863
Accrued interest - 2,367 - 2,367
Accrued interest, affiliates - 12,813 - 12,813
---------- ---------- ---------- ----------
Total current liabilities 244,533 716,124 (244,533) 716,124
---------- ---------- ---------- ----------
LONG TERM LIABILITIES
Notes payable, related party - 78,000 - 78,000
Long term debt - 21,700 - 21,700
Asset retirement obligation - 221,289 - 221,289
F-31
Natural Adjusted
Diversified Resource Pro Forma Pro Forma
Resources, Inc. Group, Inc. Notes Adjustments Totals
-------------- ----------- ----- ----------- ---------
COMMITMENTS AND CONTINGENT LIABILITIES
STOCKHOLDERS' EQUITY
Preferred stock, - - -
Common stock 5,250 1,448 1 (1,448) 19,808
1 14,558
Additional paid in capital 74,750 4,672,502 1 (93,110) 4,654,142
Deficit accumulated in the development stage (322,862) - 322,862 -
Accumulated (deficit) (2,871,443) (2,871,443)
---------- ---------- ---------- ----------
Total stockholders' equity (242,862) 1,802,507 242,862 1,802,507
---------- ---------- ---------- ----------
Total liabilities and stockholders' equity $ 1,671 $2,839,620 (1,671) 2,839,620
========== ========== ========== ==========
F-32
Diversified Resources, Inc.
UNAUDITED PRO FORMA STATEMENTS OF OPERATIONS
For the Fiscal Year Ended October 31, 2012
Natural
Diversified Resource
Resources, Inc. Group, Inc. Adjustments Pro Forma
---------------- ------------ ------------ ---------
Operating revenues $ - $ 79,104 $ - $ 79,104
--------- --------- --------- ----------
Operating expenses
Exploration costs, including
dry holes 69,718 - 69,718
Lease operating expenses 72,976 117,357 - 190,333
General and administrative 8,250 497,258 - 505,508
Accretion expense - 19,245 - 19,245
Abandonments - 120,798 - 120,798
Depreciation, depletion and
amortization - 26,303 - 26,303
--------- --------- --------- ----------
Total operating expenses 81,226 850,679 - 931,905
--------- --------- --------- ----------
(Loss) from operations (81,226) (771,575) - (852,801)
--------- --------- --------- ----------
Other income (expense)
Interest expense - (70,644) - (70,644)
--------- --------- --------- ----------
Other income (expense), net - (70,644) - (70,644)
--------- --------- --------- ----------
(Loss) before income taxes (81,226) (842,219) - (923,445)
--------- --------- --------- ----------
Net (loss) $ (81,226) $ (842,219) $ - $ (923,445)
========= ========== ========= ==========
Net (loss) per common share
Basic and diluted $ (0.02) $ (0.06) $ - $ (0.05)
========= ========== ========= ==========
Weighted average shares outstanding
Basic and diluted 5,252,000 12,966,615 - 19,815,150
========= ========== ========= ==========
Reflects the assumption that Shares O/S as if from the beginning of the period
for the pro forma
F-33
Diversified Resources Inc.
UNAUDITED PRO FORMA STATEMENTS OF OPERATIONS
Nine Months Ended July 31, 2013
Natural
Diversified Resource
Resources, Inc. Group, Inc. Adjustments Pro Forma
---------------- ------------ ------------ ---------
Operating revenues $ - 44,573 - $ 44,573
--------- --------- --------- ----------
Operating expenses
Exploration costs, including
dry holes - 49,520 - 49,520
Lease operating expenses 19,038 155,542 - 174,580
General and administrative 12,675 372,460 - 385,135
Accretion expense - 17,400 - 17,400
Depreciation, depletion and
amortization - 25,529 - 25,529
--------- --------- --------- ----------
Total operating expenses 31,713 620,451 - 652,164
--------- --------- --------- ----------
(Loss) from operations (31,713) (575,878) - (607,591)
--------- --------- --------- ----------
Other income (expense)
Loss on debt extinguishment - (330,638) - (330,638)
Gain (loss) on sale of assets - (34,480) - (34,480)
Interest expense - (92,397) - (92,397)
--------- --------- --------- ----------
Other income (expense), net - (457,515) - (457,515)
--------- --------- --------- ----------
(Loss) before income taxes
(31,713) (1,033,393) - (1,065,106)
--------- --------- --------- ----------
Net (loss) $ (31,713) $ (1,033,393) $ - $(1,065,106)
=========== ============ ========= ===========
Net (loss) per common share
Basic and diluted $ (0.01) $ (0.08) $ - $ (0.05)
=========== ============ ========= ===========
Weighted average shares outstanding
Basic and diluted 5,250,000 13,412,898 19,815,150
=========== ============ ===========
Reflects the assumption that Shares O/S as if from the beginning of the period
for the pro forma
F-34
PRO FORMA ADJUSTMENTS TO BALANCE SHEET AND STATEMENTS OF OPERATIONS
Basis of Presentation
In November 2013, Diversified Resources, Inc. ("DRI") entered into an
agreement to exchange securities with Natural Resource Group, Inc. ("NRG")
and closed the share exchange agreement in November 2013. The shareholders
of NRG received 14,558,158 shares of DRI's $0.001 par value common shares.
Immediately prior to the transaction, there were 5,250,000 shares issued
and outstanding and 19,158,150 shares issued and outstanding after the
transaction was consummated.
The accompanying pro forma balance sheets as of October 31, 2012 and pro
forma statements of operations for the years ended October 31, 2012 and
the nine months ended July 31, 2013 representing the accounts of DRI and
NRG. The accompanying pro forma balance sheets and pro forma statements of
operations are presented as if the acquisition of NRG occurred on October
31, 2012. The unaudited pro forma balance sheet as of October 31, 2012 was
based on the audited balance sheet of DRI and NRG combined with pro forma
adjustments to give effect to the reverse merger as if it occurred on
October 31, 2012. The unaudited pro forma statements of operations gives
effect to the merger as if it occurred at the beginning of the year ended
October 31, 2012.
Pro forma earnings (loss) per share is computed using the number of common
shares of DRI outstanding including the common shares issued to NRG to
effect the transaction at the beginning of the periods presented.
These unaudited pro forma financial statements are provided for
illustrative purposes and do not purport to represent what the Company's
financial position would have been if such transactions had occurred on
the above mentioned date. These statements were prepared based on
accounting principles generally accepted in the United States. The use of
estimates is required and actual results could differ from the estimates
used. The Company believes the assumptions used provide a reasonable basis
for presenting the significant effects directly attributable to the
acquisition.
The pro form statements of operations may not necessarily reflect the
results of operations had the acquisition actually occurred as of the
dates indicates.
Subsequent Event
In November 2013, the DRI entered into, and consummated, an agreement to
exchange securities with NRG whereby the shareholders of the NRG received
14,558,158 shares of Diversified Resources, Inc.'s $0.001 par value common
shares.
Explanation of Adjustments
1. Issuance of Common Shares
2. To reflect the issuance of 14,558,150 shares of DRI in exchange for
100% of the outstanding shares of NRG and reclassify accumulated
deficit to additional paid in capital in accordance with the principles
applicable to reverse acquisition accounting.
3. Changes in Current Liabilities and Current Assets
To reflect the reduction of cash and the assumption of payables by the
principals of DRI.
F-35
Item 3.02 Unregistered Sales of Equity Securities
The Company relied upon the exemption provided by Rule 506 of the
Securities and Exchange Commission with respect to the shares issued to the
shareholders of Natural Resource Group. See Item 2.01 of this report.
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.
Item 9.01 Financial Statements and Exhibits
a) Attached
b) Attached
d) 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
10.2 Note Payable - Energy Oil and Gas, Inc.
10.3 Convertible Promissory Note - $350,000
10.4 Convertible Promissory Note - $70,000
99.1 Reserve Report - Garcia Field
99.2 Reserve Report - D-J Basin
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: November 21, 2013 DIVERSIFIED RESOURCES, INC.
By: /s/ Paul Laird
------------------------------
Paul Laird, President
EXHIBITS
