U.S.
SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
————————————————————
FORM
10-KSB
x
Annual report pursuant
to Section 13 or 15(d) of the Securities Exchange Act of 1934
For
the
fiscal year ended April 30, 2006
¨
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange
Act
of 1934
For
the
transition period from _______ to _______
Commission
File No. 033-02249-FW
MILLER
PETROLEUM, INC.
(Name
of
small business issuer in its charter)
Tennessee
|
62-1028629
|
(State
or Other Jurisdiction
of
|
(I.R.S.
Employer
|
Incorporation
or
Organization)
|
Identification
No.)
|
3651
Baker Highway
Huntsville,
Tennessee 37756
(Address
of Principal Executive Offices)
(423)
663-9457
(Registrant’s
Telephone Number, Including Area Code)
Securities
Registered Under Section 12(b) of the Act: None
Securities
Registered Under Section 12(g) of the Act: None
Check
whether the issuer is not required to file reports pursuant to Section 13 or
15(d) of the Exchange Act.
Check
whether the issuer (1) has filed all reports required to be filed by Section
13
or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been
subject to such filing requirements for past 90 days. Yes No
¨
Check
if
there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will be contained,
to
the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB. ¨
The
Registrant’s revenues for the fiscal year ended April 30, 2006 were $2,538,772.
The
aggregate market value of the Common Stock held by non-affiliates, based on
the
average closing bid and asked price of the Common Stock on August 11, 2006,
was
$5,393,981.
There
are
approximately shares of common voting stock of the Registrant held by
non-affiliates. On August 11, 2006 the average bid and asked price was
$0.90.
As
of
August 11, 2006, there were 14276,856 shares of common stock
outstanding.
Forward-Looking
Statements
This
annual report on Form 10-KSB (“Annual Report”) for the period ending April 30,
2006 (“fiscal year 2006”), contains forward-looking statements as that term is
defined in the Private Securities Litigation Reform Act of 1995. These
statements relate to future events or our future financial performance. In
some
cases, you can identify forward-looking statements by terminology such as "may",
"will", "should", "expects", "plans", "anticipates", "believes", "estimates",
"predicts", "potential" or "continue" or the negative of these terms or other
comparable terminology. These statements are only predictions and involve known
and unknown risks, uncertainties and other factors, including the risks in
the
section entitled "Risk Factors” that may cause our or our industry's actual
results, levels of activity, performance or achievements to be materially
different from any future results, levels of activity, performance or
achievements expressed or implied by these forward-looking
statements.
Although
we believe that the expectations reflected in the forward-looking statements
are
reasonable, we cannot guarantee future results, levels of activity, performance
or achievements. Except as required by applicable law, including the securities
laws of the United States, we do not intend to update any of the forward-looking
statements to conform these statements to actual results.
Disclosure
Regarding Forward-Looking Statements Included in this report are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933,
as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
All
statements, other than statements of historical facts, included in this Form
10-KSB which address activities, events or developments which we expect or
anticipate will or may occur in the future are forward-looking
statements
As
used
in this Annual Report, the terms “we”, “us”, and “our” mean Miller Petroleum,
Inc.
Glossary
of Terms
We
are
engaged in the business of exploring for and producing oil and natural gas.
Oil
and gas exploration is a specialized industry. Many of the terms used to
describe our business are unique to the oil and gas industry. The following
glossary clarifies certain of these terms that may be encountered while reading
this report:
"Bcf" means
billion cubic feet, used in this annual report in reference to gaseous
hydrocarbons.
"BcfE"
means
billions of cubic feet of gas equivalent, determined using the ratio of six
thousand cubic feet of gas to one barrel of oil, condensate or gas liquids.
"Farmout"
involves
an entity's assignment of all or a part of its interest in or lease of a
property in exchange for consideration such as a royalty.
"Gross" oil
or
gas well or "gross" acre is a well or acre in which we have a working interest.
"Mcf" means
thousand cubic feet, used in this annual report to refer to gaseous
hydrocarbons.
"McfE"
means
thousands of cubic feet of gas equivalent, determined using the ratio of six
thousand cubic feet of gas to one barrel of oil, condensate or gas liquids.
"MMcf"
means
million cubic feet, used in this annual report to refer to gaseous
hydrocarbons.
"MBbl" means
thousand barrels, used in this annual report to refer to crude oil or other
liquid hydrocarbons.
"Net"
oil
and
gas wells or "net" acres are determined by multiplying "gross" wells or acres
by
our percentage interest in such wells or acres.
"Oil
and gas lease" or
"Lease"
means
an
agreement between a mineral owner, the lessor, and a lessee which conveys the
right to the lessee to explore for and produce oil and gas from the leased
lands. Oil and gas leases usually have a primary term during which the lessee
must establish production of oil and or gas. If production is established within
the primary term, the term of the lease generally continues in effect so long
as
production occurs on the lease. Leases generally provide for a royalty to be
paid to the lessor from the gross proceeds from the sale of production.
"Prospect" means
a
location where both geological and economical conditions favor drilling a well.
"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, i.e. prices and costs as of the date the estimate is
made.
Prices include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic recovery by production is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling
and
defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can reasonably be judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
"Proved
developed oil and gas reserves" are
those
proved reserves that can be expected to be recovered through existing wells
with
existing equipment and operating methods. Additional oil and gas reserves
expected to be obtained through the application of fluid injection or other
improved secondary or tertiary recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed recovery program has confirmed through production response that
increased recovery will be achieved.
"Proved
undeveloped oil and gas reserves"
are
those proved reserves that are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relatively major expenditure
is required. Reserves on undrilled acreage are limited to those drilling units
offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units are claimed only where it
can
be demonstrated with reasonable certainty that there is continuity of production
from the existing productive formation. Estimates for proved undeveloped
reserves attributable to any acreage do not include production for which an
application of fluid injection or other improved recovery technique is required
or contemplated, unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
"Royalty
interest" is
a
right to oil, gas, or other minerals that are not burdened by the costs to
develop or operate the related property.
"Working
interest" is
an
interest in an oil and gas property that is burdened with the costs of
development and operation of the property.
FORM
10-KSB
FOR
THE FISCAL YEAR ENDED APRIL 30. 2006
INDEX
Page
PART
I
Item
1
|
Description
of Business
|
6
|
Item
2
|
Description
of Property
|
14
|
Item
3
|
Legal
Proceedings
|
18
|
Item
4
|
Submission
of Matters to a Vote of Security Holders
|
18
|
PART
II
Item
5
|
Market
for Common Equity and Related Stockholder Matters
|
18
|
Item
6
|
Management’s
Discussion and Analysis or Plan of Operations
|
19
|
Item
7
|
Financial
Statements
|
24
|
Item
8
|
Changes
In and Disagreements With Accountants on Accounting and Financial
Disclosure
|
47
|
Item
8A
|
Controls
and Procedures
|
47
|
Item
8B
|
Other
Information
|
47
|
PART
III
Item
9
|
Directors,
Executive Officers, Promoters and Control Persons; Compliance
with Section 16(a) of the Exchange Act
|
47
|
Item
10
|
Executive
compensation
|
49
|
Item
11
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
50
|
Item
12
|
Certain
Relationships and Related Transactions
|
51
|
Item
13
|
Exhibits
|
52
|
Item
14
|
Principal
Accountant Fees and Services
|
53
|
PART
I
Item
1 Description
of Business
Corporate
History
We
were
founded in 1967 by Deloy Miller, our Chief Executive Officer, as a sole
proprietorship. On January 22, 1978, we were incorporated under the laws of
the
State of Tennessee as “Miller Contract Drilling, Inc.” We changed our name to
Miller Petroleum, Inc. on January 13, 1997.
Current
Business
We
are
actively engaged in the exploration, development, production and acquisition
of
crude oil and natural gas primarily in eastern Tennessee. In December 2005
we
entered into a joint venture agreement with Wind City Oil & Gas, LLC (“Wind
City”) to form Wind Mill Oil & Gas, LLC (the “Wind Mill Joint Venture”). We
own 49.9% of the Wind Mill Joint Venture and Wind City owns 50.1%. We
contributed approximately 43,000 acres, which we held under lease in Tennessee,
to the Wind Mill Joint Venture for oil and gas exploration, development and
exploitation of undeveloped wells. The joint venture will only encompass new
drilling projects. We retained our working interest in the developed and
producing wells located on such leases. In connection with the development
of
wells by the Wind Mill Joint Venture, we will also receive revenue for providing
labor and equipment.
Principal
Products or Services and Markets
The
principal markets for our crude oil and natural gas are refining companies,
utility companies and private industry end users. Direct purchases of our crude
oil are made statewide at our well sites by South Kentucky Purchasing Company,
a
refinery located in Somerset, Kentucky (“South Kentucky
Purchasing”).
Our
natural gas has multiple markets throughout the eastern United States through
gas transmission lines.
Access to these markets is presently provided by four companies in North-Eastern
Tennessee. Cumberland Valley Resources (“CV Resources”) purchases our natural
gas that is produced from the "Delta Leases." Nami Resources Company (“Nami
Resources”) purchases our gas from the Jellico West field and Tengasco services
the Swan Creek production. Local markets in Tennessee are served by Citizens
Gas
Utility District (‘Citizens Gas”) and the Powell Clinch Utility District.
Surplus gas is placed in storage facilities or transported to East Tennessee
Natural Gas which serves Tennessee and Virginia.
We
anticipate that our products will be sold to the aforementioned companies;
however, no assurance can be given that we will be able to make such sales
or
that if we do, we will be able to receive a price that is sufficient to make
our
operations profitable.
Distribution
Methods of Products or Services
Crude
oil
is stored in tanks at the well site until the purchaser retrieves it by tank
truck. Natural gas is delivered to the purchaser via gathering lines into the
main gas transmission line.
Competitive
Business Conditions
Our
oil
and gas exploration activities in Tennessee are undertaken in a highly
competitive and speculative business environment. In seeking any other suitable
oil and gas properties for acquisition, we compete with a number of other
companies located in Tennessee and elsewhere, including large oil and gas
companies and other independent operators, many with greater financial resources
than us.
At
the
local level, we have several competitors in the areas of the acreage which
we
have under lease in the State of Tennessee, five of which may be deemed to
be
significant. These are Consol Energy, Inc., Can Argo Energy Corporation (“CNR”),
Champ Oil, John Henry Oil and Tengasco. These companies are in competition
with
us for oil and gas leases in known producing areas in which we currently
operate, as well as other potential areas of interest.
Although,
our management generally does not foresee difficulties in procuring logging,
cementing and well treatment services in the area of our operations, several
factors, including increased competition in the area, may limit the availability
of logging equipment, cementing and well treatment services in the future.
If
such an event occurs, it may have a significant adverse impact on the
profitability of our operations.
The
prices of our products are controlled by the world oil market and the United
States natural gas market; thus, competitive pricing behaviors in this regard
are considered unlikely; however, competition in the oil and gas exploration
industry exists in the form of competition to acquire the most promising acreage
blocks and obtaining the most favorable prices for transporting the
product.
Dependence
on One or a Few Major Customers
We
are
dependent on local purchasers of hydrocarbons to purchase our products in the
areas where our properties are located. The loss of one or more of our primary
purchasers may have a substantial adverse impact on our sales and on our ability
to operate profitably.
Currently,
we are selling natural gas to the following purchasers:
|
·
|
Citizens
Gas purchases natural gas from our wells in Scott County, Tennessee.
Citizens is paying the Inside FERC Tn Zone 1 (Louisiana) monthly
index
less transportation costs. Sales to Citizens is less than 1% of our
total
natural gas sales.
|
|
·
|
Nami
Resources purchases our gas from the Jellico Field. The sales price
varies
each month but will not be less than $6.00 per Mcf. Sales to Nami
Resources at the present time are approximately 25% of our total
natural
gas sales.
|
|
·
|
Tengasco
purchases natural gas from wells in the Swan Creek Field. Tengasco,
Inc.
is paying the New York Mercantile Exchange first of the month posting
plus
$0.05 less transportation charges. Sales to Tengasco are about 10
% of
total natural gas sales.
|
|
·
|
CV
Resources purchases the gas produced from the joint venture with
Delta
Producers, Inc. in the Jellico East Field, Tennessee. The sales price
is
Appalachian Index minus Columbia transportation and fuel. Cumberland
Valley Resources purchases approximately 20% of total natural gas
sales.
|
|
·
|
PCUD
purchases the gas from the Lindsay Land Company lease which is another
joint venture with Delta Producers. The sales price is Inside FERC
Tn Zone
1 (Louisiana) monthly index less transportation costs. About 44%
of our
gas sales are to the PCUD.
|
|
·
|
South
Kentucky Purchasing purchases all of our crude oil. South Kentucky
Purchasing’s purchase price is based on postings for the Illinois Basin
less $2.50.
|
Patents,
Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor
Contracts
Royalty
agreements relating to oil and gas production are standard in the industry.
The
amounts of the royalty payments which we receive varies from lease to lease.
(See Description of Business - “Current Business” in this Annual
Report.)
Governmental
Approval and Regulation
The
production and sale of oil and gas are subject to regulation by federal, state
and local authorities. None of the principal products that we offer require
governmental approval, although permits are required for the drilling of oil
and
gas wells.
Our
sales
of natural gas are affected by intrastate and interstate gas transportation
regulation. Beginning in 1985, the Federal Energy Regulatory Commission
(“FERC”), which sets the rates and charges transportation and sale of natural
gas, adopted regulatory changes that have significantly altered the
transportation and marketing of natural gas. The stated purpose of FERC’s
changes are to promote competition among the various sectors of the natural
gas
industry. In 1995, FERC implemented regulations generally grandfathering all
previously approved interstate transportation rates and establishing an indexing
system for those rates by which adjustments are made annually based on the
rate
of inflation, subject to certain conditions and limitations. These regulations
may tend to increase the cost of transporting oil and natural gas by pipeline.
Every five years, FERC will examine the relationship between the change in
the
applicable index and the actual cost changes experienced by the industry. We
are
not able to predict with certainty what effect, if any, these regulations will
have on us.
Tennessee
law requires that we obtain state permits for the drilling of oil and gas wells
and to post a bond with the Tennessee Gas and Oil Board (the “Oil and Gas
Board”) to ensure that each well is reclaimed and properly plugged when it is
abandoned. The reclamation bonds cost $1,500 per well. The cost for the plugging
bonds are $2,000 per well or $10,000 for ten wells. Currently, we have several
of the $10,000 plugging bonds. For most of the reclamation bonds, we have
deposited a $1,500 Certificate of Deposit with the Oil and Gas Board.
The
state
and regulatory burden on the oil and natural gas industry generally increases
our cost of doing business and affects our profitability. While we believe
we
are presently in compliance with all applicable federal, state and local laws,
rules and regulations, continued compliance (or failure to comply) and future
legislation may have an adverse impact on our present and contemplated business
operations. Because such federal and state regulation are amended or
reinterpreted frequently, we are unable to predict with certainty the future
cost or impact of complying with these laws.
Research
and Development
We
did
not incur any research and development expenditures during the fiscal year
ended
April 30, 2006.
Environmental
Compliance
We
are
subject to various federal, state and local laws and regulations governing
the
protection of the environment, such as the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (“CERCLA”), and the Federal
Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), which
affect our operations and costs. In particular, our exploration, development
and
production operations, our activities in connection with storage and
transportation of oil and other hydrocarbons and our use of facilities for
treating, processing or otherwise handling hydrocarbons and related wastes
may
be subject to regulation under these and similar state legislation. These laws
and regulations:
|
·
|
restrict
the types, quantities and concentration of various substances that
can be
released into the environment in connection with drilling and production
activities;
|
|
·
|
limit
or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas;
and
|
|
·
|
impose
substantial liabilities for pollution resulting from our
operations.
|
Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil and criminal fines and penalties or the imposition of
injunctive relief. Changes in environmental laws and regulations occur
regularly, and any changes that result in more stringent and costly waste
handling, storage, transport, disposal or cleanup requirements could materially
adversely affect our operations and financial position, as well as those in
the
oil and natural gas industry in general. While we believe that we are in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements would
not
have a material adverse impact on us, there is no assurance that this trend
will
continue in the future.
As
with
the industry generally, compliance with existing regulations increases our
overall cost of business. The areas affected include:
|
·
|
unit
production expenses primarily related to the control and limitation
of air
emissions and the disposal of produced
water;
|
|
·
|
capital
costs to drill exploration and development wells primarily related
to the
management and disposal of drilling fluids and other oil and natural
gas
exploration wastes; and
|
|
·
|
capital
costs to construct, maintain and upgrade equipment and
facilities.
|
CERCLA,
also known as “Superfund,” imposes liability for response costs and damages to
natural resources, without regard to fault or the legality of the original
act,
on some classes of persons that contributed to the release of a “hazardous
substance” into the environment. These persons include the “owner” or “operator”
of a disposal site and entities that disposed or arranged for the disposal
of
the hazardous substances found at the site. CERCLA also authorizes the
Environmental Protection Agency (“EPA”) and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. It
is
not uncommon for 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. In the course of our ordinary
operations, we may generate waste that may fall within CERCLA’s definition of a
“hazardous substance.” We may be jointly and severally liable under CERCLA or
comparable state statutes for all or part of the costs required to clean up
sites at which these wastes have been disposed.
We
currently lease properties that for many years have been used for the
exploration and production of oil and natural gas. Although we and our
predecessors have used operating and disposal practices that were standard
in
the industry at the time, hydrocarbons or other wastes may have been disposed
or
released on, under or from the properties owned or leased by us or on, under
or
from other locations where these wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons
or
other wastes were not under our control. These properties and wastes disposed
on
these properties may be subject to CERCLA and analogous state laws. Under these
laws, we could be required:
|
·
|
to
remove or remediate previously disposed wastes, including wastes
disposed
or released by prior owners or
operators;
|
|
·
|
to
clean up contaminated property, including contaminated groundwater;
or to
perform remedial operations to prevent future
contamination.
|
|
·
|
to
clean up contaminated property, including contaminated groundwater;
or to
perform remedial operations to prevent future
contamination.
|
At
this
time, we do not believe that we are associated with any Superfund site and
we
have not been notified of any claim, liability or damages under CERCLA.
The
Resource Conservation and Recovery Act (“RCRA”) is the principal federal statute
governing the treatment, storage and disposal of hazardous wastes. RCRA imposes
stringent operating requirements and liability for failure to meet such
requirements on a person who is either a “generator” or “transporter” of
hazardous waste or an “owner” or “operator” of a hazardous waste treatment,
storage or disposal facility. At present, RCRA includes a statutory exemption
that allows most oil and natural gas exploration and production waste to be
classified as nonhazardous waste. A similar exemption is contained in many
of
the state counterparts to RCRA. As a result, we are not required to comply
with
a substantial portion of RCRA’s requirements because our operations generate
minimal quantities of hazardous wastes. At various times in the past, proposals
have been made to amend RCRA to rescind the exemption that excludes oil and
natural gas exploration and production wastes from regulation as hazardous
waste. Repeal or modification of the exemption by administrative, legislative
or
judicial process, or modification of similar exemptions in applicable state
statutes, would increase the volume of hazardous waste we are required to manage
and dispose of and would cause us to incur increased operating expenses.
The
Clean
Water Act imposes restrictions and controls on the discharge of produced waters
and other wastes into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters and to conduct construction activities
in waters and wetlands. The Clean Water Act requires us to construct a fresh
water containment barrier between the surface of each drilling site and the
underlying water table. This involves the insertion of a seven-inch diameter
steel casing into each well, with cement on the outside of the casing. The
cost
of compliance with this environmental regulation is approximately $10,000 per
well. Certain state regulations and the general permits issued under the Federal
National Pollutant Discharge Elimination System program prohibit the discharge
of produced waters and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and natural gas industry into certain coastal
and
offshore waters. Further, the EPA has adopted regulations requiring certain
oil
and natural gas exploration and production facilities to obtain permits for
storm water discharges. Costs may be associated with the treatment of wastewater
or developing and implementing storm water pollution prevention plans.
The
Clean
Water Act and comparable state statutes provide for civil, criminal and
administrative penalties for unauthorized discharges for oil and other
pollutants and impose liability on parties responsible for those discharges
for
the costs of cleaning up any environmental damage caused by the release and
for
natural resource damages resulting from the release. We believe that our
operations comply in all material respects with the requirements of the Clean
Water Act and state statutes enacted to control water
pollution.
Our
operations are also subject to laws and regulations requiring removal and
cleanup of environmental damages under certain circumstances. Laws and
regulations protecting the environment have generally become more stringent
in
recent years, and may in certain circumstances impose "strict liability,"
rendering a corporation liable for environmental damages without regard to
negligence or fault on the part of such corporation. Such laws and regulations
may expose us to liability for the conduct of operations or conditions caused
by
others, or for acts which may have been in compliance with all applicable laws
at the time such acts were performed. The modification of existing laws or
regulations or the adoption of new laws or regulations relating to environmental
matters could have a material adverse effect on our operations.
In
addition, our existing and proposed operations could result in liability for
fires, blowouts, oil spills, discharge of hazardous materials into surface
and
subsurface aquifers and other environmental damage, any one of which could
result in personal injury, loss of life, property damage or destruction or
suspension of operations. We have an Emergency Action and Environmental Response
Policy Program in place. This program details the appropriate response to any
emergency that management believes to be possible in our area of operations.
We
believe we are presently in compliance with all applicable federal and state
environmental laws, rules and regulations; however, continued compliance (or
failure to comply) and future legislation may have an adverse impact on our
present and contemplated business operations.
The
foregoing is only a brief summary of some of the existing environmental laws,
rules and regulations to which our business operations are subject, and there
are many others, the effects of which could have an adverse impact on our
business. Future legislation in this area will no doubt be enacted and revisions
will be made in current laws. No assurance can be given as to what effect these
present and future laws, rules and regulations will have on our current future
operations.
Insurance
Employees
We
currently have 15 full-time employees.
Risk
Factors
Any
investment in our Common Stock involves a high degree of risk. You should
carefully consider the risks and uncertainties described below and the other
information included in this Annual Report before purchasing our Common Stock.
Although the risks described below are the risks that we believe are material,
they are not the only risks relating to our business and our Common Stock.
Additional risks and uncertainties, including those that are not yet identified
or that we currently believe are immaterial, may also adversely affect our
business, financial condition or results of operations. If any of the events
described below occur, our business and financial results could be materially
and adversely affected. The market price of our Common Stock could decline
due
to any of these risks, perhaps significantly, and you could lose all or part
of
your investment.
General
Risks Related To Our Business
The
termination of the Wind Mill Joint Venture could have a material adverse effect
on our financial condition.
On
December 23, 2005 we entered into a joint venture agreement with Wind City
Oil
& Gas, LLC to form Wind Mill Oil & Gas, LLC to explore, drill and
develop certain oil and gas properties. As part of the agreement, Wind City
Oil
& Gas, LLC purchased 2,900,000 common shares for $4,350,000 on December 23,
2005. The stock purchase agreement contains a put whereby Wind City Oil &
Gas, LLC can put the stock back to us until September 30, 2006, thereby
requiring us to repurchase the 2,900,000 shares. If this were to occur, we
would
have a significant cashflow shortfall, which would require additional financing
arrangements and could impact our ability to continue as a going concern. There
is no assurance that such financing could be obtained on favorable terms, or
at
all. In such event, our financial condition could be adversely affected.
Our
business may fail if we do not succeed in our efforts to develop and replace
oil
and gas reserves.
Our
future success will depend upon our ability to find, acquire and develop
additional economically recoverable oil and gas reserves. Our proved reserves
will generally decline as they are produced, except to the extent that we
conduct revitalization activities, or acquire properties containing proved
reserves, or both. To increase reserves and production, we must continue our
development drilling and completion programs, identify and produce previously
overlooked or bypassed zones in shut-in wells, acquire additional properties
or
undertake other replacement activities. Our current strategy is to increase
our
reserve base, production and cash flow through the development of our existing
oil and gas fields and selective acquisitions of other promising properties
where we can use new, existing technology. Despite our efforts, our planned
revitalization, development and acquisition activities may not result in
significant additional reserves, and we may not be able to discover and produce
reserves at economical exploration and development costs. If we fail in these
efforts, our business may also fail.
Our
revenues may be less than expected if our oil and gas reserve estimates are
inaccurate.
Oil
and
gas reserve estimates and the present values attributed to these estimates
are
based on many engineering and geological characteristics as well as operational
assumptions that generally are derived from limited data. Common assumptions
include such matters as the anticipated future production from existing and
future wells, future development and production costs and the ultimate
hydrocarbon recovery percentage. As a result, oil and gas reserve estimates
and
present value estimates are frequently revised to reflect production data
obtained after the date of the original estimate. If reserve estates are
inaccurate, production rates may decline more rapidly than anticipated, and
future production revenues may be less than estimated. In addition, significant
downward revisions of reserve estimates may hinder our ability to borrow funds
in the future, or may hinder other financing arrangements that we may
consider.
In
addition, any estimates of future net revenues and their present value are
based
on period ending prices and on cost assumptions that only represent our best
estimate. If these estimates of quantities, prices and costs prove inaccurate
and we are unsuccessful in expanding our oil and gas reserves base, or if oil
and gas prices decline or become unstable, we may have to write down the
capitalized costs associated with our oil and gas assets. We will also largely
rely on reserve estimates when we acquire producing properties. If we
overestimate the potential oil and gas reserves of a property to be acquired,
or
if our subsequent operations on the property are not successful, the acquisition
of the property could result in substantial losses.
We
are implementing a growth strategy which, if successful, will place significant
demands on us and subject us to numerous risks.
Growing
businesses often have difficulty managing their growth. If our growth strategy
is successful, significant demands will be placed on our management, accounting,
financial, information and other systems and on our business. We will have
to
expand our management and continue recruiting and employing experienced
executives and key employees capable of providing the necessary support. In
addition, to manage our anticipated growth we will need to continue to improve
our financial, accounting, information and other systems in order to effectively
manage our growth, and in doing so could incur substantial additional expenses
that could harm our financial results. We cannot assure you that our management
will be able to manage our growth effectively or successfully, or that our
financial, accounting, information or other systems will be able to successfully
accommodate our external and internal growth. Our failure to meet these
challenges could materially impair our business.
We
may not be able to compete successfully in acquiring prospective reserves,
developing reserves, marketing oil and natural gas, attracting and retaining
quality personnel and raising additional capital.
Our
ability to acquire additional prospects and to find and develop reserves in
the
future will depend on our ability to evaluate and select suitable properties
and
to consummate transactions in a highly competitive environment. In addition,
there is substantial competition for capital available for investment in the
oil
and natural gas industry. Our inability to compete successfully in these areas
could have a material adverse effect on our business, financial condition or
results of operations.
A
substantial or extended decline in oil and natural gas prices could reduce
our
future revenue and earnings.
The
price
we receive for future oil and natural gas production will heavily influence
our
revenue, profitability, access to capital and rate of growth. Oil and natural
gas are commodities and their prices are subject to wide fluctuations in
response to relatively minor changes in supply and demand. Historically, the
markets for oil and natural gas have been volatile and currently oil and natural
gas prices are significantly above historic levels. These markets will likely
continue to be volatile in the future and current record prices for oil and
natural gas may decline in the future. The prices we may receive for any future
production, and the levels of this production, depend on numerous factors beyond
our control. These factors include the following:
|
·
|
changes
in global supply and demand for oil and natural
gas;
|
|
·
|
actions
by the Organization of Petroleum Exporting countries, or
OPEC;
|
|
·
|
political
conditions, including embargoes, which affect other oil-producing
activities;
|
|
·
|
levels
of global oil and natural gas exploration and production
activity;
|
|
·
|
levels
of global oil and natural gas
inventories;
|
|
·
|
weather
conditions affecting energy
consumption;
|
|
·
|
technological
advances affecting energy consumption;
and
|
|
·
|
prices
and availability of alternative
fuels.
|
Lower
oil
and natural gas prices may not only decrease our future revenues but also may
reduce the amount of oil and natural gas that we can produce economically.
A
substantial or extended decline in oil or natural gas prices may reduce our
earnings, cash flow and working capital.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties that could substantially increase our costs and reduce our
profitability.
Oil
and
natural gas exploration is subject to numerous risks beyond our control,
including the risk that drilling will not result in any commercially viable
oil
or natural gas reserves. Failure to successfully discover oil or natural gas
resources in properties in which we have oil and gas leases may materially
adversely affect our operations and financial condition.
The
total
cost of drilling, completing and operating wells will be uncertain before
drilling commences. Overruns in budgeted expenditures are common risks that
can
make a particular project uneconomical. Further, many factors may curtail,
delay
or cancel drilling, including the following:
|
·
|
delays
imposed by or resulting from compliance with regulatory
requirements;
|
|
·
|
pressure
or irregularities in geological
formations;
|
|
·
|
shortages
of or delays in obtaining equipment and qualified
personnel;
|
|
·
|
equipment
failures or accidents;
|
|
·
|
adverse
weather conditions;
|
|
·
|
reductions
in oil and natural gas prices;
|
|
·
|
land
title problems; and
|
|
·
|
limitations
in the market for oil and natural
gas.
|
Oil
and gas operations involve many physical hazards.
Natural
hazards, such as excessive underground pressures, may cause costly and dangerous
blowouts or make further operations on a particular well financially or
physically impractical. Similarly, the testing and completion of oil and gas
wells involves a high degree of risk arising from operational failures, such
as
blowouts, fires, pollution, collapsed casing, loss of equipment and numerous
other mechanical and technical problems. Any of these hazards may result in
substantial losses to us or liabilities to third parties. These could include
claims for bodily injuries, reservoir damage, loss of reserves, environmental
damage and other damages to people or property. Any successful claim against
us
would probably require us to spend large amounts on legal fees and any
successful claim may make us liable for substantial damages.
Our
dependence on outside equipment and service providers may hurt our
profitability.
We
need
to obtain logging equipment and cementing and well treatment services in the
area of our operations. Several factors, including increased competition in
the
area, may limit their availability. Longer waits and higher prices for equipment
and services may reduce our profitability.
The
oil and gas industry is highly competitive and there is no assurance that we
will be successful in acquiring any further leases.
The
oil
and gas industry is intensely competitive. We compete with numerous individuals
and companies, including major oil and gas companies, which have substantially
greater technical, financial and operational resources and staffs. Accordingly,
there is a high degree of competition for desirable oil and gas leases, suitable
properties for drilling operations and necessary drilling equipment, as well
as
access to funds. We cannot predict if the necessary funds can be raised. There
are also other competitors that have operations in our potential areas of
interest and the presence of these competitors could adversely affect our
ability to acquire additional leases.
If
we
lose the services of Deloy Miller, our operations may suffer.
We
are
substantially dependent upon the continued services of Deloy Miller, our CEO and
a director. Mr. Miller has been with us since our inception. The relationships
that he has formed in our industry and in the local area where our principal
operations are conducted are invaluable, and could be lost to us without his
services. Mr. Miller is in good health; however, his retirement, disability
or
death would seriously hurt our business operations. If his services become
unavailable, we will have to retain other qualified personnel. We may not be
able to recruit and hire another qualified person on acceptable terms. We do
not
have an employment contract with Mr. Miller. Similarly, the oil and gas
exploration industry requires the use of personnel with substantial technical
expertise. If our current technical personnel become unavailable, we will need
to hire qualified personnel to take their place. If we are not able to recruit
and hire new people on mutually acceptable terms, our operations will
suffer.
Oil
and gas operations are subject to comprehensive regulation which may cause
substantial delays or require capital outlays in excess of those anticipated,
causing an adverse effect on our Company.
Oil
and
gas operations are subject to federal, state, and local laws relating to the
protection of the environment, including laws regulating removal of natural
resources from the ground and the discharge of materials into the environment.
Oil and gas operations are also subject to federal, state, and local laws and
regulations which seek to maintain health and safety standards by regulating
the
design and use of drilling methods and equipment. Various permits from
government bodies are required for drilling operations to be conducted; no
assurance can be given that such permits will be received. Environmental
standards imposed by federal, provincial, or local authorities may be changed
and any such changes may have material adverse effects on our activities.
Moreover, compliance with such laws may cause substantial delays or require
capital outlays in excess of those anticipated, thus causing an adverse effect
on us. Additionally, we may be subject to liability for pollution or other
environmental damages. To date we have not been required to spend any material
amount on compliance with environmental regulations. However, we may be required
to do so in future and this may affect our ability to expand or maintain our
operations.
Risks
Related To Our Common Stock
The
limited trading volume in our common stock may depress our stock
price.
Our
common stock is currently traded on a limited basis on the Over-the-Counter
Bulletin Board (“OTCBB”). The quotation of our common stock on the OTCBB does
not assure that a meaningful, consistent and liquid trading market currently
exists. We cannot predict whether a more active market for our common stock
will
develop in the future. In the absence of an active trading market, investors
may
have difficulty buying and selling our common stock. Market visibility for
our
common stock may be limited. A lack of visibility of our common stock may have
a
depressive effect on the market price for our common stock.
The
issuance of shares upon exercise of outstanding warrants may cause immediate
and
substantial dilution of our existing shareholders.
The
issuance of shares upon exercise of warrants may result in substantial dilution
to the interests of other shareholders since the selling shareholders may sell
the full amount issuable on exercise. In addition, such shares would increase
the number of shares in the “public float” and could depress the market price
for our Common Stock.
If
we
fail to remain current on our reporting requirements, we could be removed from
the OTC Bulletin Board which would limit the ability of broker-dealers to sell
our securities and the ability of shareholders to sell their securities in
the
secondary market.
Companies
trading on the OTCBB, such as us, must be reporting issuers under Section 12
of
the Securities Exchange Act of 1934, as amended, and must be current in their
reports under Section 13, in order to maintain price quotation privileges on
the
OTCBB. If we fail to remain current on our reporting requirements, we could
be
removed from the OTCBB. As a result, the market liquidity for our securities
could be severely adversely affected by limiting the ability of broker-dealers
to sell our securities and the ability of shareholders to sell their securities
in the secondary market.
We
have never declared or paid cash dividends on our Common Stock. We currently
intend to retain future earnings to finance the operation, development and
expansion of our business.
We
do not
anticipate paying cash dividends on our Common Stock in the foreseeable future.
Payment of future cash dividends, if any, will be at the discretion of our
board
of directors and will depend on our financial condition, results of operations,
contractual restrictions, capital requirements, business prospects and other
factors that our board of directors considers relevant. Accordingly, investors
will only see a return on their investment if the value of our securities
appreciates.
New
legislation, including the Sarbanes-Oxley Act of 2002, may make it difficult
for
us to retain or attract officers and directors.
We
may be
unable to attract and retain qualified officers, directors and members of board
committees required to provide for our effective management as a result of
the
recent and currently proposed changes in the rules and regulations which govern
publicly-held companies. The enactment of the Sarbanes-Oxley Act of 2002 has
resulted in a series of rules and regulations by the Securities and Exchange
Commission that increase responsibilities and liabilities of directors and
executive officers. The perceived increased personal risk associated with these
recent changes may deter qualified individuals from accepting these roles.
Our
Common Stock is Subject to the "Penny Stock" Rules of the SEC and the Trading
Market in Our Securities is Limited, Which Makes Transactions in Our Stock
Cumbersome and May Reduce the Value of an Investment in Our Stock.
The
Securities and Exchange Commission has adopted Rule 15g-9 which establishes
the
definition of a "penny stock," for the purposes relevant to us, as any equity
security that has a market price of less than $5.00 per share or with an
exercise price of less than $5.00 per share, subject to certain exceptions.
For
any transaction involving a penny stock, unless exempt, the rules
require:
|
·
|
that
a broker or dealer approve a person’s account for transactions in penny
stocks; and
|
|
·
|
that
broker or dealer receives from the investor a written agreement to
the
transaction, setting forth the identity and quantity of the penny
stock to
be purchased.
|
In
order
to approve a person’s account for transactions in penny stocks, the broker or
dealer must:
|
·
|
obtain
financial information and investment experience objectives of the
person;
and
|
|
·
|
make
a reasonable determination that the transactions in penny stocks
are
suitable for that person and the person has sufficient knowledge
and
experience in financial matters to be capable of evaluating the risks
of
transactions in penny stocks.
|
The
broker or dealer must also deliver, prior to any transaction in a penny stock,
a
disclosure schedule prescribed by the Commission relating to the penny stock
market, which, in highlight form:
|
·
|
sets
forth the basis on which the broker or dealer made the suitability
determination; and
|
|
·
|
that
the broker or dealer received a signed, written agreement from the
investor prior to the transaction.
|
Generally,
brokers may be less willing to execute transactions in securities subject to
the
"penny stock" rules. This may make it more difficult for investors to dispose
of
our Common Stock and cause a decline in the market value of our stock.
Disclosure
also has to be made about the risks of investing in penny stocks in both public
offerings and in secondary trading and about the commissions payable to both
the
broker-dealer and the registered representative, current quotations for the
securities and the rights and remedies available to an investor in cases of
fraud in penny stock transactions. Finally, monthly statements have to be sent
disclosing recent price information for the penny stock held in the account
and
information on the limited market in penny stocks
Item
2 Description
of Property
Our
executive offices presently comprise approximately 6,300 square feet on 14
acres
of land in Huntsville, Tennessee that the company owns.
Oil
and Gas Leases
We
are an
exploration and production company that utilizes
seismic data, and other technologies for geophysical exploration and development
of oil and gas wells. In addition to our engineering and geological
capabilities, we have work-over rigs, dozers, roustabout crews and equipment
to
set pumping units, tanks and lay flow lines, winch trucks and trailers for
traveling support, backhoes, ditchers, fusion machines and welders for pipeline
and compression installation, as well as other equipment necessary to take
a
drilling program from the development stage to completion. The company also
sells rigs, oilfield trailers, compressors and other miscellaneous oil and
gas
production equipment. In addition to this equipment, our Wind Mill Joint Venture
has purchased a new Atlas Copco RD20 drilling rig, used RD 20 drilling rig
and
placed an order for two new SS185 Speed Star rigs to be delivered in December
2006.
Through
the Wind Mill Joint Venture, we are presently developing leases referred to
as
the Koppers North Field and Carden Tract to form 10,500 contiguous acres, the
Koppers South Field with 20,700 contiguous acres and the Lindsay Field with
3,400 contiguous acres. The Koppers, Carden and Lindsay Fields are in Campbell
County, Tennessee. Additionally, we are developing prospects in Roane County,
Tennessee to include 3,500 acres and 5,600 acres in Anderson County, Tennessee.
All of these prospects are located in the Appalachian Basin. In addition to
our
prospects in the Appalachian Basin, drilling has been completed to a total
depth
of 10,873 on the Hodnett #1 prospect in Brazoria County, Texas. This well is
located in the South Rowan Field.. There are no market restrictions in any
of
the mentioned areas.
In
Roane
County, the Eula Butler Et Al #1 and the Edwards - Fowler Unit # 1 has been
completed . The 2850 foot zone of the Edwards has been completed in the Trenton
where a 24 hour open flow test indicates natural gas flowing through a 3/8”
choke at 210 psi or about 750 mcfgd. We anticipate that production on this
well
will begin on August 14, 2006 and that future recovery of natural gas from
the
Edwards will be in excess of 500 MMcf. The Stonesriver section
in the Butler has not been that encouraging. We are currently considering
treating the same prolific Trenton zone as in the Edwards.
Lease
and Royalty Terms
The
following leases are held through our Wind Mill Joint Venture. We retained
our
working interest in the developed and producing wells which were located on
such
leases as of December 23, 2005. Through the Wind Mill Joint Venture
we hold half of the working interest in wells developed and producing subsequent
to December 23, 2005.
Koppers
Lease or "ARCO/GULF Farmout"
Located
in Campbell County in Tennessee, this is the largest acreage block we have
under
lease. This acreage was acquired through a farmout agreement with Atlantic
Richfield (“ARCO”), which has since merged into British Petroleum. We currently
own a 50% working interest in approximately 27,000 acres. This lease provides
for a landowner royalty of 12.5% and an overriding royalty interest of 7.5%
with
an 80% net royalty interest. The lease is split into two parcels. A 6,300 acre
northern parcel borders the Kentucky state line and a 20,700 acre parcel borders
the city of LaFollette, Tennessee. As of December 2005, there were ten producing
oil wells on the southern tract of this lease, consisting of Koppers 9b, 10b,
18b, 20b, 22b, 23b, 26b, 27b, 28b, 32b The ten wells have produced 170,881
barrels of oil from the “Big Lime” Formation through April 30, 2006. The Koppers
North and the Cardin tracts are producing gas from five wells in the “Devonian
Shale”. An extensive gathering system is in place to transport gas to the Delta
Natural Gas sales line. This lease remains in effect for as long as there is
production. We have leased and are currently leasing smaller tracts of 50 to
1,000 acres adjacent to or near the Koppers South Fields acreage. We will engage
in future development on this acreage through the Wind Mill Joint Venture.
Carden
Tract
This
lease includes 4,200 acres in which we have a 100% working interest and an
81.25% net royalty interest in wells developed and producing prior to December
23, 2005. This tract joins the Koppers North parcel of 6,300 acres to form
a
10,500 acre contiguous block in the north. The Koppers North and the Cardin
tracts are producing gas from five wells in the “Devonian Shale”. The lease has
a three-year term with a five well drilling commitment. As of December 2005,
three of these wells were drilled. Through the Wind Mill Joint
Venture,
the
Koppers #6A, 7A and Carden #1A, 2A & 3A were all drilled on the Koppers
North and Carden acreage to encompass a contiguous tract of 10,300 acres,
located in Campbell County, Tennessee. These wells were drilled in a blanketed
fault thickened Devonian Age Shale (Chattanooga Shale) to well depths of
approximately 3200’. Production casing has been run and the wells have been
stimulated. The wells have been producing since completion, with gas being
sold
through the Delta Natural Gas system.
Delta
Producers, Inc. Joint Venture
We
are
continuing our joint venture with Delta Producers, Inc. of Greenville,
Mississippi ("Delta Producers"). Currently, we are jointly producing ten gas
wells in the Jellico, Tennessee area northwest of the Pine Mountain Thrust
Fault. We have an average 33% working interest in these wells as well as
interest in several oil and gas leases consisting of approximately 2,000 acres
(collectively the "Delta Leases"). All of the Delta Leases are subject to a
12.5% landowner's royalty. These leases remain in effect for as long as there
is
production.
We
have
drilled nine wells with Delta Producers, the Lindsay Field #9, #10, #11, #12,
#13, #14, #15, #16 and #17 wells. The #11 well may not be completed. The #17
well is currently being completed and the #16 well will be completed considering
the results of #17. The remaining wells are all producing with gas being sold
to
the Powell-Clinch Utility District (“PCUD”), which serves the Harriman, Lake
City and Lafollette, Tennessee areas. The production of gas in the Lindsay
Field
is from the “Big Lime” Formation. We have a 40% working interest in the Lindsay
Field lease. The lease also provides for a landowner’s royalty of 12.5%. With
Delta Producers, we purchased and built more than four miles of three-inch
and
four-inch gathering lines to carry the gas to the market. This lease remains
in
effect for as long as there is production.
|
|
Date
Began
|
|
Amount
of Natural
|
|
|
Sales
of
|
|
Gas
Sold as of
|
Well
#
|
|
Natural
Gas
|
|
April
30, 2006 (Mcf)
|
9
|
|
03/02
|
|
104,186
|
10
|
|
01/03
|
|
32,709
|
11
|
|
*
|
|
*
|
12
|
|
03/02
|
|
217,969
|
13
|
|
08/03
|
|
47,993
|
14
|
|
08/03
|
|
32,466
|
15
|
|
11/03
|
|
29,011
|
16
|
|
*
|
|
*
|
17
|
|
*
|
|
394
|
*
This
well is awaiting completion.
Harriman
Prospect Joint Venture
The
Harriman Prospect Joint Venture includes several small leases in Roane County,
Tennessee with a total acreage of approximately 3,500 acres. The net royalty
interest is 87.5% with the landowners receiving a 12.5% royalty. We have a
50%
working interest in these leases. There are several smaller leases that expire
at different times. When drilled, as in the Butler and Edwards wells, they
will
be held by production. We will engage in future development on this prospect
through our Wind Mill joint Venture
Additional
Oil and Gas Leases and Wells
We
have
several small leases in Campbell, Fentress, Morgan and Overton Counties in
Tennessee totaling approximately 2,500 acres. Each of these leases is subject
to
a 12.5% to 20% landowner's royalty. As of April 30, 2006 there were eight
producing oil wells and eight producing natural gas wells on these leases that
have produced 175,789 barrels of oil and 796,233 Mcf of natural gas.
Oil
and
Gas Reserve Analyses
Our
estimated net proved oil and gas reserves and the present value of estimated
cash flows from those reserves are summarized below. The reserves were estimated
by Netherland Sewell and Associates, Inc., independent petroleum engineers,
in
accordance with regulations of the Securities and Exchange Commission, using
market or contract prices at the end of each of the years presented in the
consolidated financial statements. These prices were held constant over the
estimated life of the reserves.
Ownership
interests in estimated quantities of proved oil and gas reserves and changes
in
net proved reserves, all of which are located in the continental United States,
are summarized below for each of the years presented in the consolidated
financial statements.
|
|
Oil
(Bbls)
|
|
Gas
(Mcf)
|
|
Proved
reserves
|
|
|
|
|
|
Balance,
April 30, 2004
|
|
|
350,936
|
|
|
8,696,519
|
|
Discoveries
and extensions
|
|
|
35,400
|
|
|
220,000
|
|
[Revisions
of previous estimates]
|
|
|
(284,979
|
)
|
|
(7,592,419
|
)
|
Production
|
|
|
(7,532
|
)
|
|
(74,534
|
)
|
|
|
|
|
|
|
|
|
Balance
April 30, 2005
|
|
|
93,825
|
|
|
1,249,566
|
|
Discoveries
and extensions
|
|
|
-
|
|
|
73,980
|
|
[Revision
of previous estimates]
|
|
|
3,084
|
|
|
10,695
|
|
Production
|
|
|
(5,630
|
)
|
|
(60,914
|
)
|
|
|
|
|
|
|
|
|
Balance
April 30, 2006
|
|
|
91,279
|
|
|
1,273,327
|
|
|
|
|
|
|
|
|
|
Proved
developed producing reserves at April 30, 2006
|
|
|
58,188
|
|
|
686,580
|
|
|
|
|
|
|
|
|
|
Proved
developed producing reserves at April 30, 2005
|
|
|
60,734
|
|
|
697,916
|
|
Our
standardized measure of discounted future net cash flows from our estimated
proved oil and gas reserves is provided for the financial statement user as
a
common base for comparing oil and gas reserves of enterprises in the industry
and may not represent the fair market value of our oil and gas reserves or
the
present value of future cash flows of equivalent reserves due to various
uncertainties inherent in making these estimates. Those factors include changes
in oil and gas prices from year-end prices used in the estimates, unanticipated
changes in future production and development costs and other uncertainties
in
estimating quantities and present values of oil and gas reserves.
The
following table presents the standardized measure of discounted future net
cash
flows from our ownership interests in proved oil and gas reserves as of the
end
of each of the years presented in the consolidated financial statements. The
standardized measure of future net cash flows as of April 30, 2006 and 2005
are
calculated using weighted average process in effect as of those dates. Those
prices were $6.94 and $6.75 respectively, per Mcf of natural gas, and $61.75
and
$44.50 respectively, per barrel of oil. The resulting estimated future cash
inflows are reduced by estimated future costs to develop and produce the
estimated proved reserves based on year-end cost levels. Future income taxes
are
based on year-end statutory rates, adjusted for any operating loss carry
forwards and tax credits. The future net cash flows are reduced to present
value
by applying a 10% discount rate.
Standardized
measures of discounted future net cash flows at April 30, 2006 and 2005 are
as
follows:
|
|
2006
|
|
2005
|
|
Future
cash flows
|
|
$
|
14,470,000
|
|
$
|
12,747,600
|
|
Future
production costs and taxes
|
|
|
(1,898,000
|
)
|
|
(1,939,000
|
)
|
Future
development costs
|
|
|
(568,100
|
)
|
|
(745,000
|
)
|
Future
income tax expense
|
|
|
(3,721,209
|
)
|
|
(3,119,716
|
)
|
Future
cash flows
|
|
|
8,282,691
|
|
|
6,943,884
|
|
Discount
at 10% for timing of cash flows
|
|
|
(4,199,324
|
)
|
|
(3,463,248
|
)
|
Discounted
future net cash flows from proved reserves
|
|
$
|
4,083,367
|
|
$
|
3,480,636
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows
The
following table summarized the changes in the standardized measure of discounted
future net cash flows from estimated production of our proved oil and gas
reserves after income taxes for each of the years presented in the consolidated
financial statements.
The
following table sets forth the changes in the standardized measure of discounted
future net cash flows from proved reserves for April 30, 2006 and
2005.
|
|
April
30,
|
|
|
|
2006
|
|
2005
|
|
Balance,
beginning of year
|
|
$
|
3,480,636
|
|
$
|
23,149,947
|
|
Sales,
net of production costs and taxes
|
|
|
(721,440
|
)
|
|
(784,409
|
)
|
Changes
in prices and production costs
|
|
|
1,484,124
|
|
|
7,490,059
|
|
Revisions
of quantity estimates
|
|
|
264,640
|
|
|
(39,206,898
|
)
|
Development
costs incurred
|
|
|
176,900
|
|
|
3,995,000
|
|
Net
changes in income taxes
|
|
|
(601,493
|
)
|
|
8,836,937
|
|
Balances,
end of year
|
|
$
|
4,083,367
|
|
|
3,480,636
|
|
The
reserves presented in this Report were evaluated in accordance with Rule 4-10
of
Regulation S-X promulgated by the Securities and Exchange Commission
(“SEC”).
Item
3 Legal
Proceedings
None.
Item
4 Submission
of Matters to a Vote of Security Holders
No
proposals were submitted for approval by our shareholders during the fourth
quarter ended April 30, 2006.
PART
II
Item
5 Market
for Common Equity and Related Stockholder Matters
Market
Information
Our
common stock is quoted on the National Association of Securities Dealers
Over-the-Counter Bulletin Board (“OTCBB”) under the symbol “MILL.” The following
quotations, obtained from National Quotation Bureau,
reflect
the high and low bids for our shares for the periods indicated and are based
on
inter-dealer prices, without retail mark-up, mark-down or commission and may
not
represent actual transactions.
|
|
Bid
Prices ($)
|
|
|
|
High
|
|
Low
|
|
Quarter
Ended:
|
|
|
|
|
|
|
|
|
|
|
|
July
31, 2005
|
|
|
1.45
|
|
|
1.20
|
|
October
31, 2005
|
|
|
1.24
|
|
|
1.10
|
|
January
31, 2006
|
|
|
1.30
|
|
|
1.30
|
|
April
30, 2006
|
|
|
1.02
|
|
|
1.00
|
|
|
|
|
|
|
|
|
|
July
31, 2004
|
|
|
1.01
|
|
|
1.01
|
|
October
31, 2004
|
|
|
0.45
|
|
|
0.38
|
|
January
31, 2005
|
|
|
0.38
|
|
|
0.38
|
|
April
30, 2005
|
|
|
0.90
|
|
|
0.90
|
|
Holders
There
were approximately 385 stockholders of record of our common stock as of April
30, 2006.
Dividends
We
have
not paid or declared any cash dividends to date and do not anticipate paying
any
in the foreseeable future. There are no present restrictions that limit our
ability to pay dividends or that are likely to do so in the future. We intend
to
retain earnings, if any, to support the growth of our business.
Shares
Issuable Under Equity Compensation Plans
The
table
below provides information, as of April 30, 2006, concerning securities
authorized for issuance under equity compensation plans.
Plan
category
|
Number
of securities to be issued upon exercise of outstanding options,
warrants
and rights
|
Weighted
average exercise price of outstanding options, warrants and
rights
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
|
|
(a)
|
(b)
|
(c)
|
Equity
compensation plans approved by shareholders
|
--
|
--
|
--
|
Equity
compensation plans not approved by shareholders
|
150,000
|
0.8142
|
--
|
Total
|
150,000
|
0.8142
|
--
|
Recent
Sales of Unregistered Securities
None.
Share
Repurchases
None.
Item
6 Management’s
Discussion and Analysis or Plan of Operations
Introduction
The
following discussion is intended to facilitate an understanding of our business
and results of operations and includes forward-looking statements that reflect
our plans, estimates and beliefs. It should be read in conjunction with our
audited consolidated financial statements and the accompanying notes to the
consolidated financial statements included herein. Our actual results could
differ materially from those discussed in these forward-looking
statements.
Overview
We
are
actively engaged in the exploration, development, production and acquisition
of
crude oil and natural gas primarily in eastern Tennessee. In December 2005,
we
entered into a joint venture agreement with Wind City Oil & Gas, LLC (“Wind
City”) to form Wind Mill Oil & Gas, LLC (the “Wind Mill Joint Venture”). We
own 49.9% of the Wind Mill Joint Venture and Wind City owns 50.1%. We
contributed approximately 43,000 acres, which we held under lease in Tennessee,
to the Wind Mill Joint Venture for oil and gas exploration, development and
exploitation of undeveloped wells. Wind City contributed $10,000,000. The joint
venture will only encompass new drilling projects. We retained our working
interest in the developed and producing wells located on such leases. In
connection with the development of wells by the Wind Mill Joint Venture, we
will
also receive reimbursement for certain salaried employees and revenue for
providing labor and equipment. Including the leases that were contributed to
the
Wind Mill Joint Venture, we have approximately 50,000 acres under lease. About
90% of such leases are held by production.
Most
of
our current oil and gas production is from the Big Lime Formation. However,
there are more than 160 development drilling locations that target the Devonian
(Chattanooga Shale) as well as the Big Lime Formation. We completed the drilling
and fracing of the first five wells on Koppers North and Carden Prospect in
Campbell County, Tennessee, which consist of, the Koppers 6A and 7A and the
Carden 1A, 2A and 3A. The wells have been drilled to approximately 3,000 feet
in
depth to fully penetrate a thickened Devonian Shale, with up to 828 feet of
potential hydrocarbon entry. Gathering lines have been installed and the wells
are producing approximately 200 Mcf per month.
In
June
2001, we made a conventional Big Lime gas discovery, on the Lindsay Land Company
lease that we jointly own with Delta Producers, Inc. There are currently seven
producing wells on the property. Two wells were drilled in June 2005, the
Lindsay #16 and #17. These wells fully penetrated the Big Lime and Devonian
Shale to depths of approximately 4,700 feet. The Lindsay #17 has been foam
fraced in the Devonian Shale the Big Lime. The wells are producing approximately
2,000 Mcf per month. There are at a minimum twenty-three additional drill sites
on this 3,400 acre lease which is situated near Caryville, Tennessee. The
balance of this lease was assigned to the Wind Mill Joint Venture.
On
January 5, 2006, we drilled the Edwards/Fowler #1 gas well to 4,632 feet. This
well is the first well to be drilled under the Wind Mill Joint Venture pursuant
to which Wind Mill Oil & Gas, LLC will have a 25% net interest in the wells,
of which we will own 49.9%. In early June 2006 a twelve hour test produced
gas
flow at a rate of 1,127 Mcf per day. The well will be attached to the
Powell-Clinch gas line and is expected to begin producing at 200 to 250 Mcf
per
day. An additional well will be drilled on this lease in August
2006.
In
May
2006 the Wind Mill Joint Venture drilled the Hodnett #1 Prospect in Brazoria
County, Texas to a total depth of 10,873 ft. Production casing has been run
to
produce natural gas from 9,130 ft and oil from 8,600 ft and 8,800 ft zones.
The
well is still being tested and its status is not certain at this
time.
In
July
2006 the Wind Mill Joint Venture drilled three wells on Koppers South. All
three
wells were deemed to be commercial wells and the Koppers 38B drilled to 3,600
ft
has confirmed an open flow test of 720 Mcf of natural gas per day. We are
continuing to drill additional wells to prepare for production and to determine
the size of the field. To market the gas from the Koppers South field, a six
mile, six inch gas pipeline must be constructed to tie into the Powell-Clinch
pipeline. Approximately 90% of the right-of-ways for this pipeline have been
acquired and construction is expected to be completed by December
2006.
In
July
2006 two wells were drilled to 3,800 ft on the Lake City lease in Anderson
County, Tennessee. The early tests on these wells indicate that these wells
may
not be commercial wells.
We
are
continuing our leasing efforts in the Eastern Tennessee portion of the Eastern
Overthrust Belt, which runs from Eastern Canada through Appalachia into Alabama.
Acreage is being leased there in selected areas, which will be a part of the
Wind Mill Joint Venture.
Results
of Operations
For
the Fiscal Year Ended
|
|
Increase
/
|
|
|
|
|
|
|
|
April
30
|
|
|
|
(Decrease)
|
|
|
|
2006
|
|
2005
|
|
2005
to 2006
|
|
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas revenue
|
|
$
|
810,607
|
|
$
|
784,409
|
|
$
|
26,198
|
|
Service
and drilling revenue
|
|
|
1,728,165
|
|
|
245,627
|
|
|
1,482,538
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Revenue
|
|
|
2,538,772
|
|
|
1,030,036
|
|
|
1,508,736
|
|
COSTS
AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of oil and gas revenue
|
|
|
89,167
|
|
|
177,287
|
|
|
(88,120
|
)
|
Cost
of service and drilling revenue
|
|
|
1,523,376
|
|
|
82,730
|
|
|
1,440,646
|
|
Selling,
general and administrative
|
|
|
1,911,739
|
|
|
341,587
|
|
|
1,570,152
|
|
Salaries
and wages
|
|
|
161,583
|
|
|
262,453
|
|
|
(100,870
|
)
|
Plugged
and abandoned wells
|
|
|
624,255
|
|
|
624,255
|
|
|
|
|
Depreciation,
Depletion and amortization
|
|
|
376,461
|
|
|
366,279
|
|
|
10,182
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Costs and Expenses
|
|
|
4,686,581
|
|
|
1,230,336
|
|
|
3,456,245
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) FROM OPERATIONS
|
|
|
(2,147,809
|
)
|
|
(200,300
|
)
|
|
(1,947,509
|
)
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
959
|
|
|
875
|
|
|
84
|
|
Gain
on sale of equipment
|
|
|
157,562
|
|
|
(157,562
|
)
|
|
|
|
Interest
expense and financing cost
|
|
|
(1,443,084
|
)
|
|
(219,561
|
)
|
|
(1,223,523
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Other Income (Expense)
|
|
|
(1,442,125
|
)
|
|
(61,124
|
)
|
|
(1,381,001
|
)
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
$
|
(3,589,934
|
)
|
$
|
(261,424
|
)
|
$
|
(3,328,510
|
)
|
Revenue
Oil
and
gas revenue was $810,607 for the year ended April 30, 2006 as compared to
$784,409 for the year ended April 30, 2005, an increase of $26,198. This
resulted primarily from an increase in the price of oil and gas.
Service
and drilling revenue was $1,728,165 for the year ended April 30, 2006 as
compared to $245,627 for the year ended April 30, 2005, an increase of
$1,482,538. This resulted from an increase in drilling activity with Norwest
Energy, NL of Perth, Australia and Golden Triangle Energy of Houston, Texas
in
the amount of $1,175,000.
Cost
and Expense
The
cost
of oil and gas revenue was $89,167 for the year ended April 30, 2006 as compared
to $177,827 for the year ended April 30, 2005, a decrease of $88,660. This
decrease resulted from the fact that several oil wells were rehabilitated during
the year ended April 30, 2005.
The
cost
of service and drilling revenue was $1,523,376 for the year ended April 30,
2006
as compared to $82,730 for the year ended April 30, 2005, an increase of
$1,440,646. This increase is due to the increase in drilling activities with
Norwest Energy, NL of Perth, Australia and Golden Triangle Energy of Houston,
Texas.
Selling,
general and administrative expense was $1,911,739 for the year ended April
30,
2006 as compared to $341,587 for the year ended April 30, 2005, an increase
of
$1,570,152. This increase resulted from an increase in stock compensation of
approximately $931,000, increased legal and professional fees of approximately
$360,000, and a general increase in selling, general and administrative
expense.
Salaries
and wages expense was $161,583 for the year ended April 30, 2006 as compared
to
$262,453 for the year ended April 30, 2005, a decrease of $100,870. This
decrease resulted from the addition of new employees, less cost being
capitalized in lease acquisitions, and the reimbursement by Wind Mill of
$276,491 of salaries during the year ended April 30, 2006.
Depreciation,
depletion and amortization expense was $376,461 for the year ended April 30,
2006 as compared to $366,279 for the year ended April 30, 2005, an increase
of
$10,182. This increase resulted from more wells and equipment being placed
into
service.
There
was
no gain on the sale of equipment for the year ended April 30, 2006 as compared
to a gain of $157,562 for the year ended April 30, 2005, a decrease of $157,562.
The gain for the year ended April 30, 2005 resulted from the sale of a drilling
rig. There were no sales of equipment during the year ended April 30,
2006.
Interest
expense and financing cost was $1,443,084 for the year ended April 30, 2006
as
compared to $219,561 for the year ended April 30, 2005, an increase of
$1,223,523. This resulted from increased interest cost, loan cost, warrants
and
penalty warrants associated with loans.
|
|
Average
Net Production
|
|
|
|
Fiscal
Year
|
|
Gas
/ MBTU
|
|
Sales
Price / MBTU
|
|
2005
|
|
|
75,000
|
|
$
|
6.28
|
|
2006
|
|
|
60,914
|
|
|
6.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal
Year
|
|
|
Barrels
of Oil
|
|
|
Sales
Price
|
|
2005
|
|
|
7,500
|
|
$
|
40.48
|
|
2006
|
|
|
5,630
|
|
|
61.75
|
|
|
|
|
|
|
|
|
2004
|
|
2005
|
|
2006
|
Net
Productive Wells
|
20.20
|
|
20.20
|
|
22.84
|
Developed
Acreage
|
1,480
|
|
1,480
|
|
1,840
|
Undeveloped
Acreage
|
41,120
|
|
41,120
|
|
46,920
|
Net
Productive Exploratory Wells
|
0
|
|
0
|
|
0
|
Net
Dry Exploratory Wells
|
0.30
|
|
0.30
|
|
0.25
|
Net
Productive Developmental Wells
|
1.420
|
|
1.20
|
|
2.64
|
Net
Dry Developmental Wells
|
0
|
|
0
|
|
0
|
Liquidity
Cash
used
by operating activities was $1,921,555 for fiscal 2006, a reduction of
$2,076,135 from cash provided by operating activities in fiscal 2005 of
$154,580. Our principal source of liquidity has been oil and gas revenues,
loans
from related parties and directors, private placement transactions of our common
stock, and participation with investors in various oil and gas wells. The
increase in oil and gas prices and the fact that we have approximately 50,000
acres under lease in Tennessee enhances our ability to attract investors and
to
pursue joint ventures in oil and gas. This is reflected by the our entry into
a
convertible loan on May 9, 2005 for $4,150,000, secured by our assets which
paid
off most of our liabilities and provided approximately $800,000 for operations
and drilling and completing oil and gas wells. Also, during May and June of
2005
we received $1,175,000 as a part of our joint venture with GTE and Norwest
for
the initial drilling and completion of five (5) wells.
On
December 23, 2005 we entered into the Wind Mill Oil & Gas LLC Agreement
(“Wind Mill”) and also sold 2,900,000 shares of common stock to Wind City Oil
& Gas, LLC (“Wind City”) for $4,350,000. These funds were used to pay off
the $4,150,000 of loans and to provide some working capital. Wind City also
contributed $10,000,000 to Wind Mill and we contributed oil and gas leases
as
part of the Wind Mill agreement. For the year ended April 30, 2006 we received
$276,491 of administrative salary reimbursements and revenue of $153,096 for
various labor, parts and use of equipment. The continued receipt of salary
reimbursements and revenue from Wind Mill is a significant factor in our cash
flow as we are completing wells to obtain revenue. The anticipated completion
of
the pipeline for Koppers South in December 2006, should increase the sale of
gas
significantly.
Our
long-term cash flows are subject to a number of variables including the level
of
production and prices as well as various economic conditions that have
historically affected the oil and gas business. A material drop in oil and
gas
prices or a reduction in production and reserves would reduce our ability to
fund capital expenditures, reduce debt, meet financial obligations and remain
profitable. We operate in an environment with numerous financial and operating
risks, including, but not limited to, the inherent risks of the search for,
development and production of oil and gas, the ability to buy properties and
sell production at prices which provide an attractive return and the highly
competitive nature of the industry. Our ability to expand our reserve base
is,
in part, dependent on obtaining sufficient capital through internal cash flow
or
the issuance of debt or equity securities. There can be no assurance that
internal cash flow and other capital sources will provide sufficient funds
to
maintain capital expenditures that we believe are necessary to offset future
declines in production and proved reserves.
Item
7
Financial Statements
INDEX
TO
FINANCIAL STATEMENTS
Report
of Independent Certified Public Accountants
|
25
|
|
|
Consolidated
Balance Sheet
|
26-27
|
|
|
Consolidated
Statements of Operations
|
28
|
|
|
Consolidated
Statements of Stockholders' Equity
|
29
|
|
|
Consolidated
Statements of Cash Flows
|
30
|
|
|
Notes
to the Consolidated Financial Statements
|
31-46
|
MILLER
PETROLEUM, INC.
CONSOLIDATED
FINANCIAL STATEMENTS
April
30,
2006 and 2005
REPORT
OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board
of
Directors Miller Petroleum, Inc. and Subsidiary
Huntsville,
Tennessee
We
have
audited the accompanying consolidated balance sheets of Miller Petroleum, Inc.
and its subsidiary as of April 30, 2006 and April 30, 2005 and the related
consolidated statements of operations, changes in stockholders’ equity and cash
flows for the years then ended. These consolidated financial statements are
the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated 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 audits to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. The Company
has determined that it is not required to have, nor was it engaged to perform,
an audit of internal control over financial reporting. Our audits included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Company’s
internal control over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as
well
as evaluating the overall financial statement presentation. We believe that
our
audits provide a reasonable basis for our opinion.
In
our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Miller Petroleum, Inc.
and
its Subsidiary as of April 30, 2006 and 2005, and the results of its operations
and cash flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.
The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern. As discussed in Note 1 to the financial
statements, the Company has suffered recurring losses from operations, and
$2,900,000 of the Company’s common stock is subject to a put option, which the
Company does not have the current capability of funding. This raises substantial
doubt about the Company’s ability to continue as a going concern. The financial
statements do not include any adjustments that might result from the outcome
of
this uncertainty.
/s/
Rodefer Moss & Co, PLLC
Knoxville,
Tennessee
August
15, 2006
Miller
Petroleum, Inc.
Consolidated
Balance Sheets
|
|
April
30,
|
|
April
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
|
|
$
|
$2,362
|
|
Accounts
receivable
|
|
|
311,286
|
|
|
182,951
|
|
Accounts
receivable - related parties
|
|
|
347,060
|
|
|
|
|
Note
receivable
|
|
|
43,000
|
|
|
47,000
|
|
Inventory
|
|
|
97,388
|
|
|
67,389
|
|
Unbilled
service and drilling costs
|
|
|
76,944
|
|
|
|
|
Deferred
offering costs
|
|
|
|
|
|
88,842
|
|
Total
Current Assets
|
|
|
875,678
|
|
|
388,544
|
|
|
|
|
|
|
|
|
|
FIXED
ASSETS
|
|
|
|
|
|
|
|
Machinery
|
|
|
880,904
|
|
|
941,601
|
|
Vehicles
|
|
|
321,895
|
|
|
333,583
|
|
Buildings
|
|
|
315,835
|
|
|
313,335
|
|
Office
equipment
|
|
|
23,028
|
|
|
72,549
|
|
|
|
|
1,541,662
|
|
|
1,661,068
|
|
Less:
accumulated depreciation
|
|
|
(782,971
|
)
|
|
(939,579
|
)
|
|
|
|
|
|
|
|
|
Net
Fixed Assets
|
|
|
758,691
|
|
|
721,489
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL
AND GAS PROPERTIES
|
|
|
1,576,950
|
|
|
2,941,832
|
|
(On
the basis of successful efforts accounting)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIPELINE
FACILITIES
|
|
|
193,948
|
|
|
206,298
|
|
|
|
|
|
|
|
|
|
OTHER
ASSETS
|
|
|
|
|
|
|
|
Investment
in joint venture at cost
|
|
|
801,319
|
|
|
|
|
Land
|
|
|
496,500
|
|
|
496,500
|
|
Investments
|
|
|
500
|
|
|
500
|
|
Well
equipment and supplies
|
|
|
440,712
|
|
|
431,462
|
|
Cash
- restricted
|
|
|
83,000
|
|
|
71,000
|
|
|
|
|
|
|
|
|
|
Total
Other Assets
|
|
|
1,822,031
|
|
|
999,462
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
5,227,298
|
|
$
|
5,257,625
|
|
See
notes
to consolidated financial statements.
Miller
Petroleum, Inc.
Consolidated
Balance Sheets
|
|
April
30,
|
|
April
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
LIABILITIES,
TEMPORARY EQUITY
|
|
|
|
|
|
AND
PERMANENT STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
Bank
overdraft
|
|
$
|
27,253
|
|
$
|
-
|
|
Accounts
payable - trade
|
|
|
305,494
|
|
|
330,620
|
|
Accrued
expenses
|
|
|
43,189
|
|
|
224,306
|
|
Current
portion of notes payable
|
|
|
16,636
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Total
Current Liabilities
|
|
|
392,572
|
|
|
554,926
|
|
|
|
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
payable
|
|
|
|
|
|
|
|
Related
parties
|
|
|
-
|
|
|
1,673,693
|
|
Other
|
|
|
323,898
|
|
|
655,646
|
|
|
|
|
|
|
|
|
|
Total
Long-Term Liabilities
|
|
|
323,898
|
|
|
2,329,339
|
|
|
|
|
|
|
|
|
|
Total
Liabilities
|
|
|
716,470
|
|
|
2,884,265
|
|
|
|
|
|
|
|
|
|
TEMPORARY
EQUITY
|
|
|
|
|
|
|
|
Common
stock subject to put rights; 2,900,000
|
|
|
|
|
|
|
|
and
0 shares, respectively
|
|
|
4,350,000
|
|
|
-
|
|
|
|
|
|
|
|
|
|
PERMANENT
STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock: 500,000,000 shares authorized
|
|
|
|
|
|
|
|
at
$0.0001 par value, 11,466,856 and 9,396,856
|
|
|
|
|
|
|
|
shares
issued and outstanding
|
|
|
1,146
|
|
|
939
|
|
Additional
paid-in capital
|
|
|
6,624,683
|
|
|
4,495,498
|
|
Unearned
compensation
|
|
|
(751,990
|
)
|
|
|
|
Accumulated
deficit
|
|
|
(5,713,011
|
)
|
|
(2,123,077
|
)
|
|
|
|
|
|
|
|
|
Total
Stockholders’ Equity
|
|
|
160,828
|
|
|
2,373,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES, TEMPORARY EQUITY
|
|
|
|
|
|
|
|
AND
PERMANENT STOCKHOLDERS’ EQUITY
|
|
$
|
5,227,298
|
|
$
|
5,257,625
|
|
See notes to consolidated financial statements.
Miller
Petroleum, Inc.
Consolidated
Statements of Operations
|
|
For
the
|
|
For
the
|
|
|
|
Year
Ended
|
|
Year
Ended
|
|
|
|
April
30,
|
|
April
30,
|
|
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Oil
and gas revenue
|
|
$
|
810,607
|
|
$
|
784,409
|
|
Service
and drilling revenue
|
|
|
1,728,165
|
|
|
245,627
|
|
|
|
|
|
|
|
|
|
Total
Revenue
|
|
|
2,538,772
|
|
|
1,030,036
|
|
|
|
|
|
|
|
|
|
COSTS
AND EXPENSES
|
|
|
|
|
|
|
|
Oil
and gas cost
|
|
|
89,167
|
|
|
177,287
|
|
Service
and drilling cost
|
|
|
1,523,376
|
|
|
82,730
|
|
Selling,
general and administrative
|
|
|
2,073,322
|
|
|
604,040
|
|
Impairment
loss - plugged and abandoned wells
|
|
|
624,255
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
376,461
|
|
|
366,279
|
|
|
|
|
|
|
|
|
|
Total
Costs and Expenses
|
|
|
4,686,581
|
|
|
1,230,336
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS)
|
|
|
|
|
|
|
|
FROM
OPERATIONS
|
|
|
(2,147,809
|
)
|
|
(200,300
|
)
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
Interest
income
|
|
|
959
|
|
|
875
|
|
Gain
on sale of equipment
|
|
|
|
|
|
157,562
|
|
Interest
expense and financing cost
|
|
|
(1,443,084
|
)
|
|
(219,561
|
)
|
|
|
|
|
|
|
|
|
Total
Other Expense
|
|
|
(1,442,125
|
)
|
|
(61,124
|
)
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
LOSS
|
|
$
|
(3,589,934
|
)
|
$
|
(261,424
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
AND DILUTED LOSS PER SHARE
|
|
$
|
(0.33
|
)
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
BASIC
WEIGHTED AVERAGE NUMBER
|
|
|
|
|
|
|
|
OF
SHARES OUTSTANDING
|
|
|
10,812,774
|
|
|
9,030,738
|
|
See notes to consolidated financial statements.
MILLER
PETROLEUM, INC.
Consolidated
Statements of Permanent Stockholders’ Equity
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
Common
|
|
Shares
|
|
Paid-in
|
|
Unearned
|
|
Accumulated
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Compensation
|
|
Deficit
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
April 30, 2004
|
|
|
8,378,856
|
|
$
|
838
|
|
$
|
4,173,998
|
|
$ |
|
|
$
|
$(1,861,653
|
)
|
$
|
2,313,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of restricted shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
for
cash at discounts from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
market
for free-trading
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
shares
|
|
|
275,000
|
|
|
|
|
|
79,974
|
|
|
|
|
|
-
|
|
|
80,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of restricted shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
for
services at prevailing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
discounts
from market for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
free
trading shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113,000
|
|
|
11
|
|
|
42,589
|
|
|
|
|
|
|
|
|
42,600
|
|
Issuance
of restricted shares for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
leasehold
interests in mineral rights
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
at
prevailing discount from market
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
price
for free-trading shares
|
|
|
500,000
|
|
|
|
|
|
105,950
|
|
|
|
|
|
-
|
|
|
106,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of shares for cash
|
|
|
20,000
|
|
|
2
|
|
|
15,998
|
|
|
|
|
|
|
|
|
16,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of shares for services
|
|
|
110,000
|
|
|
11
|
|
|
76,989
|
|
|
|
|
|
|
|
|
77,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss for the year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ended
April 30, 2005
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
(261,424
|
)
|
|
(261,424
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
April 30, 2005
|
|
|
9,396,856
|
|
|
|
|
|
|
|
|
|
|
|
(2,123,077
|
)
|
|
2,373,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of warrants as
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
prepayment
of financing costs
|
|
|
|
|
|
|
|
|
370,392
|
|
|
|
|
|
|
|
|
370,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of warrants for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
financing
cost penalty
|
|
|
|
|
|
|
|
|
66,000
|
|
|
|
|
|
|
|
|
66,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of shares as payment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
for
services
|
|
|
1,650,000
|
|
|
|
|
|
1,682,835
|
|
|
|
)
|
|
|
|
|
931,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of shares for stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
sales
commission
|
|
|
400,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
460,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of stock sales
|
|
|
|
|
|
|
|
|
(460,000
|
) |
|
|
|
|
|
|
|
(460,000
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
of warrants
|
|
|
20,000
|
|
|
2
|
|
|
9,998
|
|
|
|
|
|
|
|
|
10,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss for the year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ended
April 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,589,934
|
)
|
|
(3,589,934
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
April 30, 2006
|
|
|
11,466,856
|
|
$
|
1,146
|
|
$
|
6,624,683
|
|
$
|
(751,990
|
)
|
$
|
(5,713,011
|
)
|
$
|
160,828
|
|
See notes to consolidated financial statements.
Miller
Petroleum, Inc.
Consolidated
Statements of Cash Flows
|
|
April
30,
|
|
April
30,
|
|
|
|
2006
|
|
2005
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
loss
|
|
$
|
(3,589,934
|
)
|
$
|
(261,424
|
)
|
Adjustments
to Reconcile Net Loss to
|
|
|
|
|
|
|
|
Net
Cash from Operating Activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
376,461
|
|
|
393,061
|
|
Gain
on sale of equipment
|
|
|
|
|
|
(157,562
|
)
|
Impairment
loss - plugged and abandoned wells
|
|
|
624,255
|
|
|
|
|
Options
issued in exchange for services
|
|
|
436,392
|
|
|
|
|
Common
Stock issued in exchange for services
|
|
|
931,010
|
|
|
119,600
|
|
Write
off offering cost
|
|
|
88,842
|
|
|
|
|
Changes
in Operating Assets and Liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(475,395
|
)
|
|
(65,784
|
)
|
Inventory
|
|
|
(29,999
|
)
|
|
(16,478
|
)
|
Unbilled
service and drilling costs
|
|
|
(76,944
|
)
|
|
|
|
Prepaid
expenses
|
|
|
|
|
|
39,808
|
|
Bank
overdraft
|
|
|
27,253
|
|
|
|
|
Accounts
payable
|
|
|
(25,126
|
)
|
|
(4,936
|
)
|
Accrued
expenses
|
|
|
(181,117
|
)
|
|
108,295
|
|
|
|
|
|
|
|
|
|
Net
Cash from Operating Activities
|
|
|
(1,894,302
|
)
|
|
154,580
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Proceeds
from sale of land
|
|
|
|
|
|
15,000
|
|
Purchase
of equipment
|
|
|
(139,106
|
)
|
|
(1,500
|
)
|
Purchase
of oil and gas properties
|
|
|
(335,905
|
)
|
|
(386,687
|
)
|
Proceeds
from sale of equipment
|
|
|
|
|
|
187,682
|
|
Increase
in restricted cash
|
|
|
(12,000
|
)
|
|
|
|
Changes
in note receivable
|
|
|
4,000
|
|
|
28,125
|
|
|
|
|
|
|
|
|
|
Net
Cash from Investing Activities
|
|
|
(483,011
|
)
|
|
(157,380
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Proceeds
from issuance of stock
|
|
|
4,360,000
|
|
|
96,001
|
|
Payments
on Notes Payables
|
|
|
(6,135,049
|
)
|
|
(137,716
|
)
|
Proceeds
from borrowings
|
|
|
4,150,000
|
|
|
44,461
|
|
|
|
|
|
|
|
|
|
Net
Cash from Financing Activities
|
|
|
2,374,951
|
|
|
2,746
|
|
|
|
|
|
|
|
|
|
NET
DECREASE IN CASH
|
|
|
(2,362
|
)
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS, BEGINNING OF YEAR
|
|
|
2,362
|
|
|
2,416
|
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS, END OF YEAR
|
|
$
|
-
|
|
$
|
2,362
|
|
See
notes
to consolidated financial statements.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
1 -
BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS
a. Organization
and Basis of Presentation
These
consolidated financial statements include the accounts of Miller Petroleum,
Inc.
and the accounts of its subsidiary, Miller Pipeline Company, Inc. All
inter-company balances have been eliminated in consolidation.
The
Company’s principal business consists of oil and gas exploration, production and
related property management in the Appalachian region of eastern Tennessee
and
in the state of Texas. The Company’s corporate offices are in Huntsville,
Tennessee. The Company operates as one reportable business segment, based on
the
similarity of activities
The
Company formed Miller Pipeline Corporation Inc. (“MPC, Inc.”), a wholly-owned
subsidiary, to manage the construction and operation of the gathering system
used to transport natural gas to market.
b. Continuing
Operations
The
Company has incurred recurring losses over the past several years, and 2,900,000
shares of the Company’s common stock is subject to a put provision whereby a
major stockholder and joint venture partner can put the stock back to the
Company if notification is given thirty (30) days prior to September 30, 2006.
As
discussed further in Note 2, Wind City Oil & Gas, LLC has an unwind
provision in their stock purchase agreement whereby they can put the stock
back
to the Company if notification is given thirty days prior to September 30,
2006.
If the stockholder should exercise the put option, the Company would have to
repurchase the stock for $4,350,000 (2,900,000 shares at $1.50/share).
Currently, the Company does not have the financial resources to repurchase
the
stock. In the event the put is exercised, the Company will attempt to obtain
other investors or a loan to repay Wind City Oil & Gas, LLC for the
stock.
Management
is taking the following steps to improve the Company’s financial
performance:
The
Company, through Wind Mill Oil & Gas, LLC, has made gas discoveries in the
Koppers South field and needs to complete a gas pipeline to the Powell-Clinch
pipeline to sell the gas. All rights-of-way except one have been acquired for
the pipeline and it is expected to be completed by December 2006 or January
2007. The completion of the pipeline and the revenue from selling the gas is
expected to have a positive impact on the Company’s cash flow.
The
operating agreement with Wind Mill restricts the Company’s ability to enter into
drilling agreements with other parties and commits all our undeveloped acreage
to the Wind Mill Joint Venture. Also, the Wind Mill agreement, as currently
constituted, provides for ongoing exploration and drilling, activities for
which
the Company realizes substantial revenues and cost reimbursements. Under the
Wind Mill agreement the Company believes it has addressed its operational
difficulties, and the Company would expect to structure any future joint
ventures in replacement of Wind Mill so that the Company’s future operations
were similarly addressed. The Company has received a number of requests to
participate in other drilling ventures, and in the event the put is exercised
the Company will pursue other joint ventures.
However,
if substantial losses continue or if we are unable to raise sufficient
additional capital through debt and equity offerings, liquidity problems will
cause us to curtail operations, liquidate or sell assets or entities or pursue
other actions that could adversely affect future operations. These factors
raise
substantial doubt about our ability to continue as a going concern. These
financial statements do not include any adjustments that could be required
if
the company was unable to continue as a going concern.
c. Accounting
Method
The
Company follows the successful efforts method of accounting for its oil and
gas
activities. Accordingly, costs associated with the acquisition, drilling and
equipping of successful exploratory wells are capitalized. Geological and
geophysical costs, delay and surface rentals and drilling costs of unsuccessful
exploratory wells are charged to expense as incurred. Costs of drilling
development wells are capitalized. Upon the sale or retirement of oil and gas
properties, the cost thereof and the accumulated depreciation or depletion
are
removed from the accounts and any gain or loss is credited or charged to
operations.
Depreciation,
depletion and amortization of capitalized costs of proved oil and gas properties
is provided on a pooled basis using the units-of-production method based upon
proved reserves. Acquisition costs of proved properties are amortized by using
total estimated units of proved reserves as the denominator. All other costs
are
amortized using total estimated units of proved developed reserves.
Pipeline
and facilities are stated at original cost. Depreciation of pipeline and
facilities is provided on a straight-line basis over the estimated useful life
of the pipeline of forty years.
d. Impairment
of Long-Lived Assets and Long-Lived Assets to Be Disposed Of
SFAS
144,
“Accounting for the Impairment or Disposal of Long-Lived Assets,” requires that
an asset be evaluated for impairment when the carrying amount of an asset
exceeds the sum of the undiscounted estimated future cash flows of the asset.
In
accordance with the provisions of SFAS 144, the Company reviews the carrying
values of its long-lived assets 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 we 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
using discount rates commensurate with the risks involved in the asset group.
The long-lived assets of the Company, which are subject to evaluation, consist
primarily of oil and gas properties. For the year ended April 30, 2006 the
Company expensed $624,255 for impairment in connection with its assessment
of
remaining properties following the assignment of leases to Wind Mill Oil &
Gas, LLC as discussed in Note 2.
e. Net
earnings (loss) per share:
The
Company presents “basic” earnings (loss) per share and, if applicable, “diluted”
earnings per share pursuant to the provisions of Statement of Financial
Accounting Standards No. 128, “Earnings Per Share” Basic earnings (loss) per
share is calculated by dividing net income or loss by the weighted average
number of common shares outstanding during each period. The calculation of
diluted earnings per share is similar to that of basic earnings per share,
except that the denominator is increased to include the number of additional
common shares that would have been outstanding if all potentially dilutive
common shares, such as those issuable upon the exercise of stock options and
warrants, were issued during the period.
Since
the
Company had a net loss for the years ended April 30, 2006 and 2005, the assumed
effects of the exercise of the options and warrants to purchase 1,550,000 and
540,000 shares of common stock that were outstanding at April 30, 2006 and
2005,
respectively, and the application of the treasury stock method would have been
anti-dilutive. Therefore, there are no diluted per share amounts in the 2006
and
2005 statements of operations.
f. Cash
Equivalents
The
Company considers all highly liquid investments with a maturity of three months
or less when purchased to be cash equivalents.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
1 -
BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS
(Continued)
g. Principles
of Consolidation
The
consolidated financial statements include the accounts of the Company, and
its
wholly-owned subsidiary MPC, Inc. All significant intercompany transactions
have
been eliminated.
h. Fixed
Assets
Fixed
assets are stated at cost. Depreciation and amortization are computed using
the
straight-line method for financial reporting purposes and accelerated methods
for income tax purposes. The estimated useful lives are as follows:
|
|
Lives
|
Class |
|
(Years)
|
Building |
|
40
|
Machinery and equipment |
|
5-20
|
Vehicles |
|
5-7
|
Office equipment |
|
5
|
Depreciation
expense for the years ended April 30, 2006 and 2005 was $101,248 and $120,419
respectively.
i. Revenue
Recognition
Oil
and
gas production revenue is recognized as income as production is extracted and
sold. Service and drilling income is recognized at the time it is both earned
and we have a contractual right to receive the revenue. Turnkey contracts not
completed at year end are reported on the completed contract method of
accounting. There were no uncompleted contracts at the end of fiscal 2006 and
2005. Retail sales of various parts and equipment is immaterial for the years
ended April 30, 2006 and 2005 and has been combined with service and drilling
revenue.
j. Concentrations
of Credit Risk
Financial
instruments which potentially subject the Company to concentrations of credit
risk are primary cash and cash equivalents and accounts receivable. The Company
places its cash investments, which at times may exceed federally insured
amounts, in highly rated financial institutions.
Accounts
receivable arise from sales of gas and oil, equipment and services. Credit
is
extended based on the evaluation of the customer’s creditworthiness, and
generally collateral is not required. Accounts receivable more than 45 days
old
are considered past due. The Company does not accrue late fees or interest
income on past due accounts. Management uses the aging of accounts receivable
to
establish an allowance for doubtful accounts. Credit losses are written off
to
the allowance at the time they are deemed not to be collectible. Credit losses
have historically been minimal and within management’s expectations. The
allowance for doubtful accounts was $5,183 and $6,944 at April 30, 2006 and
2005, respectively. Accounts receivable more than 90 days old were $58,503
at
April 30, 2006 and $ 32,498 at April 30, 2005. Bad debt expense for the year
ended April 30, 2006 was $14,659
k. Inventory
Inventory
consists primarily of crude oil in tanks and is carried at market
value.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
1 -
BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS
(Continued)
l. Well
Equipment and Supplies
Well
equipment represent equipment held by the Company and is carried at salvage
value. When well equipment is acquired by the Company in basket purchases,
the
cost is applied only to the marketable portion of the equipment.
m. 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 on the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates. The most significant assumptions are for asset retirement
obligation liabilities and estimated reserves of oil and gas. Oil and gas
reserve estimates are developed from information provided by the Company’s
management to Netherland Sewell and Associates, Inc., of Dallas Texas (“NSAI”)
for the years ended April 30, 2006 and 2005, respectively. In 2005, management’s
estimate of its proved reserves was revised downward from approximately 350,000
barrels of oil to about 94,000, and its proved reserves estimates for natural
gas were revised from about 8,700,000 thousand cubic feet (“Mcf”) to about
1,200,000 Mcf. This revision was the result primarily of NSAI’s reclassification
of proved reserves to probable and possible reserves. While reserves are not
reflected on the Company’s balance sheet, the revision in estimate did affect
the 2005 depletion expense associated with its oil and gas properties, which
is
calculated on the basis of proved reserves only. The change was accounted for
as
a revision in an estimate, and the effect on net income was approximately
$160,000 or $0.02 per basic diluted share of common stock.
n. Reclassifications
Certain
amounts and balances pertaining to the April 30, 2005 financial statements
have
been reclassified to conform with the April 30, 2006 financial statement
presentations.
o. Stock
Warrants
The
Company measures its equity transactions with non-employees using the fair
value
based method of accounting prescribed by Statement of Financial Accounting
Standards No. 123. The Company continues to use the intrinsic value approach
as
prescribed by APB Opinion No. 25 in measuring equity transactions with
employees.
p. Income
Taxes
The
Company accounts for income taxes using the “asset and liability method.”
Accordingly, deferred tax liabilities and assets are determined based on the
temporary differences between the financial reporting and tax basis of assets
and liabilities, using enacted tax rates in effect for the year in which the
differences are expected to reverse. Deferred tax assets arise primarily from
net operating loss carry forwards. Management evaluates the likelihood of
realization of such assets at year-end reserving any such amounts not likely
to
be recovered in future periods.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
1 -
BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS
(Continued)
q. Recent
Accounting Pronouncements
In
March
2004, The Emerging Issues Task Force (“EITF”) reached a consensus that mineral
rights, as defined in EITF Issue No. 04-02, “Whether Mineral Rights are Tangible
or Intangible Asset,” are tangible assets and that they should be removed as
examples of intangible assets in SFAS Nos. 141 and 142. The FASB has recently
ratified this
consensus
and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance
of FASB Staff Positions FSP FAS 141-1 and FSP FAS 142-1. Historically the
Company has included the cost of such mineral rights as tangible assets, which
is consistent with the EITF’s consensus. As such, EITF 04-02 did not affect the
Company’s consolidated financial statements.
Effective
February 1, 2006, the Company adopted the fair value recognition provisions
of
Statement of Financial Accounting Standard 123(R) “Share-Based
Payment” (“SFAS
123R”) using the modified prospective transition method. In addition, the
Securities and Exchange Commission issued Staff Accounting Bulletin No. 107
“Share-Based
Payment”
(“SAB
107”) in March, 2005, which provides supplemental SFAS 123R application guidance
based on the views of the SEC. Under the modified prospective transition method,
compensation cost recognized in the fiscal year ended April 30, 2006 includes:
(a) compensation cost for all share-based payments granted prior to, but not
yet
vested as of February 1, 2006, based on the grant date fair value estimated
in
accordance with the original provisions of SFAS No. 123, and (b) compensation
cost for all share-based payments granted beginning February 1, 2006, based
on
the grant date fair value estimated in accordance with the provisions of SFAS
123R. Expected pre-vesting forfeitures were estimated based on actual historical
pre-vesting forfeitures over the most recent years ending April 30, 2006 for
the
expected option term. In accordance with the modified prospective transition
method, results for prior periods have not been restated. The adoption of SFAS
123R resulted in no material stock compensation expense for the year ended
April
30, 2006.
Prior
to
the adoption of SFAS 123R, the Company presented any tax benefits of deductions
resulting from the exercise of stock options within operating cash flows in
the
condensed consolidated statements of cash flow. SFAS 123R requires tax benefits
resulting from tax deductions in excess of the compensation cost recognized
for
those options (“excess tax benefits”) to be classified and reported as both an
operating cash outflow and a financing cash inflow upon adoption of SFAS 123R.
As a result of the Company’s net operating losses, the excess tax benefits that
would otherwise be available to reduce income taxes payable have the effect
of
increasing the Company’s net operating loss carry forwards. Accordingly, because
the Company is not able to realize these excess tax benefits, such benefits
have
not been recognized in the condensed statement of cash flow for the quarterly
period ended June 30, 2006.
In
April
2005, the FASB issued Staff Interpretation No. 19-1 FSP FAS 19-1 (“FSP 19-1”)
“Accounting for Suspended Well Costs,” which provides guidance on the accounting
for exploratory well costs and proposes an amendment to FASB Statement No.
19
(“FASB 19”), “Financial Accounting and Reporting By Oil and Gas Producing
Companies.” The guidance in FSP 19-1 applies to enterprises that use the
successful efforts method of accounting as described in FASB 19. The guidance
in
FSP 19-1 does not impact the consolidated financial position, result of
operations or cash flows.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
1 -
BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS
(Continued)
r. Major
Customers
The
Company depends upon local purchasers of hydrocarbon in the areas where its
properties are located. The Company has three major customers. The loss of
one
or more purchasers may substantially reduce its sales and ability to operate
profitably. These major customers are:
Delta
Producers, Inc. accounted for $301,461 of the Company’s total revenue, which was
about 12% of the Company’s total revenue.
Nami
Resources, LLC accounted for $119,509 of the Company’s total revenue, which was
about 5% of the Company’s total revenue.
South
Kentucky Purchasing Co. - South Kentucky accounted for $229,963 of the Company’s
total revenue, which was about 9% of the Company’s total revenue. South Kentucky
purchases all of the Company’s crude oil.
Wind
Mill
Oil & Gas, LLC - Wind Mill accounted for $153,096 of the Company’s total
revenue, which was about 6% of the company’s total revenue.
Norwest
Energy, NL of Perth, Australia and Golden Triangle energy of Houston, Texas
accounted for $1,175,000 of the Company’s drilling revenue.
NOTE
2 -
WIND MILL OIL & GAS, LLC JOINT VENTURE
On
December 23, 2005 the Company executed an LLC agreement with Wind City Oil
&
Gas, LLC (“Wind City”) to form Wind Mill Oil & Gas, LLC (“Wind Mill”) for
the purpose of locating, producing and selling oil and gas. Wind City
contributed $10,000,000 of cash and received a 50.1% interest in Wind Mill.
The
Company contributed approximately 43,000 acres of oil and gas leases with a
stated value of $3,000,000 and a cost basis of $801,319, and received a 49.9%
interest in Wind Mill.
Under
the
Wind Mill agreement the Company is reimbursed for administrative salaries and
receives revenue for Wind Mill’s use of the Company’s production equipment and
employees. For the period from December 23, 2005 to April 30, 2006 the Company
received salary reimbursements of $276,491 and drilling revenue of
$153,096.
Under
the
Wind Mill agreement Wind City is to be allocated all of the initial losses
until
its capital account is reduced to zero, and then will be allocated all initial
profits until the profits are equal to the initial losses
allocated.
The
Wind
Mill agreement contains a provision to unwind the LLC at the option of Wind
City
based on certain well results from the initial drilling. The four commercial
wells drilled have exceeded the minimum requirements contained in the
agreement.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
2 -
WIND MILL OIL & GAS, LLC JOINT VENTURE (Continued)
In
the
event that the Wind Mill agreement becomes subject to the unwind provision,
the
Company has no responsibility for funding any losses and would receive a
reassignment of the oil and gas leases transferred by the Company to Wind
Mill.
As
part
of the Wind Mill agreement Wind City purchased 2,900,000 shares of the Company’s
common stock for $1.50 per share for a total of $4,350,000. Part of the stock
purchase agreement allows Wind City to put the stock back to the Company
if
notification is given prior to September 30, 2006. The Company would then
be
required to repurchase the stock for the original selling price of
$4,350,000.
NOTE
3 -
STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURE
|
|
2006
|
|
2005
|
|
CASH
PAID FOR:
|
|
|
|
|
|
Interest
|
|
$
|
364,325
|
|
$
|
70,990
|
|
Loan
fees and cost
|
|
|
553,524
|
|
|
|
|
|
|
|
|
|
|
|
|
NON-CASH
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Financing
costs from issuance of warrants
|
|
|
436,392
|
|
|
|
|
Stock
issued for mineral rights
|
|
|
|
|
|
106,000
|
|
Common
stock issued for services
|
|
|
2,143,000
|
|
|
119,600
|
|
Deferred
offering cost
|
|
|
88,842
|
|
|
|
|
NOTE
4 -
DEFERRED OFFERING COST
Through
April 30, 2004, the Company issued 85,000 shares of its common stock valued
at
approximately $89,000 in connection with a proposed public offering of its
common stock. In June, 2004, the Company postponed its proposed public offering
due to market conditions. This planned offering was abandoned upon consummation
of the Wind Mill Joint Venture, and the offering costs were expensed during
the
year ended April 30, 2006.
NOTE
5 -
OIL AND GAS PROPERTIES - PIPELINE FACILITIES
The
Company uses the successful efforts method of accounting for oil and gas
producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves,
and
to drill and equip development wells are capitalized. Costs to drill exploratory
wells that do not find proved reserves, geological and geophysical costs,
and
costs carrying and retaining unproved properties are expensed. The Company
amortizes the oil and gas properties using the unit-of-production method
based
on total proved reserves. The Company capitalized $335,905 and $549,687 of
oil
and gas properties for the years ended April 30, 2006 and 2005, respectively,
and recorded $275,213 and $245,860 of amortization expense for the years
ended
April 30, 2006 and 2005, respectively.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
6 -
LONG-TERM DEBT
The
Company had the following debt obligations at
April
30, 2006 and April 30 2005
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
Note
payable to First National Bank of Oneida secured by
|
|
|
|
|
|
stock
and equipment, bearing interest at 7.5%, due in
|
|
|
|
|
|
quarterly
payments of $15,000 beginning January 14, 2006
|
|
$
|
|
|
$
|
$85,097
|
|
|
|
|
|
|
|
|
|
Note
payable to American Fidelity Bank secured by
|
|
|
|
|
|
|
|
A
trust deed on property, bearing interest at prime, due in
|
|
|
|
|
|
|
|
monthly
payments of $2,500, with the final payment due in
|
|
|
|
|
|
|
|
August
2008
|
|
|
340,534
|
|
|
353,891
|
|
|
|
|
|
|
|
|
|
Line
of credit payable to First National Bank of the
|
|
|
|
|
|
|
|
Cumberlands,
secured by equipment and accounts
|
|
|
|
|
|
|
|
receivable,
bearing interest at 10,388%, due on
|
|
|
|
|
|
|
|
October
12, 2005
|
|
|
|
|
|
16,835
|
|
|
|
|
|
|
|
|
|
Note
payable to supplier secured by assignment of royalty
|
|
|
|
|
|
|
|
income
from five gas wells in Campbell County, Tennessee,
|
|
|
|
|
|
|
|
interest
at prime 5.75% at April 30, 2005
|
|
|
|
|
|
199,824
|
|
|
|
|
|
|
|
|
|
Note
payable to related party, unsecured, interest at 7.00%
|
|
|
|
|
|
|
|
with
payments due annually, with the principal due in May 2005
|
|
|
|
|
|
59,692
|
|
|
|
|
|
|
|
|
|
Note
payable to related party, secured by twelve oil and gas
|
|
|
|
|
|
|
|
wells,
bearing interest at 9.00% and requiring interest payments
|
|
|
|
|
|
|
|
quarterly
with the principal due in December 2004
|
|
|
|
|
|
1,110,000
|
|
|
|
|
|
|
|
|
|
Note
payable to related party, bearing interest at 8.00%,
|
|
|
|
|
|
|
|
with
principal due in December 2005
|
|
|
|
|
|
254,000
|
|
|
|
|
|
|
|
|
|
Note
payable to related party, secured by twelve oil and gas
|
|
|
|
|
|
|
|
wells,
bearing interest at 9.00% and requiring interest payments
|
|
|
|
|
|
|
|
quarterly
with the principal due in December 2004
|
|
|
|
|
|
250,000
|
|
|
|
|
|
|
|
|
|
Total
Notes Payable
|
|
$
|
340,534
|
|
$
|
2,329,339
|
|
Less
current maturities
|
|
|
16,636
|
|
|
-
|
|
Notes
Payable - Long-term
|
|
$
|
323,898
|
|
$
|
2,329,339
|
|
On
May 9,
2005 the Company entered into a credit agreement with Prospect Energy
Corporation, Inc. (“Prospect”) and Petro Capital III, LP (“Petro”). Under the
agreement, the Company received an aggregate of $4,150,000 in debt financing
under two convertible promissory notes with Prospect and Petro, for $3,150,000
and $1,000,000, respectively. Proceeds from this borrowing were used to satisfy
the obligations existing at April 30, 2005. Accordingly, the maturities
reflected above represent the maturities of the debt entered into subsequent
to
April 30, 2005.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
6 -
LONG-TERM DEBT (Continued)
The
Prospect and Petro notes were due on June 30, 2006, with interest only payments
accruing at 12% during the interim. The notes were convertible into common
stock
at the lesser price of $1.50 per share or the price of common stock issued
to
investors in a then-planned equity offering of the Company.
When
the
stock was sold to Wind City in December 2005 the Prospect and Petro notes
were
paid off.
NOTE
7 -
RELATED PARTY TRANSACTIONS
At
April
30, 2006 the Company has an account receivable from Wind Mill in the amount
of
$294,038 and an account receivable from Herman Gettlefinger, a member of
the
board of directors, and his wife in the amount of $53,062. The Company also
received salary reimbursement and compensation from Wind Mill as discussed
in
Note 2.
For
the
year ended April 30, 2006 the Company issued, as compensation, 500,000 shares
of
common stock to the Company’s President, Ernest Payne, and 400,000 shares of
common stock to a consultant, Scott Boruff, the son-in law of the Company’s CEO,
Deloy Miller.
The
Company had a note payable to Sharon Miller (wife of Deloy Miller, majority
stockholder) for $59,693 at April 30, 2005. The note was payable with a
principle payment of $59,693 due in May 2006. The note was the balance remaining
on the original purchase of the property that houses the Company’s offices. This
note was paid off in May 2005.
The
Company issued notes payable of $1,110,000 and $250,000 on August 13, 2003
at 9%
with a one year term to Sherri Ann Parker Lee and William Parker Lee
respectively. These notes payable were issued to raise working capital. The
related party notes were due to members of the Company’s board of directors or
their immediate families. These notes were paid off in May 2005.
NOTE
8 -
ASSET RETIREMENT OBLIGATION
In
2001,
the Financial Accounting Standards Board approved the issuance of SFAS No.
143,
"Accounting for Asset Retirement Obligations." SFAS 143 addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. This
statement requires companies to record the present value of obligations
associated with the retirement of tangible long-lived assets in the period
in
which it is incurred. The liability is capitalized as part of the related
long-lived asset's carrying amount. Over time, accretion of the liability
is
recognized as an operating expense and the capitalized cost is depreciated
over
the expected useful life of the related asset.
The
changes in the Company’s liability for the years ended April 30, 2005 and 2006
as follows:
Asset
retirement obligation as of April 30, 2004
|
|
$
|
13,306
|
|
Accretion
expense for 2005
|
|
|
1,890
|
|
Asset
retirement obligation as of April 30, 2005
|
|
|
15,196
|
|
Accretion
expense for 2006
|
|
|
2,353
|
|
Asset
retirement obligation as of April 30, 2006
|
|
$
|
17,549
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
9 -
ASSET IMPAIRMENT - PLUGGED AND ABANDONED WELLS
In
connection with the assignment of leases to Wind Mill as discussed in Note
2,
management assessed the remaining oil and gas properties and determined that
$624,222 of well and lease cost should be written off as impaired.
NOTE
10 -
INCOME TAXES
The
Company provides deferred income tax assets and liabilities using the liability
method for temporary differences between book and taxable income.
A
reconciliation of the statutory U. S. Federal income tax and the income tax
provision included in the accompanying consolidated statements of operations
is
as follows:
|
|
2006
|
|
2005
|
|
Current
Year Addition:
|
|
|
|
|
|
Federal
statutory rate
|
|
34%
|
|
34%
|
|
Federal
tax benefit at statutory rate
|
|
$
|
1,220,000
|
|
$
|
89,000
|
|
State
income tax, net of benefit
|
|
|
126,000
|
|
|
19,600
|
|
Stock
compensation
|
|
|
(93,000
|
)
|
|
|
|
Stock
warrants
|
|
|
(126,000
|
)
|
|
|
|
|
|
|
1,127,000
|
|
|
108,600
|
|
Increase
in valuation allowance
|
|
|
(1,127,000
|
)
|
|
(108,600
|
)
|
|
|
|
|
|
|
|
|
Increase
in deferred tax asset and valuation allowance
|
|
$
|
0
|
|
$
|
0
|
|
|
|
|
|
|
|
|
|
Cumulative
Tax Benefit:
|
|
|
|
|
|
|
|
Net
operating loss carryforward
|
|
$
|
2,452,000
|
|
$
|
1,451,000
|
|
Stock
warrants
|
|
|
126,000
|
|
|
|
|
Valuation
allowance
|
|
|
(2,578,000
|
)
|
|
(1,451,000
|
)
|
|
|
|
|
|
|
|
|
Net
deferred tax benefit
|
|
$
|
0
|
|
$
|
0
|
|
The
Company recorded a valuation allowance at April 30, 2006 and 2005 equal to
the
excess of deferred tax assets over deferred tax liabilities, as management
is
unable to determine that these tax benefits are more likely than not to be
realized.
The
Company had available, to offset taxable income, cumulative net operating
loss
carry forwards arising from the periods since the year ended April 30, 1997
of
approximately $7,328,000 at April 30, 2006. The carry forwards begin expiring
in
2012.
NOTE
11 -
STOCKHOLDERS’ EQUITY
During
the year ended April 30, 2006 the Company issued 2,050,000 free-trading common
shares of stock for services valued at $2,143,000 and issued 2,920,000
free-trading common shares of stock for $4,360,000 of cash. The Company also
issued 1,200,000 warrants in connection with the Prospect / Petro loan at
an
average exercise price of $0.61 per share.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
11 -
STOCKHOLDERS’ EQUITY (Continued)
During
the year ended April 30, 2005, the Company issued 130,000 free trading shares
of
its common stock for cash and services valued at $93,000. Also during fiscal
2005, the Company sold 275,000 shares of restricted common stock in private
placements for proceeds of $80,000. The sales transpired at discounts ranging
from 66% to 43% from prevailing prices for free-trading shares.
Further,
the Company issued 113,000 restricted shares of its common stock for leasehold
interests in oil and gas properties at a discount of 60% from prevailing
prices
for free-trading shares.
Additionally,
the Company has warrants and options outstanding from prior periods. All
warrants must be adjusted in the event of any forward or reverse split of
outstanding common stock. The warrants have no voting rights or liquidation
preferences, unless exercised in accordance with the particular
warrant.
Prior
to
adoption of SFAS 123R, the fair value of the options granted was estimated
on
the date of grant using the Black-Scholes option-pricing model with the
following weighted average assumptions used for grants in fiscal year 2006:
50%
volatility, two and a half year life, zero dividend yield, and risk-free
interest rate of 4.50%.
Information
regarding the options and warrants at April 30, 2006 and 2005 is as
follows:
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
outstanding,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
beginning
of year
|
|
|
540,000
|
|
|
$
|
1.30
|
|
|
2,235,000
|
|
|
$
|
0.88
|
|
Options
canceled
|
|
|
170,000
|
|
|
|
1.01
|
|
|
1,695,000
|
|
|
|
0.77
|
|
Options
exercised
|
|
|
20,000
|
|
|
|
0.50
|
|
|
-
|
|
|
|
0.00
|
|
Options
granted
|
|
|
1,200,000
|
|
|
|
0.61
|
|
|
-
|
|
|
|
0.00
|
|
Options
outstanding,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
end
of year
|
|
|
1,550,000
|
|
|
$
|
0.81
|
|
|
540,000
|
|
|
$
|
1.30
|
|
Options
exercisable,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
end of year
|
|
|
1,550,000
|
|
|
$
|
0.81
|
|
|
540,000
|
|
|
$
|
0.88
|
|
Option
price range,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
end of year
|
|
|
|
|
|
$
|
0.50
to 2.00
|
|
|
|
|
|
$
|
0.50
to 2.00
|
|
Option
price range,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
exercised shares
|
|
|
|
|
|
|
0.50
|
|
|
|
|
|
|
n/a
|
|
Options
available for grant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
at end of year
|
|
|
|
|
|
|
n/a
|
|
|
|
|
|
|
n/a
|
|
Weighted
average fair value of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
options granted during the year
|
|
|
|
|
|
|
0.36
|
|
|
|
|
|
|
n/a
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 20058
NOTE
12 -
CONTINGENCIES
The
Company’s activities are subject to federal, state and local laws and
regulations governing environmental quality and pollution control in the
United
States. The company cannot predict what effect future regulations or
legislation, enforcement policies, and claims for damages to property,
employees, other persons and the environment resulting from the Company’s
operations could have on its activities. Although no assurances can be made,
the
Company’s management believes that absent the occurrence of an extraordinary
event, compliance with existing laws, rules and regulations regulating the
release of materials in the environment or otherwise relating to the protection
of the environment will not have a material effect upon the Company’s financial
position.
NOTE
13 -
DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The
carrying amount reported on the balance sheet for cash, accounts and notes
receivable, accounts payable and accrued liabilities approximates fair value
because of the immediate or short-term maturity of these financial instruments.
The carrying value of notes payable approximate fair value due to the settlement
at carrying value of these obligations subsequent to the balance sheet date
(see
Note 6, Long Term Debt).
NOTE
14 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited)
(1)
Capitalized Costs Relating to Oil and Gas Producing Activities at April 30,
2006
and 2005 are as follows:
|
|
2006
|
|
2005
|
|
Proved
oil and gas properties and related lease equipment
|
|
|
|
|
|
Developed
|
|
$
|
2,776,181
|
|
$
|
3,841,996
|
|
Non-developed
|
|
|
7,199
|
|
|
31,053
|
|
|
|
|
2,783,380
|
|
|
3,873,049
|
|
Accumulated
depreciation and depletion
|
|
|
(1,206,430
|
)
|
|
(931,217
|
)
|
Net
Capitalized Costs
|
|
$
|
1,576,950
|
|
$
|
2,941,832
|
|
(2)
Costs Incurred in Oil and Gas Property Acquisition, Exploration,
and
Development Activities
|
|
|
|
|
2006
|
|
|
2005
|
|
Acquisition
of Properties Proved and Unproved
|
|
$
|
-
|
|
$
|
-
|
|
Exploration
Costs
|
|
|
-
|
|
|
-
|
|
Development
Costs
|
|
|
335,905
|
|
|
549,687
|
|
Total
|
|
$
|
335,905
|
|
$
|
549,687
|
|
(3)
Results of Operations for Producing Activities
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
Production
revenues
|
|
$
|
810,607
|
|
$
|
784,409
|
|
Production
costs
|
|
|
89,167
|
|
|
177,287
|
|
Depreciation
and amortization
|
|
|
275,313
|
|
|
245,860
|
|
Results
of operations for producing activities
|
|
|
|
|
|
|
|
(excluding
corporate overhead and interest costs)
|
|
$
|
446,127
|
|
$
|
361,262
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
14 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)
(4)
Reserve Quantity Information
The
following schedule estimates proved oil and natural gas reserves attributable
to
the Company. Proved reserves are estimated quantities of oil and natural
gas
which geological and engineering data demonstrate with reasonable certainty
to
be recoverable in future years from known reservoirs under existing economic
and
operating conditions. Proved developed reserves are those which are expected
to
be recovered through existing wells with existing equipment and operating
methods. Reserves are stated in barrels of oil (Bbls) and thousands of cubic
feet of natural gas (Mcf). Geological and engineering estimates of proved
oil
and natural gas reserves at one point in time are highly interpretive,
inherently imprecise and subject to ongoing revisions that may be substantial
in
amount. Although every reasonable effort is made to ensure that the reserve
estimates reported represent the most accurate assessments possible, these
estimates are by their nature generally less precise than other estimates
presented in connection with financial statement disclosures.
|
|
Oil
(Bbls)
|
|
Gas
(Mcf)
|
|
Proved
reserves
|
|
|
|
|
|
Balance,
April 30, 2004
|
|
|
350,936
|
|
|
8,696,519
|
|
Discoveries
and extensions
|
|
|
35,400
|
|
|
220,000
|
|
Revisions
of previous estimates
|
|
|
(284,979
|
)
|
|
(7,592,419
|
)
|
Production
|
|
|
(7,532
|
)
|
|
(74,534
|
)
|
|
|
|
|
|
|
|
|
Balance,
April 30, 2005
|
|
|
93,825
|
|
|
1,249,566
|
|
Discoveries
and extensions
|
|
|
-
|
|
|
73,980
|
|
Revisions
of previous estimates
|
|
|
3,084
|
|
|
10,695
|
|
Productions
|
|
|
(5,630
|
)
|
|
(60,914
|
)
|
|
|
|
|
|
|
|
|
Balance,
April 30, 2006
|
|
|
91,279
|
|
|
1,273,327
|
|
|
|
|
|
|
|
|
|
Proved
developed producing
|
|
|
|
|
|
|
|
reserves
at April 30, 2006
|
|
|
58,188
|
|
|
686,580
|
|
|
|
|
|
|
|
|
|
Proved
developed producing
|
|
|
|
|
|
|
|
reserves
at April 30, 2005
|
|
|
60,734
|
|
|
697,916
|
|
In
addition to the proved developed producing oil and gas reserves reported
in the
geological and engineering reports, the Company holds ownership interests
in
various proved undeveloped properties. The reserve and engineering reports
performed for the Company were by Netherland Sewell and Associates, Inc.
for the
years ended April 30, 2006 and April 30, 2005. Although wells have been drilled
and completed in each of these four properties, certain production and pipeline
facilities must be installed before actual gas production will be able to
commence. The most recent development plan for these properties indicates
that
facilities installation and commencement of production will be in the summer
of
2006. However, such timing as well as the actual financing arrangements that
will be secured by the Company is uncertain at this time.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
14 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)
The
following schedule presents the standardized measure of estimated discounted
future net cash flows from the Company’s proved developed reserves for the years
ended April 30, 2006 and 2005. Estimated future cash flows were based on
independent reserves evaluation from Netherland Sewell & Associates, Inc.
for the years ended April 30, 2006 and April 30, 2005. Because the standardized
measure of future net cash flows was prepared using the prevailing economic
conditions existing at April 30, 2006 and 2005, it should be emphasized that
such conditions continually change. Accordingly, such information should
not
serve as a basis in making any judgment on the potential value of the Company’s
recoverable reserves or in estimating future results of operations.
Estimated
future net cash flows represent an estimate of future net revenues from the
production of proved reserves using current sales prices, along with estimates
of the operating costs, production taxes and future development and abandonment
costs (less salvage value) necessary to produce such reserves. The average
prices used at April 30, 2006 and 2005 were $61.75 and $40.75 per barrel
of oil
and $6.94 and $7.14 per Mcf gas, respectively. No deduction has been made
for
depreciation, depletion or any indirect costs such as general corporate overhead
or interest expense.
Operating
costs and production taxes are estimated based on current costs with respect
to
producing gas properties. Future development costs are based on the best
estimate of such costs assuming current economic and operating
conditions.
Income
tax expense is computed based on applying the appropriate statutory tax rate
to
the excess of future cash inflows less future production and development
costs
over the current tax basis of the properties involved.
The
future net revenue information assumes no escalation of costs or prices,
except
for gas sales made under terms of contracts which include fixed and determinable
escalation. Future costs and prices could significantly vary from current
amounts and, accordingly, revisions in the future could be
significant.
Standardized
measures of discounted future net cash flows at April 30, 2006 and 2005 are
as
follows:
|
|
2006
|
|
2005
|
|
Future
cash flows
|
|
$
|
14,470,000
|
|
$
|
12,747,600
|
|
Future
production costs and taxes
|
|
|
(1,898,000
|
)
|
|
(1,939,000
|
)
|
Future
development costs
|
|
|
(568,100
|
)
|
|
(745,000
|
)
|
Future
income tax expense
|
|
|
(3,721,209
|
)
|
|
(3,119,716
|
)
|
Future
cash flows
|
|
|
8,282,691
|
|
|
6,943,884
|
|
Discount
at 10% for timing of cash flows
|
|
|
(4,199,324
|
)
|
|
(3,463,248
|
)
|
Discounted
future net cash flows
|
|
|
|
|
|
|
|
from
proved reserves
|
|
$
|
4,083,367
|
|
$
|
3,480,636
|
|
Of
the
Company’s total proved reserves as of April 30, 2006 and 2005, approximately 57%
and 59%, respectively, were classified as proved developed producing, 31%
and
11%, respectively, were classified as proved developed non-producing and
12% and
30%, respectively, were classified as proved undeveloped. All of the Company’s
reserves are located in the continental United States.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2006 and 2005
NOTE
14 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)
The
following table sets forth the changes in the standardized measure of discounted
future net cash flows from proved reserves for April 30, 2006 and
2005.
|
|
April
30,
|
|
|
|
2006
|
|
2005
|
|
Balance,
beginning of year
|
|
$
|
3,480,636
|
|
$
|
23,149,947
|
|
|
|
|
|
|
|
|
|
Sales,
Net of production costs and taxes
|
|
|
(721,440
|
)
|
|
(784,409
|
)
|
|
|
|
|
|
|
|
|
Changes
in prices and production costs
|
|
|
1,484,124
|
|
|
7,490,059
|
|
Revisions
of quantity estimates
|
|
|
264,640
|
|
|
(39,206,898
|
)
|
Development
costs incurred
|
|
|
176,900
|
|
|
3,995,000
|
|
Net
changes in income taxes
|
|
|
(601,493
|
)
|
|
8,836,937
|
|
|
|
|
|
|
|
|
|
Balances,
end of year
|
|
$
|
4,083,367
|
|
$
|
3,480,636
|
|
Item
8 Changes
In and Disagreements With Accountants On Accounting and Financial
Disclosure
None.
Item
8A Controls
and Procedures
Disclosure
Controls and Procedures. Under
the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation
of the
effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Securities Exchange Act of 1934) as of the end of the period covered by this
report (the “Evaluation Date”). Based on this evaluation, our Chief Executive
Officer and Chief Financial Officer concluded as of the Evaluation Date that
our
disclosure controls and procedures were not adequate and effective to ensure
that our management is alerted to material information required to be included
in our periodic filings. Nevertheless, our management has determined that
all
matters to be disclosed in this report have been fully and accurately reported.
We are in the process of improving our processes and procedures to ensure
full,
accurate and timely disclosure in the current fiscal year, with the expectation
of establishing effective disclosure controls and procedures as soon as
reasonably practicable.
Internal
Control over Financial Reporting. Under
the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we are responsible for
establishing and maintaining an adequate system of internal control over
financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the
Securities Exchange Act of 1934). During our most recent fiscal year ended
April
30, 2006, there were no changes in our internal control over financial reporting
that have materially affected or are reasonably likely to affect, our internal
control over financial reporting.
Item
8B Other
Information
None.
PART
III
Item
9 Directors,
Executive Officers, Promoters and Control Persons; Compliance with Section
16(a)
of the Exchange Act
Directors
and Executive Officers
The
following table shows the names, ages and positions held by our executive
officers, directors and significant employees.
Name
|
Age
|
Position
|
Deloy
Miller
|
59
|
Director
and Chief Executive Officer
|
Ernest
Payne
|
59
|
President
|
Lyle
H. Cooper
|
63
|
Chief
Financial Officer
|
Herbert
J. White
|
80
|
Vice
President and Director
|
Gary
Bible
|
56
|
Vice
President of Geology
|
Teresa
Cotton
|
43
|
Secretary
and Treasurer
|
Charles
M. Stivers
|
44
|
Director
|
Herman
E. Gettelfinger
|
73
|
Director
|
Business
Experience
Deloy
Miller
has been
Chairman of the Board of Directors since December 1996, and Chief Executive
Officer since December 1997. Mr. Miller is a seasoned gas and oil professional
with more than 30 years of experience in the drilling and production business
in
the Appalachian basin. During his years as a drilling contractor, he acquired
extensive geological knowledge of Tennessee and Kentucky and received training
in the reading of well logs. A native Tennessean, Miller is credited with
being
the leader in converting the Appalachian Basin from cable tool drilling to
air
drilling, using the Ingersoll-Rand T3 Drillmaster rigs. The introduction
of air
drilling sparked the 1969 drilling boom and Miller soon became a successful
drilling contractor in the southern Appalachian basin. He served two terms
as
president of the Tennessee Oil & Gas Association and in 1978 the
organization named Miller the Tennessee Oil Man of the Year. He continues
to
serve on the board of that organization. Mr. Miller was appointed by the
Governor of Tennessee to be the petroleum industry's representative on the
Tennessee Oil & Gas Board, the state agency that regulates gas and oil
operations in the state.
Ernest
Payne
was
appointed President on in August 2003.
Mr.
Payne
rejoined the Miller Team after serving as Project Manager and Superintendent
for
Youngquist Brothers of Fort Myers, Florida from early 1994 through May of
2001.
Mr. Payne has 20 years experience in oil and gas well design and stimulations
as
well as supervising the operation of drilling and workover rigs. He earned
a
B.S. in engineering at Tennessee Technological University. He originally
joined
Miller in the early 70's and was the general manager for 17 years. He directed
the operation of 18 drilling and workover rigs. In the mid 1980's he formed
his
own company and managed large drilling jobs in Florida and Puerto Rico until
joining Youngquist.
Lyle
H. Cooper
was
appointed Chief Financial Officer on January 20, 2006. Mr. Cooper owns a
private
CPA firm where since 1991 he has specialized in providing accounting, auditing,
tax and SEC related services. During 2002 and 2003 he served as Secretary
of
aurora Lighting Inc., a leading manufacturer of electronic ballasts. In 2003
and
2004 Mr. Cooper participated as principal in an oil drilling venture in Clinton
County, Kentucky.
Charles
M. Stivers has
been
a Director since 2004. He also served as our Chief Financial Officer from
2004
until January 2006. Mr. Stivers has over 18 years accounting experience and
over
12 years of experience within the energy industry. He owns and operates Charles
M. Stivers, C.P.A., which specializes in the oil and gas industry and has
clients located in eight different states. His responsibilities include all
forms of SEC audit work, SEC quarterly financial statement filings, oil and
gas
consulting work, and income tax work. Mr. Stivers served as Treasurer and
CFO
for Clay Resource Company and Senior Tax and Audit Specialist for Gallaher
and
Company. He received a Bachelor of Science degree in accounting from Eastern
Kentucky University.
Herbert
J. White
has been
a Vice President and Director since April 1997. Mr. White has more than 44
years
of Petroleum related experience. After earning his BS degree from North Texas
University, he became an engineer with Halliburton, handling Louisiana Gulf
Coast and offshore operations and serving in Australia. In 1975 he joined
Petroleum Development Corporation, a West Virginia-based public company,
supervising engineering and operations in Southern Appalachian basin. He
also
has experience in Devonian Shale production, enhanced recovery and coal
degasification. Miller Petroleum and its predecessor corporation have employed
Mr. White as a Petroleum Engineer since July of 1985. In April, 1997, he
became
a director and Vice President of Development Engineering for Miller
Petroleum.
Herman
Gettelfinger
has been
a Director since 1997. Mr. Gettelfinger is a co-owner of Kelso Oil Company,
Knoxville Tennessee and has been the President of Kelso since 1960. Kelso
is one
of eastern Tennessee's largest distributors of motor oils, fuels and lubricants
to the industrial and commercial market. Mr. Gettelfinger has been active
in the
gas and oil drilling and exploration business for more than 35 years and
has
been associated with Miller Petroleum for more than 25 years.
Dr.
Gary Bible
was
appointed Vice President of Geology in September 1997. Dr. Bible came from
Alamco, where he had served since May of 1991 as Manager of Geology and Senior
Geologist. Dr. Bible earned his BS Degree in Geology from Kent State University
and his Msc. and PhD. Degrees in Geology from Iowa State University. He is
a
proven hydrocarbon finder who drilled his first successful wildcat as a Trainee
Geologist. Dr. Bible brings to the Company 20 years experience as a Petroleum
Geologist. In addition, Dr. Bible has spent more than 10 years in the
Appalachian Basin in the exploration and development of reserves in the Big
Lime, Devonian Shale and in deeper horizons. He is credited with managing
a
drilling program at Alamco that kept its finding cost the lowest in the
nation.
Teresa
Cotton
was
appointed Secretary/Treasurer in December 2001. Prior to joining the Miller
Team, Mrs. Cotton was employed by Halliburton Services. She has more than
twenty
years experience in the oil and gas industry. Mrs. Cotton, a Tennessee native,
earned an A.S. in Business Administration at Roane State Community College
in
Huntsville, Tennessee.
Term
of Office
Our
officers are appointed by our board of directors and hold office until removed
by the board.
Audit
Committee Financial Expert
We
have
an audit committee consisting of Deloy
Miller,
Herman
Gettelfinger and Charles Stivers. Our board of directors has determined that
Mr.
Stivers is an “audit committee financial expert” based on his qualification as a
certified public accountant and his prior experience.
Compliance
With Section 16(a)
We
have
no securities registered under Section 12 of the Securities Exchange Act
of
1934, as amended (the “Exchange Act”). We file our periodic and annual reports
pursuant to Section 15(d) thereof. Accordingly, our directors, executive
officers and 10% stockholders are not required to file statements of beneficial
ownership of securities under 16(a) of the Exchange Act.
Code
of Ethics
We
have
adopted a Code of Conduct that applies to our President, Chief Executive
Officer, Chief Accounting Officer or Controller and any other persons performing
similar functions. Our Code of Conduct is attached as an exhibit to our annual
report on Form 10-KSB for the year ended April 30, 2004.
Item
10 Executive
Compensation
Summary
Compensation Table
The
following table sets forth information for the periods indicated concerning
compensation paid to our Chief Executive Officer and each of our other executive
officer who received the highest compensation for services rendered to us
with
respect to 2006.
|
ANNUAL
COMPENSATION
|
LONG
TERM COMPENSATION
|
Name
|
Title
|
Year
|
Salary
|
Bonus
|
Other
Annual
Compen-
sation
|
AWARDS
|
PAYOUTS
|
All
Other
Compen-
sation
|
Restricted
Stock
Awarded
|
Options/
SARs*
(#)
|
LTIP
payouts
($)
|
Deloy
Miller
|
Chief
Executive Officer
|
2006
2005
2004
|
$185,500
180,000
183,000
|
0
0
0
|
0
0
0
|
0
0
0
|
0
0
0
|
0
0
0
|
0
0
0
|
Long-Term
Incentive Plan
We
do not
have any long-term incentive plans, pension plans, or similar compensatory
plans
for our directors and executive officers.
Compensation
of Directors
Directors
receive an annual fee for Board service of $0 as compensation as well as
attendance fees of $500 for each meeting of the Board attended in person
and $0
for each meeting attended by telephone.
Employment
Contracts, Termination of Employment and Change in Control Arrangements
We
have a
three-year contract with our President beginning February 21, 2006. In
connection with this contract, the President was issued 500,000 shares of
common
stock.
Our
company has no plans or arrangements in respect of remuneration received
or that
may be received by named executive officers of our company in fiscal year
2006
to compensate such officers in the event of termination of employment (as
a
result of resignation, retirement, change of control) or a change of
responsibilities following a change of control.
Item
11 Security
Ownership of Certain Beneficial Owners and Management
The
following table sets forth certain information concerning the number of shares
of our common stock owned beneficially as of August 11, 2006 by: (i) each
person
(including any group) known to us to own more than five percent (5%) of our
common stock, (ii) each of our directors and each of our named executive
officers and (iii) officers and directors as a group.
The
number and percentage of shares beneficially owned is determined in accordance
with Rule 13d-3 of the Securities Exchange Act of 1934, and is not necessarily
indicative of beneficial ownership for any other purpose. Shares of Common
Stock
that a person has a right to acquire within 60 days are deemed outstanding
for
purposes of computing the percentage ownership of that person, but are not
deemed outstanding for purposes of computing the percentage ownership of
any
other person, except with respect to the percentage ownership of all directors
and executive officers as a group. We based our calculations of the percentage
owned on 14,366,856 shares outstanding on August 11, 2006.
Except
as
otherwise indicated, each director and named executive officer (1) has sole
investment and voting power with respect to the securities indicated or
(2) shares investment and/or voting power with that individual’s spouse.
The address of each director and named executive officer listed in the table
below is c/o Miller Petroleum, Inc. 3651 Baker Highway, Huntsville, Tennessee
37756.
Name
of Beneficial Owner
|
Amount
and Nature of Beneficial Ownership
|
Percent
of Class
|
Directors
and Officers
|
|
|
|
Deloy
Miller
|
4,090,343
|
|
28.5%
|
Ernest
Payne
|
605,000
|
(1)
|
4.2%
|
Charles
M. Stivers
|
20,000
|
|
*
|
Herman
E. Gettelfinger
|
342,901
|
(2)
|
2.4%
|
Herbert
J. White
|
300
|
|
*
|
All
directors and executive officers (6 persons)
|
5,058,544
|
(3)
|
34.9%
|
|
|
|
|
Beneficial
Owner of More Than 5%
|
|
|
|
Prospect
Energy Corporation
|
781,805(4)
|
|
5.16%
|
Wind
City Oil & Gas LLC
|
2,900,000
|
|
16.8%
|
_________
*
Represents less than 1% of our outstanding common stock.
(1)
Includes 75,000 shares issuable upon the exercise of presently exercisable
stock
options.
(2)
Includes 50,000 shares issuable upon the exercise of presently exercisable
stock
options and 100,000 shares held by Mr. Gettelfinger’s spouse.
(3)
Includes 125,000 shares issuable upon the exercise of presently exercisable
stock options.
(4)
Represents 781,805 shares issuable upon the exercise of presently exercisable
warrants.
Item
12 Certain
Relationships and Related Transactions
On
September 8, 2005, we agreed to issue 400,000 shares of Common Stock to Scott
Boruff (son-in-law of Deloy Miller, our Chief Executive Officer), in
consideration of consulting services.
The
Company had a note payable to Sharon Miller (wife of Deloy Miller, our Chief
Executive Officer) for $56,693 at July 31, 2005 for the balance remaining
on the
original purchase of the property which houses our executive offices. This
note
was settled May 2005.
The
Company issued a note payable for $254,000 at 8% with principle due in December
2005 to Herman E. Gettelfinger. This note was settled May 2005.
The
Company issued a note payable of $250,000 on August 13, 2003 at 9% with a
one
year term to William Parker Lee, a former member of our Board of Directors.
This
note was settled May 2005.
As
of
April 30, 2006 Wind Mill owed
the
Company $295,257 on an open account in connection with salary reimbursement
and
other contract services.
Other
than the transactions disclosed above, there have been no material transactions,
series of similar transactions or currently proposed transactions, to which
we,
or any of our subsidiaries was or is to be a party, in which the amount involved
exceeds $60,000 and in which any director or executive officer or any security
holder who is known to us to own of record or beneficially more than 5% of
the
Company's common stock, or any member of the immediate family of any of the
foregoing persons, had a material interest.
Item
13 Exhibits
EXHIBIT
NO.
|
|
DESCRIPTION
|
31.1
|
|
Certification
of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley
Act
of 2002 (“Sarbanes-Oxley”).
|
31.2
|
|
Certification
of Chief Financial Officer pursuant to Section 302 of
Sarbanes-Oxley.
|
32.1
|
|
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350,
as adopted
pursuant to Section 906 of Sarbanes-Oxley.
|
32.2
|
|
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350,
as adopted
pursuant to Section 906 of Sarbanes-Oxley.
|
Item
14 Principal
Accountants Fees and Service
The
aggregate fees we paid to Rodefer Moss & Company, PLLC for the years ended
April 30, 2006 and 2005 were as follows:
|
|
2006
|
|
2005
|
|
Audit
Fees
|
|
$
|
82,734
|
|
$
|
45,000
|
|
Audit-Related
Fees
|
|
|
--
|
|
|
--
|
|
Total
Audit and Audit-Related Fees
|
|
|
82,734
|
|
|
45,000
|
|
|
|
|
|
|
|
|
|
Tax
Fees
|
|
|
--
|
|
|
--
|
|
All
Other Fees
|
|
|
--
|
|
|
--
|
|
Total
|
|
$
|
82,734
|
|
$
|
45,000
|
|
The
Audit
Committee’s policy is that all audit and non-audit services to be performed by
our independent auditors must be approved in advance. The policy permits
the
Audit Committee to delegate pre-approval authority to one or more of its
members
and requires any member who pre-approves such services pursuant to that
authority to report his decision to the Committee.
In
accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934,
the
Registrant caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
|
|
|
|
MILLER
PETROLEUM,
INC. |
|
|
|
|
By: |
/s/ Deloy
Miller |
|
Deloy Miller
Chief Executive Officer
|
Dated:
August 17, 2006
In
accordance with the Securities Exchange Act of 1934, this report has been
signed
below by the following persons on behalf of the Registrant and in the capacities
and on the dates indicated.
/s/
Deloy Miller
Deloy
Miller
|
Chairman
of the Board of Directors, and Chief Executive Officer
|
August
17, 2006
|
|
|
|
/s/
Lyle H. Cooper
Lyle
C. Cooper
|
Chief
Financial Officer
|
August
17, 2006
|
|
|
|
/s/
Charles M. Stivers
Charles
M. Stivers
|
Director
|
August
17, 2006
|
|
|
|
______________
Herbert
J. White
|
Director
|
August
17, 2006
|
|
|
|
/s/
Herman E. Gettelfinger
Herman
E. Gettelfinger
|
Director
|
August
17, 2006
|