Unassociated Document
U.S.
SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
————————————————————
FORM
10-KSB/A
x
Annual
report
pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the
fiscal year ended April 30, 2005
¨
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
(State
or Other Jurisdiction of
Incorporation
or Organization)
|
62-1028629
(I.R.S.
Employer
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 (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 x 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, 2005 were $1,030,036.
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 July 25, 2005, was
$6,440,780.80.
There
are
approximately 5,031,860 shares of common voting stock of the Registrant held
by
non-affiliates. On July 25, 2005 the average bid and asked price was
$1.28.
As
of
July 25, 2005, there were 9,466,856 shares of common stock outstanding.
EXPLANATORY
NOTE
This
Amendment No. 1 on Form 10-KSB/A (“Form 10-KSB/A) to Miller Petroleum’s Annual
Report on Form 10-KSB for the fiscal year ended April 30, 2004, initially
filed
with the Securities and Exchange Commission (the “SEC”) on August 30, 2005 (the
“Original Annual Report”), is being filed to reflect responses to comments
received from the SEC on February 1, 2006 concerning the Original Annual
Report,
as well as additional disclosure revisions deemed appropriate by current
management.
In
addition, the Original Filing has been amended to include currently dated
certifications from our Chief Executive Officer and Chief Financial Officer,
as
required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.
This
Form
10-KSB/A does not reflect events occurring after the filing of the Original
Annual Report or modify or update those disclosures affected by subsequent
events.
Forward-Looking
Statements
This
annual report on Form 10-KSB (“Annual Report”) for the period ending April 30,
2005 (“fiscal year 2005”), 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.
PART
I
Item
1. Description
of Business.
General
Overview
We
are
actively engaged in the exploration, development, production and acquisition
of
crude oil and natural gas. Our business involves the operation of oil and gas
wells, the acquisition of oil and gas leases and the rebuilding and sale of
oil
field equipment. Our principal activities are the acquisition, exploration,
development and production of proven, undeveloped and underdeveloped reserves
independently and through joint venture drilling programs with other companies
in the industry. Our properties are currently concentrated in eastern Tennessee.
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
Our
business includes the operation of oil and gas wells, acquisition and
development of oil and gas leases, rebuilding and sales of oil field equipment
and the organization of joint venture drilling programs with other companies
in
the industry.
Oil
and Gas Leases
We
presently have approximately 43,000 acres under lease in Tennessee and seek
to
acquire additional strategic acreage. We utilize seismic data, and other
advanced technologies for geophysical exploration and development of oil and
gas
wells. In addition to our engineering and geological capabilities, we also
have
work over rigs, dozers, roustabout crews and equipment to set pumping units
and
tanks and lay flow lines, winch trucks and trailers for traveling support,
backhoes, ditchers, fusion machines and welders for pipeline and compression
installation, and other equipment necessary to take a well drilling program
from
the development stage to completion. The company also sells rigs, oilfield
trailers, compressors and other miscellaneous oil and gas production equipment.
We
are
presently developing leases referred to as the Koppers North Field (the “Koppers
North”) and the Koppers South Field (the “Koppers South”), which are located in
Tennessee’s Appalachian Basin. These areas, in addition to our recent
acquisition of the Carden Tract, which adjoins the Koppers North, form a 10,500
acre contiguous block in Campbell County, Tennessee and have more than one
hundred and fifty possible developmental well locations. We are also continuing
to develop approximately 3,400 acres leased from the Lindsay Land Company (the
“Lindsay Field”) located near Caryville, Tennessee in Campbell County, which has
twenty five possible developmental well locations. Prospects in Harriman,
Tennessee (Roane County) (the “Harriman Prospect”) have recently been defined by
a seismic study. We have completed the drilling of one well and plan to drill
at
least two more wells there this year.
Our
current drilling program calls for the development of 100 Devonian (Chattanooga)
Shale gas wells in the Koppers North, sixty Big Lime Formation oil/gas wells
in
the Koppers South and ten gas wells in the Lindsay Field.
On
April
21, 2005, we began drilling operations of the Eula Butler Et Al #1 well, a
deep
wildcat in Roane County, to a depth of 6200 feet to the Knox dolomite, as a
part
of our joint venture with a large Appalachian based oil and gas company. A
seismic study revealed a
possibility of significant
quantities of oil and gas from the nearby Trenton-Stones River limestone
formations. The target depth is around 6200 feet and we anticipate that this
well will be completed at the beginning of the next fiscal year.
On
April
11, 2005, we signed an agreement with Norwest Energy, NL of Perth, Australia
(“Norwest”) and Golden Triangle Energy of Houston, Texas (“GTE”) to develop the
Koppers North and Carden Tract. GTE and Norwest will pay 100% of the cost to
drill and complete the first twenty wells in five, five and ten well packages.
We will retain a 25% working interest. After the completion of the first twenty
wells, should Norwest and GTE continue to participate in development of the
remaining acreage, we will pay a portion of the development costs which are
proportionate to our 25% working interest therein.
Lease
and Royalty Terms
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 own a 100%
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. Currently, there are 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 163,983 barrels
of
oil from the Big Lime Formation through April 30, 2005. This lease remains
in
effect
for as long as there is production.
The
Company has leased and is currently leasing smaller tracts of 50 to 1,000 acres
adjacent to or near the Koppers South Fields acreage.
Carden
Tract
This
lease includes 4,200 acres in which we have a 100% working interest and an
81.25% net royalty interest. This tract joins the Koppers North parcel of 6,300
acres to form a 10,500 acre contiguous block in the north. We anticipate that
this lease will produce gas because of previous drilling and production in
the
area by others in the industry. The lease has a three-year term with a five
well
drilling commitment.
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 25%
working interest in gas wells in this area where 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.
As
of
April 30, 2005, we have drilled seven wells with Delta Producers, the Lindsay
Field #9, #10, #11, #12, #13, #14 and #15 wells. The #11 well is awaiting
completion and the remaining wells are producing and we are selling gas from
them 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 50% working interest in the
Lindsay Field lease. The lease also provides for a landowner’s royalty of 12.5%.
We purchased and built with Delta Producers 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.
Well
#
|
Date
Began
Sales
of
Natural
Gas
|
Amount
of Natural
Gas
Sold as of
April
30, 2005 (Mcf)
|
9
|
3/02
|
85,165
|
10
|
1/03
|
29,057
|
11
|
*
|
*
|
12
|
3/02
|
194,432
|
13
|
8/03
|
38,090
|
14
|
8/03
|
24,721
|
15
|
11/03
|
20,707
|
(*)
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. In addition to the Eula Butler Et Al #1 well,
additional wells are being planned on this area.
There
are several smaller leases that expire at different times. When drilled on,
they
will be held by production.”
Tengasco
Farmout
We
entered into a farmout agreement (the “Tengasco Farmout”) with Tengasco, Inc.
(“Tengasco”) for ten wells to be drilled in the Swan Creek Field, located in
Hancock County in Tennessee.
In
August
of 2000, we drilled our first oil well under the Tengasco Farmout, the Dewey
Sutton #1 well, located in the Trenton formation. We have sold more than 16
MBbl
and are currently producing about 200 barrels of oil per month from the Dewey
Sutton #1 well.
Tengasco
completed its pipeline and began buying natural gas from us on March 8, 2001
from the Worlie Purkey#1 well. We have sold 12,400 Mcf from this well. We
started selling gas to Tengasco from the Worlie Purkey #3 well in May 2001.
During the latter part of June 2001, we began selling from the Jeff Johnson
#1
well. Through April 30, 2005, we have sold 50,080 Mcf of gas from the Worlie
Purkey #3 and 78,249 Mcf of gas from the Jeff Johnson #1 to Tengasco. These
leases will remain in effect for as long as there is production.
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. There are thirteen producing oil wells
and
eight producing natural gas wells on these leases that have produced 148,693
barrels of oil and 291,996 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, 2003
|
|
|
208,821
|
|
|
5,365,057
|
|
Discoveries
and extensions
|
|
|
68,903
|
|
|
718,160
|
|
Revisions
of previous estimates
|
|
|
79,169
|
|
|
2,642,073
|
|
Production
|
|
|
(5,957
|
)
|
|
(28,771
|
)
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
Proved
developed producing reserves at April 30, 2005
|
|
|
60,734
|
|
|
697,916
|
|
|
|
|
|
|
|
|
|
Proved
developed producing reserves at April 30, 2004
|
|
|
62,106
|
|
|
1,035,850
|
|
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, 2005 and 2004
are
calculated using weighted average process in effect as of those dates. Those
prices were $6.75 and $6.25 respectively, per Mcf of natural gas, and $44.50
and
$32.75 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 carryforwards
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, 2005 and 2004 are
as
follows:
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Future
cash flows
|
|
$
|
12,747,600
|
|
$
|
65,105,641
|
|
Future
production costs and taxes
|
|
|
(1,939,000
|
)
|
|
(2,769,464
|
)
|
Future
development costs
|
|
|
(745,000
|
)
|
|
(4,740,000
|
)
|
Future
income tax expense
|
|
|
(3,119,716
|
)
|
|
(17,854,815
|
)
|
Future
cash flows
|
|
|
6,943,884
|
|
|
39,741,362
|
|
Discount
at 10% for timing of cash flows
|
|
|
(3,463,248
|
)
|
|
(16,591,415
|
)
|
Discounted
future net cash flows from proved reserves
|
|
$
|
3,480,636
|
|
$
|
23,149,947
|
|
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, 2005 and
2004.
|
|
April
30,
|
|
|
|
2005
|
|
2004
|
|
Balance,
beginning of year
|
|
$
|
23,149,947
|
|
$
|
13,165,412
|
|
Sales,
net of production costs and taxes
|
|
|
(784,409
|
)
|
|
(773,033
|
)
|
Changes
in prices and production costs
|
|
|
7,490,059
|
|
|
9,737,935
|
|
Revisions
of quantity estimates
|
|
|
(39,206,898
|
)
|
|
5,505,439
|
|
Development
costs incurred
|
|
|
3,995,000
|
|
|
-
|
|
Net
changes in income taxes
|
|
|
8,836,937
|
|
|
(4,485,806
|
)
|
Balances,
end of year
|
|
$
|
3,480,636
|
|
$
|
23,149,947
|
|
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”).
Business
Strategy: Growth through the Drillbit
Our
goal
is to maximize shareholder value through the execution of a business strategy
designed to capitalize on our strengths and the continued expansion of our
operations through the growth of our oil and gas reserves. We believe this
can
best be achieved by:
· |
Focusing
on the development, drilling and production of natural gas and crude
oil
in east Tennessee’s Appalachian Basin. Appalachian gas sells at a premium
price to Henry Hub, due to its proximity to major consuming regions.
|
· |
Manage
risk exposure by market testing prospects and optimizing our working
interest--Drilling and development capital will be raised through
partnership drilling programs where Miller keeps up to a 50% working
interest, therefore limiting our financial and operating risks by
varying
our level of participation. We also seek to operate our projects
in order
to control costs associated with drilling and the timing of the drilling.
|
· |
Exploration
Activities--During 2006 we plan to focus our exploration activities
on
projects that are near currently owned productive fields, we believe
that
we can successfully add growth through exploratory activities given
the
much improved technology, and our experienced technical staff. We
have
allocated approximately 1 million dollars to our 2006 development
budget
for exploration activities.
|
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.
Competition
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, 2005.
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 11full-time employees, however, when we commence a full-scale
drilling program, we may employ up to as many as 10 additional subcontractors
or
temporary employees.
Risk
Factors
An
investment in shares of our common stock involves a high degree of risk.
Potential investors should consider the following factors, in addition to other
information provided by us in our filings with the SEC, in evaluating our
business and proposed activities before purchasing our shares.
General
Risks Related To Our Business
Our
business may fail if we do not raise additional money.
We
will
require additional funding to realize our future goals of conducting the oil
and
gas exploration operations on properties under lease and acquiring additional
oil and gas properties for development. We anticipate that our additional
funding will come from the sale of fractional working interests to investors
participating in our oil and gas partnerships and equity or debt financing,
which may be very difficult for our highly speculative enterprise. We can not
assure you that any additional funding will be available to us, or if it is
available, that the terms of the funding will be satisfactory to us.
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.
Our
current petroleum engineering report has substantially revised downward previous
estimates of our petroleum reserves.
Our
current petroleum engineer, Netherland Sewell & Associates, Inc. (“NSAI”),
in its report dated June 28, 2005, estimated that our current petroleum “proven”
reserves, calculated on the basis of a discounted cash flow analysis, are valued
at approximately $3.5 million. This estimate is a significant reduction from
the
estimate at April 30, 2004 of approximately $23 million of proven reserves
previously provided to us by our former petroleum engineering firm.
Our
future success will depend on the price of oil and gas.
Our
revenue comes primarily from the sale of oil and gas. Prices and markets for
oil
and gas are unpredictable, highly volatile, potentially subject to government
fixing, pegging, controls or any combination of these or other factors and
respond to changes in domestic, international, political, social, and economic
environments. If oil and gas prices go below our costs and expenses of operating
our company, we will lose money.
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.
Compliance
with governmental regulations can be costly and can limit our planned
operations.
We
face
many state and federal laws, rules and regulations covering the safety of our
operations, environmental conditions and other facets of our business. These
laws, rules and regulations can be expensive and may seriously limit our ability
to conduct our intended business operations. (See Description of
Business--"Governmental Approvals and Regulation” and “Environmental
Compliance.”)
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.
You
will not be able to elect our directors or officers.
Deloy
Miller, our CEO, currently owns 43% of our stock, on a fully diluted basis.
Although he does not have absolute voting control, he is still in a position
to
exert substantial influence on the election of all directors, who in turn elect
all of the officers. You will have little or no ability to influence the
direction of Miller Petroleum.
Indemnification
of Directors, Officers, Employees and Agents
Miller
Petroleum currently does not have a Directors and Officers Insurance
Policy.
Available
Information
We
file
annual, quarterly and current reports and other information with the Securities
and Exchange Commission. You may read and copy any document we file at the
SEC’s
public reference room at Room 1024, 450 Fifth Street, NW, Washington, D.C.
20549. Please call the SEC at 1-800-SEC-0330 for information on the public
reference room.
In
addition, we are electronic filers and our reports and information filed with
the SEC are available on the SEC’s website located at www.sec.gov.
Our
website is located at www.millerpetroleum.com.
Under
the “Archive” section of the website, you may access our most recent press
releases.
Item
2. Properties.
Our
executive offices presently comprise approximately 6,300 square feet on 14
acres
of land in Huntsville, Tennessee that the company owns.
Please
see “Current Business” for a description of our oil and gas leases. Please also
refer Management’s Discussion and Analysis or Plan of Operation—“Results of
Operations” for additional disclosure regarding our oil and gas operations in
accordance with pursuant to Industry Guides 2 of the Securities and Exchange
Act
(the “Act”).
Item
3. Legal
Proceedings.
None.
Item
4. Submission
of Matters to a Vote of Stockholders.
No
proposals were submitted for approval by our shareholders during the fourth
quarter ended April 30, 2005.
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.
|
|
High
|
|
Low
|
|
Quarter
Ended:
|
|
Bid
Prices ($)
|
|
|
|
|
|
|
|
July
31, 2003
|
|
|
0.55
|
|
|
0.55
|
|
October
31, 2003
|
|
|
0.68
|
|
|
0.45
|
|
January
31, 2004
|
|
|
0.45
|
|
|
0.35
|
|
April
30, 2004
|
|
|
0.91
|
|
|
0.59
|
|
|
|
|
|
|
|
|
|
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 275 stockholders of record of our common stock as of July
25,
2005.
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
EQUITY
COMPENSATION PLAN INFORMATION
The
table
below provides information, as of April 30, 2005, 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
|
540,000(1)
|
1.30
|
--
|
Total
|
540,000
|
1.30
|
--
|
Recent
Sales of Unregistered Securities
None.
Share
Repurchases
None.
Item
6. Management’s
Discussion and Analysis or Plan of Operation.
The
following discussion is intended to facilitate an understanding of our business
and results of operations. It should be read in conjunction with our
consolidated financial and the accompanying notes to the consolidated financial
statements included elsewhere in this Annual Report.
We
have
more than approximately 43,000 acres under lease in Tennessee. About
90% of these 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.
Currently, We are
offering five to twenty well drilling programs to "accredited investors" or
"sophisticated investors" to help spread the risk associated with drilling
projects and to facilitate investor returns. We will sell up to a 70% working
interest to investors while retaining a 30% working interest. Each program
will
be made up of five to fifteen Chattanooga Shale wells on its Koppers South
acreage.
In
June
of 2001, we made a conventional Big Lime gas discovery, on the Lindsay Land
Company lease jointly owned by Delta Producers, Inc. and Miller. Currently
there
are six producing wells on the property. There are at a minimum twenty five
additional drill sites on this 3,400 acre lease which is situated near
Caryville, Tennessee.
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.
Results
of Operations
In
fiscal
2005, we increased our capitalized costs of oil and gas properties
from $2,638,005 to $2,941,832. Our development costs for oil and gas
properties decreased from $565,779 to $549,687. Estimates of proved
reserves of oil decreased from 350,937 barrels to 93,825 and estimates of proved
reserves of natural gas decreased from 8,696,519 Mcf to 1,249,566 Mcf. Proved
developed producing reserves of oil decreased to 60,734 barrels from 62,106
barrels and proved developed producing reserves of natural gas decreased to
697,916 Mcf from 1,035,850 Mcf. These decreases were primarily due to a change
in the evaluations by our new engineering firm NSAI, which reclassified
previous estimates of proved reserves as possible and probable. (See
Description of Business—“Oil and Gas Reserve Analyses.” in this Annual Report.)
During fiscal 2005, future cash flows discounted 10% after income taxes from
proved reserves decreased from $23,149,947 to $3,480,639. Our oil and gas
revenue was $784,409 for fiscal 2005, up from $773,033 for fiscal 2004. Volatile
changes in the price of natural gas and oil partially offset by normal declines
in our production curves brought about this increase. During fiscal 2005,
service and drilling revenue was $209,680, down from $1,186,823, in part due
to the disposal of a drilling rig. Cost of revenue from service and
drilling decreased by $682,943 from Fiscal 2004 to Fiscal 2005. The drilling
rig
was old and in need of major repairs. To acquire new drill pipe, hammers and
a
compressor would cost $320,000, and likely the motor would need to be replaced
to continue using the rig. The cost of repairs, combined with high worker’s
compensation insurance rates, would have resulted in a negative cash flow to
the
Company. At the time the rig was sold it was not being utilized, and management
believed that it was in the best interests of the Company sell the rig and
use
the funds to enhance the Company’s oil and gas leases. Retail sales increased
from $6,939 in fiscal 2004, to $35,947 in fiscal 2005 primarily due to the
market volatility, and are included in service and drilling revenue for
financial statement purposes.
During
fiscal 2005, Miller Petroleum produced 75 MMBTUs of natural gas, with an average
price of $6.28 per MMBTU. Production decreased from about 88 MMBTUs in fiscal
2004, and the average price per MMBTU was $5.63. The following tables reflect
our production figures for the fiscal years ended April 30, 2005, and 2004
Fiscal
Year
|
|
Average
Net
Production
Gas
/MBTU
|
|
Sales
Price
/MMBTU
|
|
2004
|
|
|
88,000
|
|
$
|
5.63
|
|
2005
|
|
|
75,000
|
|
$
|
6.28
|
|
Fiscal
Year
|
|
Average
Net
Barrels
of Oil
|
|
Sales
Price
|
|
2004
|
|
|
10,100
|
|
$
|
27.30
|
|
2005
|
|
|
7,500
|
|
$
|
40.48
|
|
|
|
2003
|
|
2004
|
|
2005
|
|
Net
Productive Wells
|
|
|
22.60
|
|
|
20.20
|
|
|
20.20
|
|
Developed
Acreage
|
|
|
1,480
|
|
|
1,480
|
|
|
1,480
|
|
Undeveloped
Acreage
|
|
|
41,120
|
|
|
41,120
|
|
|
41,120
|
|
Net
Productive Exploratory Wells
|
|
|
0
|
|
|
0
|
|
|
0
|
|
Net
Dry Exploratory Wells
|
|
|
0.24
|
|
|
0.30
|
|
|
0.30
|
|
Net
Productive Developmental Wells
|
|
|
1.408
|
|
|
1.20
|
|
|
1.20
|
|
Net
Dry Developmental Wells
|
|
|
0
|
|
|
0
|
|
|
0
|
|
Liquidity
Cash
provided by operating activities was $154,580 for fiscal 2005, a reduction
of
$203,287 from operating activities of $357,867 in fiscal 2004. 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 43,000 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.
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.
Subsequent
to year end, we drilled ten (10) gas wells on four (4) properties. Based on
flow
tests, seven (7) of the wells are producing gas. Our net production volume
was
expected to be about 600,000 Mcf per month. We expect these wells to produce
an
additional $8,000 to $10,000 per month in net gas revenues beginning in October
to November 2005.
Item
7. Financial Statements.
INDEX
TO FINANCIAL STATEMENTS
|
|
|
|
Report
of Independent Certified Public Accountants
|
21
|
|
|
Consolidated
Balance Sheet
|
22-23
|
|
|
Consolidated
Statements of Operations
|
24
|
|
|
Consolidated
Statements of Stockholders' Equity
|
25
|
|
|
Consolidated
Statements of Cash Flows
|
26
|
|
|
Notes
to the Consolidated Financial Statements
|
27-43
|
MILLER
PETROLEUM, INC.
CONSOLIDATED
FINANCIAL STATEMENTS
April
30,
2005 and 2004
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, 2005 and April 30, 2004 and the related
consolidated statements of operations, changes in stockholders’ equity and cash
flows for the years then ended. These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audits to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. The Company
is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our 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, 2005 and 2004, 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.
As
discussed in Note 2 to the financial statements, the Company has restated its
financial statements for the year ended April 30, 2004 to properly reflect
transactions in its common stock.
/s/
Rodefer Moss & Co, PLLC
Knoxville,
Tennessee
July
28,
2005
Miller
Petroleum, Inc.
Consolidated
Balance Sheets
|
|
April
30,
2005
|
|
Restated
April
30,
2004
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
2,362
|
|
$
|
2,416
|
|
Accounts
receivable
|
|
|
182,951
|
|
|
117,167
|
|
Current
portion of note receivable
|
|
|
47,000
|
|
|
18,875
|
|
Inventory
|
|
|
67,389
|
|
|
50,911
|
|
Deferred
offering costs
|
|
|
88,842
|
|
|
88,842
|
|
Prepaid
expenses
|
|
|
—
|
|
|
66,590
|
|
Total
Current Assets
|
|
|
388,544
|
|
|
344,801
|
|
FIXED
ASSETS
|
|
|
|
|
|
|
|
Machinery
|
|
|
941,601
|
|
|
1,036,802
|
|
Vehicles
|
|
|
333,583
|
|
|
385,465
|
|
Buildings
|
|
|
313,335
|
|
|
313,335
|
|
Office
equipment
|
|
|
72,549
|
|
|
72,549
|
|
Less:
accumulated depreciation
|
|
|
(939,579
|
)
|
|
(905,531
|
)
|
Total
Fixed Assets
|
|
|
721,489
|
|
|
902,620
|
|
OIL
AND GAS PROPERTIES
|
|
|
2,941,832
|
|
|
2,638,005
|
|
(On
the basis of successful
efforts
accounting)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIPELINE
FACILITIES
|
|
|
206,298
|
|
|
218,637
|
|
OTHER
ASSETS
|
|
|
|
|
|
|
|
Land
|
|
|
496,500
|
|
|
511,500
|
|
Investments
|
|
|
500
|
|
|
500
|
|
Well
equipment and supplies
|
|
|
431,462
|
|
|
443,942
|
|
Long-term
notes receivable
|
|
|
—
|
|
|
56,338
|
|
Cash
- restricted
|
|
|
71,000
|
|
|
71,000
|
|
Total
Other Assets
|
|
|
999,462
|
|
|
1,083,280
|
|
TOTAL
ASSETS
|
|
$
|
5,257,625
|
|
$
|
5,187,343
|
|
See
notes
to consolidated financial statements.
Miller
Petroleum, Inc.
Consolidated
Balance Sheets
|
|
April
30,
|
|
April
30,
|
|
|
|
2005
|
|
2004
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
CURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable - trade
|
|
$
|
330,620
|
|
$
|
335,556
|
|
Accrued
expenses
|
|
|
224,306
|
|
|
116,011
|
|
Current
portion of notes payable
|
|
|
|
|
|
|
|
Related
parties
|
|
|
—
|
|
|
1,360,000
|
|
Other
|
|
|
—
|
|
|
176,624
|
|
Total
Current Liabilities
|
|
|
554,926
|
|
|
1,988,191
|
|
|
|
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
payable
|
|
|
|
|
|
|
|
Related
parties
|
|
|
1,673,693
|
|
|
269,230
|
|
Other
|
|
|
655,646
|
|
|
616,739
|
|
Total
Long-Term Liabilities
|
|
|
2,329,339
|
|
|
885,969
|
|
Total
Liabilities
|
|
|
2,884,265
|
|
|
2,874,160
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock: 500,000,000 shares
authorized at $0.0001
par
value,
9,396,856
and 8,378,856 shares
issued and outstanding
|
|
|
939
|
|
|
838
|
|
Additional
paid-in capital
|
|
|
4,495,498
|
|
|
4,173,998
|
|
Accumulated
deficit
|
|
|
(2,123,077
|
)
|
|
(1,861,653
|
)
|
Total
Stockholders’ Equity
|
|
|
2,373,360
|
|
|
2,313,183
|
|
STOCKHOLDERS’
EQUITY
|
|
$
|
5,257,625
|
|
$
|
5,187,343
|
|
See
notes
to consolidated financial statements.
MILLER
PETROLEUM, INC.
Consolidated
Statements of Operations
|
|
Year
Ended
April
30,
|
|
April
30,
|
|
|
|
2005
|
|
2004
|
|
REVENUES
|
|
|
|
|
|
Oil
and gas revenue
|
|
$
|
784,409
|
|
$
|
773,033
|
|
Service
and drilling revenue
|
|
|
245,627
|
|
|
1,193,762
|
|
Total
Revenue
|
|
|
1,030,036
|
|
|
1,966,795
|
|
|
|
|
|
|
|
|
|
COSTS
AND EXPENSES
|
|
|
|
|
|
|
|
Oil
and gas cost
|
|
|
177,287
|
|
|
228,301
|
|
Service
and drilling cost
|
|
|
82,730
|
|
|
765,673
|
|
Selling,
general and administrative
|
|
|
604,040
|
|
|
567,112
|
|
and
amortization
|
|
|
366,279
|
|
|
233,439
|
|
Total
Costs and Expenses
|
|
|
1,230,336
|
|
|
1,794,525
|
|
FROM
OPERATIONS
|
|
|
(200,300
|
)
|
|
172,270
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
Interest
income
|
|
|
875
|
|
|
1,918
|
|
Gain
on sale of equipment
|
|
|
157,562
|
|
|
42,897
|
|
Interest
expense
|
|
|
(219,561
|
)
|
|
(228,436
|
)
|
Total
Other Expense
|
|
|
(61,124
|
)
|
|
(183,621
|
)
|
INCOME
TAXES
|
|
|
—
|
|
|
—
|
|
NET
LOSS
|
|
$
|
(261,424
|
)
|
$
|
(11,351
|
)
|
BASIC
AND DILUTED
|
|
|
|
|
|
|
|
LOSS
PER SHARE
|
|
$
|
(0.03
|
)
|
$
|
(0.00
|
)
|
BASIC
WEIGHTED AVERAGE NUMBER OF
SHARES
OUTSTANDING
|
|
|
9,030,738
|
|
|
8,350,048
|
|
See
notes
to consolidated financial statements.
MILLER
PETROLEUM, INC.
Consolidated
Statements of Stockholders’ Equity
|
|
Common
Shares
|
|
Shares
Amount
|
|
Capital
|
|
Deficit
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated
balance, April
30, 2003
|
|
|
8,293,856
|
|
$
|
830
|
|
$
|
4,000,871
|
|
|
($1,850,302
|
)
|
$
|
2,151,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of shares in connection
with
deferred offering
|
|
|
85,000
|
|
|
8
|
|
|
88,834
|
|
|
—
|
|
|
88,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of warrants as prepayment
of
financing costs
|
|
|
—
|
|
|
—
|
|
|
59,293
|
|
|
—
|
|
|
59,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of options for
services
|
|
|
—
|
|
|
—
|
|
|
25,000
|
|
|
—
|
|
|
25,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss for the year ended
April 30, 2004
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,351
|
)
|
|
(11,351
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated
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
|
|
|
27
|
|
|
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
|
|
|
50
|
|
|
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
|
|
$
|
939
|
|
$
|
4,495,498
|
|
$
|
(2,123,077
|
)
|
$
|
2,373,360
|
|
See
notes
to consolidated financial statements.
Miller
Petroleum, Inc.
Consolidated
Statements of Cash Flows
|
|
April
30,
|
|
April
30,
|
|
|
|
2005
|
|
2004
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
loss
|
|
$
|
(261,424
|
)
|
$
|
(11,351
|
)
|
Adjustments
to Reconcile Net Loss to
|
|
|
|
|
|
|
|
Net
Cash Provided by Operating Activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
393,061
|
|
|
265,950
|
|
Gain
on sale of equipment
|
|
|
(157,562
|
)
|
|
(42,897
|
)
|
Options
issued in exchange for services
|
|
|
—
|
|
|
25,000
|
|
Common
Stock issued in exchange for services
|
|
|
119,600
|
|
|
—
|
|
Changes
in Operating Assets and Liabilities:
|
|
|
|
|
|
|
|
Increase
in accounts receivable
|
|
|
(65,784
|
)
|
|
(8,894
|
)
|
Increase
in inventory
|
|
|
(16,478
|
)
|
|
(13,092
|
)
|
Decrease
(increase) in prepaid expenses
|
|
|
39,808
|
|
|
(10,398
|
)
|
Increase
(decrease) in accounts payable
|
|
|
(4,936
|
)
|
|
121,729
|
|
Increase
in accrued expenses
|
|
|
108,295
|
|
|
31,820
|
|
Net
Cash Provided by Operating Activities
|
|
|
154,580
|
|
|
357,867
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Proceeds
from sales of investments
|
|
|
—
|
|
|
12,812
|
|
Proceeds
from sale of land
|
|
|
15,000
|
|
|
—
|
|
Purchase
of equipment
|
|
|
(1,500
|
)
|
|
(113,834
|
)
|
Purchase
of oil and gas properties
|
|
|
(386,687
|
)
|
|
(565,779
|
)
|
Proceeds
from sale of equipment
|
|
|
187,682
|
|
|
392,499
|
|
Decrease
in restricted cash
|
|
|
—
|
|
|
3,000
|
|
Changes
in note receivable
|
|
|
28,125
|
|
|
14,201
|
|
Net
Cash Used by Investing Activities
|
|
|
(157,380
|
)
|
|
(257,101
|
)
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Proceeds
from issuance of stock
|
|
|
96,001
|
|
|
—
|
|
Payments
on Notes Payables
|
|
|
(137,716
|
)
|
|
(502,376
|
)
|
Proceeds
from borrowings
|
|
|
44,461
|
|
|
400,662
|
|
Net
Cash Provided (Used) by Financing Activities
|
|
|
2,746
|
|
|
(101,714
|
)
|
NET
DECREASE IN CASH
|
|
|
(54
|
)
|
|
(948
|
)
|
CASH
AND CASH EQUIVALENTS,
BEGINNING
OF YEAR
|
|
|
2,416
|
|
|
3,364
|
|
CASH
AND CASH EQUIVALENTS,
END
OF YEAR
|
|
$
|
2,362
|
|
$
|
2,416
|
|
See
notes
to consolidated financial statements.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
a.
Oganization and Basis of Presentation
These
consolidated financial statements include the accounts of Miller Petroleum,
Inc.
(“The Company”) formerly Triple Chip Systems, 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.
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 field by field basis using the units-of-production method
based
upon proved reserves. Acquisition costs are amortized by using total proved
reserves as the denominator. Development costs are amortized using proved
developed reserves, rather than total proved reserves, as the
denominator.
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.
c.
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 years ended April 30, 2005 and
2004
the Company has recognized no changes or allowances for impairment.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
d.
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, 2005 and 2004, the assumed
effects of the exercise of the options and warrants to purchase 555,177 and
2,435,672 and shares of common stock that were outstanding at April 30, 2005
and
2004, respectively, and the application of the treasury stock method would
have
been anti-dilutive. Therefore, there are no diluted per share amounts in the
2005 and 2004 statements of operations.
e.
Cash Equivalents
The
Company considers all highly liquid investments with a maturity of three months
or less when purchased to be cash equivalents.
f.
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.
g.
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:
Class
|
Lives
(Years)
|
Building
|
40
|
Machinery
and equipment
|
5-20
|
Vehicles
|
5-7
|
Office
equipment
|
5
|
Depreciation
expense for the years ended April 30, 2005 and 2004 was $120,419 and $182,047
respectively.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
h.
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 2005 and
2004. Retail sales of various parts and equipment is recognized as income at
the
time the item is sold and, under the 10% rule, has been combined with service
and drilling revenue.
i.
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 $6,944 and $8,684 at April 30, 2005 and
2004, respectively. Accounts receivable more than 90 days old were $32,498
at
April 30, 2005 and $ 22,722 at April 30, 2004.
j.
Inventory
Inventory
consists primarily of crude oil in tanks and is carried at market
value.
k.
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.
l.
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”)
and Glover Petroleum Consultants, of Crossville, Tennessee (“Glover”), for the
years ended April 30, 2005 and 2004, 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.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
m.
Reclassifications
Certain
amounts and balances pertaining to the April 30, 2004 financial statements
have
been reclassified to conform with the April 30, 2005 financial statement
presentations.
n.
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.
o.
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.
p.
Recent Accounting Pronouncements
In
June
2003, the FASB approved SFAS 150, “Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity” SFAS 150 establishes
standards for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and equity. This Statement
is effective for financial instruments entered into or modified after May 31,
2003, and otherwise was effective at the beginning of the first interim period
beginning after June 15, 2003. SFAS 150 did not have an effect on the Company’s
financial position.
In
December 2003, the FASB issued a revised interpretation No 46, “Consolidation of
Variable Interest Entities.” The interpretation clarifies the application of
Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to
certain types of entities. Adoption did not have an impact on the Company’s
financial statements.
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 is not expected to
affect the Company’s consolidated financial statements.
In
December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This
statement is a revision to SFAS No. 123, “Accounting for Stock-Based
Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to
Employees.” This statement establishes standards for the accounting for
transactions in which an entity exchanges its equity instruments for goods
or
services, primarily focusing on the accounting for transactions in which an
entity obtains employee services in share-based payment transactions. Companies
will be required to measure the cost of employee services received in exchange
for an award of equity instruments based on the grant date fair value of the
award (with limited exceptions). That cost will be recognized over the period
during which an employee is required to provide service, the requisite service
period (usually the vesting period), in exchange for the award. The grant date
fair value of employee share options and similar instruments will be estimated
using option-pricing models.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
If
an
equity award is modified after the grant date, incremental compensation cost
will be recognized in an amount equal to the excess of the fair value of the
modified award over the fair value of the original award immediately before
the
modifications for small business issuers. SFAS No. 123R will be effective for
periods beginning after December 15, 2005. Accordingly, the Company will adopt
SFAS No. 123R in its fourth quarter of fiscal 2006. The Company is currently
evaluating the provisions of SFAS No. 123R and has not determined the impact
that this Statement will have on its results of operations or financial
position.
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 is not expected to impact the consolidated financial position, result
of operations or cash flows.
q.
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 $406,246 of the Company’s total revenue which was
about 39% of the Company’s total revenue.
Nami
Resources, LLC accounted for $79,111 of the Company’s total revenue which was
about 8% of the Company’s total revenue.
South
Kentucky Purchasing Co. - South Kentucky accounted for $256,235 of the Company’s
total revenue which was about 25% of the Company’s total revenue. South Kentucky
purchases all of the Company’s crude oil.
NOTE
2 -
RESTATEMENT OF FINANCIAL STATEMENTS
The
Company previously issued its financial statements as of and for the year ended
April 30, 2004, which were included in its Form 10KSB filed on July 29, 2004.
The filing included a report, dated July 20, 2004, which expressed an
unqualified opinion on those statements by independent accountants who had
not
registered with the Public Companies Accounting Oversight Board (PCAOB).
Additionally, the report, failed to note the conduct of the audit in accordance
with the standards of the PCAOB. Because of these failures, the Company’s
financial reporting was not in compliance with rules established by the
Securities Exchange Commission, and accordingly, the Company engaged other
auditors to conduct a PCAOB-compliant audit of its April 30, 2004 financial
statements.
In
connection with the PCAOB-compliant audit of the 2004 financial statements,
management identified errors in amounts previously reported in the Company’s
financial statements for the years ended April 30, 2002, 2003 and 2004. The
Company made an error in failing to record, in total, bad debt expense of
approximately $237,500 in relation to the non-payment of a stockholder
receivable in 2002, resulting in a misstatement of retained earnings in 2002,
2003 and 2004. In 2004 the Company’s previously issued financial statements
failed to include compensation and interest expense of approximately $57,000
in
connection with issuances of options and warrants. The Company, therefore,
is
restating its financial statements beginning with financial position at April
30, 2002 and including its annual financial statements for 2003 and
2004.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
3 -
STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURE
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
CASH
PAID FOR:
|
|
|
|
|
|
Interest
|
|
$
|
70,990
|
|
$
|
195,919
|
|
Income
Taxes
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
NON-CASH
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Financing
costs from issuance of warrants
|
|
|
—
|
|
|
59,293
|
|
Common
stock issued for deferred offering costs
|
|
|
—
|
|
|
88,842
|
|
Stock
issued for mineral rights
|
|
|
106,000
|
|
|
—
|
|
Common
stock issued for services
|
|
|
119,600
|
|
|
—
|
|
Conversion
of account to note payable
|
|
|
—
|
|
|
250,689
|
|
Amortization
of prepaid interest
|
|
|
26,786
|
|
|
32,511
|
|
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. If the proposed offering were to be permanently
abandoned, the costs incurred would be charged to expense in the period the
decision is made. If the proposed offering is successful, the contribution
to
shareholders’ equity will be reduced by these costs.
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 $549,687 and $565,779 of
oil
and gas properties for the years ended April 30, 2005 and 2004, respectively,
and recorded $245,860 and $43,800 of amortization expense for the years ended
April 30, 2005 and 2004, respectively.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
6 -
LONG-TERM DEBT AND SUBSEQUENT EVENT
The
Company had the following debt obligations at April
30,
2005 and April 30 2004
|
|
|
2005
|
|
|
2004
|
|
Note
payable to First National Bank of Oneida secured by stock and equipment,
bearing interest at 7.50% due in quarterly payments of $15,000 on
January
14, 2006 |
|
$ |
85,097 |
|
$ |
136,650 |
|
|
|
|
|
|
|
|
|
Note
payable to American Fidelity Bank secured by equipment, bearing interest
at 4.00% due in monthly payments of $2,272 with final payment due
in
August 2008 |
|
$ |
353,891 |
|
$ |
366,724 |
|
|
|
|
|
|
|
|
|
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 |
|
$ |
19,380 |
|
|
|
|
|
|
|
|
|
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 |
|
$
|
250,688
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
6 -
LONG-TERM DEBT AND SUBSEQUENT EVENT (Continued)
|
|
2005
|
|
2004
|
|
Note
payable to related party, unsecured, interestat 7.00%
with
payments due yearly with the principle due in May of
2005
|
|
$
|
59,692
|
|
$
|
15,230
|
|
|
|
|
|
|
|
|
|
Note
payable to related party secured by twelve oil
and
gas wells, bearing interest at 9.00% and requiring
interest payments quarterly with principle due in December
2004
|
|
$
|
1,110,000
|
|
$
|
1,110,000
|
|
|
|
|
|
|
|
|
|
Note
payable to related party bearing interest at 8.00% with
principle due in December 2005
|
|
$
|
254,000
|
|
$
|
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 principle due in December 2004
|
|
$
|
250,000
|
|
$
|
250,000
|
|
|
|
|
|
|
|
|
|
Note
payable to Home Federal Bank secured by equipment,
bearing
interest at 9.75% due in monthly payments with final
payment
due in August 2005
|
|
|
—
|
|
$
|
7,001
|
|
|
|
|
|
|
|
|
|
Note
payable to General Motors Acceptance
Corporation secured by a pickup truck, bearing interest at 0.00%
due
in
monthly payments of $721 with final payment due in
October
2004
|
|
|
—
|
|
$
|
5,768
|
|
|
|
|
|
|
|
|
|
Note
payable to General Motors Acceptance Corporation
Secured
by a Suburban, bearing interest at 0.00% due in
monthly
payments of $894 with final payment due in
October
2004
|
|
|
—
|
|
$
|
7,152
|
|
|
|
|
|
|
|
|
|
Total
notes payable
|
|
$
|
2,329,339
|
|
$
|
2,422,593
|
|
Less
current maturities
|
|
|
—
|
|
|
1,536,624
|
|
Notes
payable - long-term
|
|
$
|
2,329,339
|
|
$
|
885,969
|
|
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 the balance sheet date. 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,
2005 and 2004
NOTE
6 -
LONG-TERM DEBT AND SUBSEQUENT EVENT (Continued)
The
notes
are due on June 30, 2006, with interest only payments accruing at 12% during
the
interim. The notes are convertible into common stock at the lesser price of
$1.50 per share or the price of common stock issued to investors in a planned
equity offering of the Company. The notes contain restrictive covenants
pertaining to debt to equity, asset and liquidity ratios, and imposes other
affirmative conditions upon the Company. Upon event of default, the interest
rate of the note resets to the highest rate allowed by law.
NOTE
7 -
RELATED PARTY TRANSACTIONS
The
Company has a note payable to Sharon Miller (wife of Deloy Miller, majority
stockholder) for $59,693 at April 30, 2005. The note is payable with a principle
payment of $59,693 due in May 2006. The note is the balance remaining on the
original purchase of the property that houses the Company’s
offices.
The
Company issued a note 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. This note payable was issued to raise working capital. The related
party notes were due to members of the Company’s board of directors or their
immediate families.
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 Company's asset retirement
obligations relate primarily to the plugging, dismantlement, removal, site
reclamation and similar activities of its oil and gas properties. Prior to
adoption of this statement, such obligations were accrued ratably over the
productive lives of the assets through its liability for such amounts. The
Company adopted SFAS 143 beginning on May 1, 2003 and using a credit-adjusted
risk free rate of 12%, an estimated useful life of wells ranging from five
to
forty-five years and estimated plugging and abandonment cost of $1,000 per
well,
the Company recorded a non-cash charge related to the cumulative effect of
a
change in accounting principle of $7,592.
The
changes in the Company’s liability from adoption at July 1, 2004 to April
30, 2005 were as follows:
Liability
from adoption of SFAS No. 143 May 1, 2003
|
|
$
|
11,538
|
|
|
|
|
|
|
Accretion
expense for 2004
|
|
|
1,768
|
|
|
|
|
|
|
Asset
retirement obligation as of December 31, 2003
|
|
|
13,306
|
|
|
|
|
|
|
Accretion
expense for 2004
|
|
|
1,890
|
|
|
|
|
|
|
Asset
retirement obligation as of December 31, 2004
|
|
$
|
15,196
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
9 -
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:
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Federal
statutory rate
|
|
|
34 |
% |
|
34 |
% |
Federal
tax benefit at statutory rate
|
|
$
|
89,000
|
|
$
|
13,000
|
|
State
income tax benefit
|
|
|
19,600
|
|
|
2,800
|
|
|
|
|
|
|
|
|
|
Increase
in deferred tax asset and
valuation
allowance
|
|
$
|
108,600
|
|
$
|
15,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
Net
operating loss carryforward
|
|
$
|
1,451,000
|
|
$
|
1,362,000
|
|
|
|
|
|
|
|
|
|
|
|
|
1,451,000
|
|
|
1,362,000
|
|
|
|
|
|
|
|
|
|
Valuation
allowance
|
|
|
(1,451,000
|
)
|
|
(1,362,000
|
)
|
|
|
|
|
|
|
|
|
Net
deferred taxes
|
|
$ |
— |
|
$
|
— |
|
The
Company recorded a valuation allowance at April 30, 2005, and 2004 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, 1989
of
approximately $ 4,000,000 at April 30, 2005. The carry forwards begin expiring
in 2005.
NOTE
10 -
STOCKHOLDERS’ EQUITY
During
the year ended April 30, 2004, the Company issued 85,000 shares for services
in
connection with a planned offering. The Company recorded $88,842 in deferred
offering costs on its balance sheet in connection with the
transaction.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
10 -
STOCKHOLDERS’ EQUITY (Continued)
In
August
2003, the Company issued 1,110,000 warrants to Sherri Ann Parker Lee and 250,000
warrants to William Parker Lee. The warrants were issued along with the note
payable to them dated August 13, 2003 and can be exercised for $0.80 per share,
and expired on January 1, 2005. The warrants were recorded as $59,293 of prepaid
financing costs and will be amortized to interest expense over the term of
the
loan. Interest expense connected with the warrants was $26,782 for the year
ended April 30, 2005.
In
March
2004, the Company issued 100,000 options in exchange for services. The warrants
can be exercised for $0.50 per share, and expire in March 2006. In connection
with the transaction the Company recorded an expense of $25,000.
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 restricted common stock in private placements
for
proceeds of $80,000. The sales transpired at discounts ranging from 66% to
43%
from prices prevailing for free-trading shares.
Further,
the Company issued 113,000 restricted shares of its common stock in exchange
for
services and 500,000 shares of its restricted common stock for leasehold
interests in oil and gas properties at a discount of 60% from prices prevailing
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.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
10 -
STOCKHOLDERS’ EQUITY (Continued)
Information
regarding the warrants at April 30, 2005 and 2004 is as follows:
|
|
2005
|
|
2004
|
|
|
|
Weighted
Shares
|
|
Average
Exercise
Price
|
|
Weighted
Shares
|
|
Average
Exercise
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
outstanding beginning of year
|
|
|
2,235,000
|
|
$
|
0.88
|
|
|
875,000
|
|
$
|
1.19
|
|
Options
canceled
|
|
|
1,695,000
|
|
|
0.77
|
|
|
100,000
|
|
|
2.00
|
|
Options
exercised
|
|
|
—
|
|
|
n/a
|
|
|
—
|
|
|
n/a
|
|
Options
granted
|
|
|
—
|
|
|
0.00
|
|
|
1,460,000
|
|
$
|
0.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
outstanding, end
of year
|
|
|
540,000
|
|
$
|
1.30
|
|
|
2,235,000
|
|
$
|
0.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
exercisable, end
of year
|
|
|
540,000
|
|
$
|
1.30
|
|
|
2,435,672
|
|
$
|
0.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option
price range, end
of year
|
|
|
|
|
|
|
|
|
|
|
$ |
0.46
to 2.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option
price range, exercised
shares
|
|
|
|
|
|
|
|
|
|
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
available for grant
at end of year
|
|
|
|
|
|
|
|
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average fair value
of options
granted
during the
year
|
|
|
|
|
|
n/a
|
|
|
|
|
$ |
0.05 |
|
For
non-employees, the fair value of stock options used to compute pro forma net
loss and loss per share disclosures is the estimated present value at grant
date
using the Black-Scholes option-pricing model with the following weighted average
assumptions for 2004. Expected volatility of 40%; a risk free interest rate
of
3.00% and an expected option life of 1 year, five months.
NOTE
11 -
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.
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
12 -
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
13 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited)
(1)
Capitalized Costs Relating to Oil and Gas Producing Activities at April 30,
2005
and 2004 is as follows:
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Proved
oil and gas properties
and
related lease equipment
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
$
|
3,841,996
|
|
$
|
3,362,316
|
|
Non-developed
|
|
|
31,053
|
|
|
31,053
|
|
|
|
|
3,873,049
|
|
|
3,393,369
|
|
Accumulated
depreciation and depletion
|
|
|
(931,217
|
)
|
|
(755,364
|
)
|
Net
Capitalized Costs
|
|
$
|
2,941,832
|
|
$
|
2,638,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
Costs Incurred in Oil and Gas Property Acquisition, Exploration,
and
Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
Acquisition
of Properties Proved and Unproved
|
|
$
|
—
|
|
$
|
—
|
|
Exploration
Costs
|
|
|
—
|
|
|
—
|
|
Development
Costs
|
|
|
549,687
|
|
|
565,779
|
|
Total
|
|
$
|
549,687
|
|
$
|
565,779
|
|
|
|
|
|
|
|
|
|
(3)
Results of Operations for Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
Production
revenues
|
|
$
|
784,409
|
|
$
|
773,033
|
|
|
|
|
|
|
|
|
|
Production
costs
|
|
|
177,287
|
|
|
228,301
|
|
Depreciation
and amortization
|
|
|
245,860
|
|
|
43,800
|
|
|
|
|
|
|
|
|
|
Results
of operations for producing activities
(excluding
corporate overhead and interest costs)
|
|
$
|
361,262
|
|
$
|
500,932
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
13 -
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, 2003
|
|
|
208,821
|
|
|
5,365,057
|
|
Discoveries
and extensions
|
|
|
68,903
|
|
|
718,160
|
|
Revisions
of previous estimates
|
|
|
79,169
|
|
|
2,642,073
|
|
Productions
|
|
|
(5,957
|
)
|
|
(28,771
|
)
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
Proved
developed producing reserves
at April 30, 2005
|
|
|
60,734
|
|
|
697,916
|
|
|
|
|
|
|
|
|
|
Proved
developed producing reserves
at April 30, 2004
|
|
|
62,106
|
|
|
1,035,850
|
|
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. and
Glover Petroleum Consultants of Crossville, Tennessee for the year ended April
30, 2005 and April 30, 2004, respectively. 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
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
13 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)
uncertain
at this time. Therefore, these proven undeveloped reserves are not being
included in the presentation of the oil and gas reserves at April 30, 2005,
nor
are such reserves being considered in calculating depreciation, depletion and
amortization expense for the year based on the April 30, 2005 and April 30,
2004
balance of the proven developed producing reserves set forth above.
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, 2005 and 2004. Estimated future cash flows were based on
independent reserves evaluation from Netherland Sewell & Associates, Inc.
and Glover Petroleum Consultants for the years ended April 30, 2005 and April
30, 2004, respectively. Because the standardized measure of future net cash
flows was prepared using the prevailing economic conditions existing at April
30, 2005 and 2004, 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, 2005 and 2004 were $44.50 and $32.75 per barrel of
oil
and $6.75 and $6.25 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, less applicable carry
forwards, for both regular and alternative minimum tax.
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, 2005 and 2004 is
as
follows:
|
|
2005
|
|
2004
|
|
Future
cash flows
|
|
$
|
12,747,600
|
|
$
|
65,105,641
|
|
Future
production costs and taxes
|
|
|
(1,939,000
|
)
|
|
(2,769,464
|
)
|
Future
development costs
|
|
|
(745,000
|
)
|
|
(4,740,000
|
)
|
Future
income tax expense
|
|
|
(3,119,716
|
)
|
|
(17,854,815
|
)
|
|
|
|
|
|
|
|
|
Future
cash flows before income
taxes
|
|
|
6,943,884
|
|
|
39,741,362
|
|
|
|
|
|
|
|
|
|
Discount
at 10% for timing of cash
flows
|
|
|
(3,463,248
|
)
|
|
(16,591,415
|
)
|
|
|
|
|
|
|
|
|
Discounted
future net cash flows from
proved reserves
|
|
$
|
3,480,636
|
|
$
|
23,149,947
|
|
MILLER
PETROLEUM, INC.
Notes
to
the Consolidated Financial Statements
April
30,
2005 and 2004
NOTE
13 -
S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)
Of
the
Company’s total proved reserves as of April 30, 2005 and 2004, approximately 59%
and 7%, respectively, were classified as proved developed producing, 11% and
4%,
respectively, were classified as proved developed non-
producing
and 30% and 89%, respectively, were classified as proved undeveloped. All of
the
Company’s reserves are located in the continental United States.
The
following table sets forth the changes in the standardized measure of discounted
future net cash flows from proved reserves for April 30, 2005 and
2004.
|
|
April
30,
|
|
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Balance,
beginning of year
|
|
$
|
23,149,947
|
|
$
|
13,165,412
|
|
|
|
|
|
|
|
|
|
Sales,
Net of production costs and taxes
|
|
|
(784,409
|
)
|
|
(773,033
|
)
|
|
|
|
|
|
|
|
|
Changes
in prices and production costs
|
|
|
7,490,059
|
|
|
9,737,935
|
|
Revisions
of quantity estimates
|
|
|
(39,206,898
|
)
|
|
5,505,439
|
|
Development
costs incurred
|
|
|
3,995,000
|
|
|
— |
|
Net
changes in income taxes
|
|
|
8,836,937
|
|
|
(4,485,806
|
)
|
Balances,
end of year
|
|
$
|
3,480,636
|
|
$
|
23,149,947
|
|
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, 2005, 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
|
58
|
Director
and Chief Executive Officer
|
Ernest
Payne
|
58
|
President
|
Charles
M. Stivers
|
43
|
Chief
Financial Officer and Director
|
Herbert
J. White
|
79
|
Vice
President and Director
|
Herman
E. Gettelfinger
|
72
|
Director
|
Gary
Bible
|
55
|
Vice
President of Geology
|
Teresa
Cotton
|
42
|
Secretary
and Treasurer
|
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.
Charles
M.
Stivers was
appointed Chief Financial Officer in 2004. 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.
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.
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, Greg Love
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 2005.
|
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
|
2005
2004
2003
|
$180,000
183,000
180,000
|
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
currently do not have any employment contracts with members of our management;
however, depending on our future operations and requirements, we may offer
long
term contracts to directors, executive officers or key employees in the future.
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 2005
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 July 25, 2005 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 9,466,856 shares outstanding on July [25], 2005.
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
|
|
43.2%
|
Ernest
Payne
|
105,000
|
(1)
|
*
|
Charles
M. Stivers
|
50,000
|
(2)
|
*
|
Herman
E.
Gettelfinger
|
342,901
|
(3)
|
3.62%
|
Herbert
J. White
|
300
|
|
*
|
All
directors and
executive officers (6 persons)
|
4.588,544
|
(4)
|
48.5%
|
|
|
|
|
Beneficial
Owner of
More Than 5%
|
|
|
|
Ratliff
Farms,
Inc.
|
500,000
|
|
5.28%
|
_________
*
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.
(3)
Includes 100,000 shares held by Mr. Gettelfinger’s spouse.
(4)
Includes 225,000 shares issuable upon the exercise of presently exercisable
stock options.
Item
12.
Certain Relationships and Related Transactions.
The
Company has a note payable to Sharon Miller (wife of Deloy Miller, a majority
stockholder), for $59,693 at April 30, 2005. The note is payable with interest
in May 2005. The note is the balance remaining on the original purchase of
the
property that houses the offices.
The
Company issued a note payable of $1,110,000 on August 13, 2003 at 9% with a
one
year term to Sherri Ann Parker Lee, and wife of William Parker Lee, a member
of
our Board of Directors.
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 member of our Board of
Directors.
The
company issued a note payable to William M. Thomas for $199,824 secured by
twelve oil and gas wells bearing interest at 9.00% and requiring interest
payments quarterly with principle due in December 2005.
The
company issued a note payable for $254,000 at 8% with principle due in December
2005 to Herman E. Gettelfinger.
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, 2005 and 2004 were as follows:
|
|
2005
|
|
2004
|
|
Audit
Fees
|
|
$
|
45,000
|
|
$
|
26,000
|
|
Audit-Related
Fees(a)
|
|
|
—
|
|
|
—
|
|
Total
Audit and Audit-Related Fees
|
|
$
|
45,000
|
|
|
26,000
|
|
|
|
|
|
|
|
|
|
Tax
Fees
|
|
|
—
|
|
|
—
|
|
All
Other Fees
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
45,000
|
|
$
|
26,000
|
|
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:
February 28, 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
|
|
Chairman
of the Board of Directors,
|
February
28, 2006
|
Deloy
Miller
|
|
and
Chief Executive
Officer
|
|
|
|
|
|
/s/
Lyle H. Cooper
|
|
Chief
Financial Officer
|
February
28, 2006
|
Lyle
H. Cooper
|
|
|
|
|
|
|
|
/s/
Charles M. Stivers
|
|
Director
|
February
28, 2006
|
Charles
M. Stivers
|
|
|
|
|
|
|
|
|
|
|
|
Herbert
J. White
|
|
Director
|
February
28, 2006
|
|
|
|
|
/s/
Herman E. Gettelfinger
|
|
|
|
Herman
E. Gettelfinger
|
|
Director
|
February
28, 2006
|