UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(MARK ONE)
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
FOR THE FISCAL YEAR ENDED APRIL 30, 2009
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
FOR THE TRANSITION PERIOD FROM __________________ TO __________________
COMMISSION FILE NUMBER: 33-2249-FW
MILLER PETROLEUM, INC.
(Exact name of registrant as specified in its charter)
TENNESSEE 62-1028629
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
3651 BAKER HIGHWAY, HUNTSVILLE, TN 37756
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (423) 663-9457
SECURITIES REGISTERED UNDER SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
NONE NOT APPLICABLE
SECURITIES REGISTERED UNDER SECTION 12(g) OF THE ACT:
NONE
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. [ ] Yes [X] No
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. [ ] Yes [X] No
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss. 232.405
of this chapter) during the preceding 12 (or for such shorter period that the
registrant was required to submit and post such files). Yes [ ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company:
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [ ] Smaller reporting company [X]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act) Yes [ ] No [X]
State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was sold, or the average bid and asked prices of such common equity, as of the
last business day of the registrant's most recently completed second fiscal
quarter. $1,589,409 on October 31, 2008.
Indicated the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date. 18,324,356 - shares of
common stock are issued and outstanding as of July 17, 2009.
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the Part
of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: (1) Any annual report to security holders; (2) Any proxy or
information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or
(c) under the Securities Act of 1933. The listed documents should be clearly
described for identification purposes (e.g., annual report to security holders
for fiscal year ended December 24, 1980). None.
ii
TABLE OF CONTENTS
Page
No.
----
Part I
Item 1. Business. .................................................... 5
Item 1A. Risk Factors. ................................................ 18
Item 1B. Unresolved Staff Comments. ................................... 23
Item 2. Properties. .................................................. 23
Item 3. Legal Proceedings. ........................................... 26
Item 4. Submission of Matters to a Vote of Security Holders. ......... 26
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities. ........... 27
Item 6. Selected Financial Data. ..................................... 28
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations. ................................... 28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk. .. 38
Item 8. Financial Statements and Supplementary Data. ................. 38
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure. .................................... 38
Item 9A.(T) Controls and Procedures. ..................................... 38
Item 9B. Other Information. ........................................... 40
Part III
Item 10. Directors, Executive Officers and Corporate Governance. ...... 40
Item 11. Executive Compensation. ...................................... 43
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters. ............................. 47
Item 13. Certain Relationships and Related Transactions, and Director
Independence. ................................................ 50
Item 14. Principal Accountant Fees and Services. ...................... 50
Part IV
Item 15. Exhibits, Financial Statement Schedules. ..................... 51
2
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This report contains forward-looking statements. These forward-looking
statements are subject to known and unknown risks, uncertainties and other
factors which may cause actual results, performance or achievements to be
materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. These forward-looking
statements were based on various factors and were derived utilizing numerous
assumptions and other factors that could cause our actual results to differ
materially from those in the forward-looking statements. These factors include,
but are not limited to, the availability of sufficient capital to fund the
anticipated growth of our company, fluctuations in the prices of oil and gas,
the competitive nature of our business environment, our dependence on a limited
number of customers, our ability to comply with environmental regulations,
changes in government regulations which could adversely impact our business and
other factors. Most of these factors are difficult to predict accurately and are
generally beyond our control. You should consider the areas of risk described in
connection with any forward-looking statements that may be made herein. Readers
are cautioned not to place undue reliance on these forward-looking statements
and readers should carefully review this report in its entirety. Except for our
ongoing obligations to disclose material information under the Federal
securities laws, we undertake no obligation to release publicly any revisions to
any forward-looking statements, to report events or to report the occurrence of
unanticipated events. These forward-looking statements speak only as of the date
of this report, and you should not rely on these statements without also
considering the risks and uncertainties associated with these statements and our
business.
OTHER PERTINENT INFORMATION
Unless specifically set forth to the contrary, when used in this report
the terms the "Company," "we," "us," "ours," and similar terms refers to Miller
Petroleum, Inc., a Tennessee corporation and our subsidiaries, Miller Rig &
Equipment, LLC, Miller Drilling TN, LLC, Miller Energy Services, LLC, Miller
Energy GP, LLC. Miller Energy Drilling 2009-A LP and Miller Energy Income 2009-A
LP.
Our fiscal year end is April 30. When used in this annual report,
"fiscal 2009" means the fiscal year ended April 30, 2009, " fiscal 2010" means
the fiscal year ending April 30, 2010, "fiscal 2011" means the fiscal year
ending April 30, 2011, "fiscal 2012" means the fiscal year ending April 30, 2012
and "fiscal 2013" means the fiscal year ending April 30, 2013.
The information which appears on our web site at
www.millerenergyresources.com is not part of this report.
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:
"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 report to refer to
gaseous hydrocarbons.
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"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.
"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 is
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.
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PART I
ITEM 1. BUSINESS.
We are an exploration and production company that utilizes seismic
data, and other technologies for geophysical exploration and development of oil
and gas wells. In addition to our engineering and geological capabilities, we
provide land drilling services on a contract basis to customers primarily
engaged in natural gas exploration and production.
During fiscal 2009, we completed two transactions which we believe had
both a positive impact on our balance sheet and removed certain historical
obstacles in our continued growth. These transactions included:
SALE OF LEASES AND WELLS TO ATLAS ENERGY RESOURCES, LLC
Effective as of June 13, 2008 we entered into an agreement with Atlas
Energy Resources, LLC ("Atlas Energy") pursuant to which we assigned to Atlas
Energy:
o an unencumbered, undivided 100% working interest and an 80% net
revenue interest in and to the oil and gas lease comprising 27,620
acres known as Koppers North and Koppers South and located in
Campbell County, Tennessee;
o an unencumbered, undivided 100% interest and an 82.5% net revenue
interest (net of a 5% overriding royalty interest to us) in and to
the oil and gas lease comprising 1,952 acres adjacent to Koppers
North and Koppers South and located in Campbell County, Tennessee;
and
o an unencumbered, undivided 100% working interest and an 80% net
revenue interest in eight gas wells on Koppers South.
The transaction is subject to unwinding pursuant to a pending
litigation between us and CNX Gas Company LLC which is described elsewhere
herein. The aggregate consideration for the assignment of the leases and wells
to Atlas Energy was $19,625,000, $9,025,000 of which was paid to us in 2008 and
the balance of $10,600,000 was paid directly to Wind City Oil & Gas, LLC in
consideration of a settlement of claims between Wind City and us described
below.
As part of the transaction, we agreed to provide Atlas America LLC
("Atlas America"), a sister company to Atlas Energy, with two rigs for two years
to drill up to 10 wells commencing a significant commitment to contract
drilling. To give Atlas America the level of service required, during the first
quarter of fiscal 2009, we purchased a 2007 Atlas RD20 III drilling rig and
related equipment for approximately $1.9 million. We drilled six wells for Atlas
America from November 2008 to January, 2009, for a total depth of 14,905 feet.
We expect to drill more wells for Atlas America in the next three to six months.
For two years after the closing date, Atlas Energy granted us the
opportunity to bid on any other drilling or service work that Atlas Energy bids
on in the State of Tennessee. In addition, we entered into:
o a natural gas transportation agreement with Atlas Energy which
provides us access to the Atlas Volunteer Pipeline, to the extent
that capacity is available, on substantially the same terms as those
offered to the producers delivering into the system; and
5
o a natural gas processing agreement pursuant to which Atlas Energy
will provide gas processing services to us on substantially the same
terms as those services are provided to other producers delivering
gas into the Atlas Volunteer Pipeline and deliver back to us gas
with a heating value of 1,100 BTUs (British Thermal Units) per cubic
foot.
SETTLEMENT OF WIND CITY LITIGATION
Effective as of June 13, 2008, we also settled all issues and
controversies with Wind City Oil & Gas, LLC, Wind Mill Oil & Gas, LLC and Wind
City Oil & Gas Management, LLC pending in the previously disclosed Tennessee
litigation, Tennessee arbitration and litigation in the Southern District of New
York. Pursuant to the settlement, we paid $10,600,000 for the repurchase of
2,900,000 shares of our common stock and reacquisition of all leases previously
assigned by us to Wind City, Wind Mill or Wind City Oil & Gas, all wells and
equipment associated with these leases, all pipeline rights and rights of way,
all contract rights and all other equipment, property and real property rights.
As set forth above, we used a portion of the proceeds from the Atlas Energy
transaction to pay the settlement amounts.
OUR CURRENT STRATEGY
With the closing of Atlas Energy transaction and the settlement of the
Wind City litigation our management is now able to focus the majority of its
efforts on growing our company. We are presently refining our business model in
an effort to take advantage of opportunities we believe are available to us,
both as a result of our agreement with Atlas Energy and the elimination of
various uncertainties surrounding our company as a result of the Wind City
litigation. It is anticipated that our focus in future periods will be within
five distinct areas, including:
o investment partnership management pursuant to which we will seek to
drill additional wells, concentrating on the East Tennessee portion
of the Southern Appalachian Basin with emphasis in horizontal
drilling in Devonian Shale;
o organically growing production through drilling for own benefit on
existing leases, leveraging our 100,000 plus well log database with
a view towards retaining the majority of working interest in the new
wells;
o expanding our contract drilling and service capabilities and
revenues, including through our drilling contract with Atlas;
o expanding our leasing capabilities by implementing strategies unique
to the gas and oil industry to secured leases and enter into new
partnerships to increase monetary capabilities, and
o increasing our overall production through economically viable
acquisitions of additional wells.
Our ability, however, to implement one or more of these goals is
dependent both upon the availability of additional capital and the augmenting of
our senior staff. To fully expand our operations as set forth above, we require
approximately up to $50 million in cash to fund the balance of our expansion
plans. To provide this capital, we intend to leverage our existing assets as
well as seek to raise capital through the sale of equity and/or debt securities.
Our ability, however, to fully implement our expanded business model is
dependent on our ability to raise the additional capital on a timely basis so as
to take advantage of the opportunities we presently have available to us.
6
We are currently offering three distinct capital raising programs. One
is a subordinated debenture seeking $5 million to $15 million for the
refinancing of existing rigs and the acquisition of new rigs. Another program is
an up to 30 well drilling program, which seeks limited partners for a $1,500,000
to $25,500,000 raise with 100% of the tax advantage from IDC costs being passed
on to investors. Limited investors will share in any net interest revenue as
well. The third program is a program designed to provide income to limited
partners. This oil and gas acquisition and development program is targeted for
projects primarily in the Appalachian Basin and will focus on projects that may
include the acquisition of oil and gas leases, royalty interests, overriding
royalty interests, working interests, mineral interests, real estate, producing
and non-producing wells, reserves, oil and gas related equipment including
transportation lines and potential investments in entities that invest in such
assets. The partnership anticipates it will drill new wells, including infield
development wells and will engage in the revitalization and enhancement of
acquired wells to increase production by using the latest techniques of well
restimulation. The partnership may also monetize purchased real estate or
interests and may incur debt to finance activities. There are no assurances we
will be able to raise any capital and, accordingly, we may be unable to pursue
any of these goals.
OUR BACKGROUND
Our core operations were started in 1978 by Mr. Deloy Miller, currently
our Chairman of the Board of Directors. Initially, we were involved with shallow
cable tool oil and gas drilling. We adapted an Ingersoll-Rand 3 Drillmaster for
deeper drilling which led to modernization of the drilling industry in our area
and we became the largest drilling contractor in Tennessee. By the 1980's, we
were active throughout the Appalachian Basin, with more than 18 drilling rigs
working from southern New York to northern Alabama. Between 1978 and 1983, we
drilled more than 4,000 wells.
During our years as a drilling contractor, we acquired several oil and
gas leases and 50 or more working interests in oil and gas wells. When drilling
activity declined drastically in the late 1980's, we sold or stacked most of our
drilling rigs and began developing prospects and drilling them with industry
partners.
During the early 1990's, when drilling activity remained well below
normal we decided to change our focus to exploration and production, continuing
to develop prospects, actively lease promising areas for oil and gas, seek out
opportunities to purchase oil and gas properties, and drill promising prospects
with industry partners. This strategy remained our substantially all of focus
until recently. As a result of rising oil and gas prices and new drilling
technologies, we recently established Miller Drilling to provide contract
drilling services.
OUR OPERATIONS
OUR EXPLORATION AND PRODUCTION ACTIVITIES
Our exploration and production activities include the operation of gas
and oil wells, and the acquisition and development of gas and oil leases.
We have partial ownership, sometimes referred to as a working interest,
in 20 producing oil wells and 32 producing gas wells. Our working interests in
these wells range from 25% to 100%. These wells are located in Anderson,
Cumberland, Roane and Scott counties in Tennessee. These wells mostly include
joint venture partners that we share the net revenue interest. The number of
joint venture holders per well ranges from none to thirteen and we enjoy a
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percentage range of net revenue interest from 19.25% to 98.1625%. As of April
30, 2009, we had approximately 14,489 acres of oil and gas leases. We retained a
5% royalty interest on a 1,930 acre tract that we expect to be the subject of
Atlas Energy drilling. Additionally, we retained the right to participate in up
to ten wells with a 25% working interest without offset for a promotion fee or
interest. Crude oil is stored in tanks at the well site until the purchaser
retrieves it by tank truck.
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 Barrett Oil Purchasing
Company. Our natural gas has multiple markets throughout the eastern United
States through gas transmission lines. Access to these markets is presently
provided by three companies in northeastern Tennessee, including Cumberland
Valley Resources, NAMI Resources Company, and Tengasco. Local markets in
Tennessee are served by Citizens Gas Utility District and the Powell Clinch
Utility District.
Natural gas is delivered to the purchaser via gathering lines into the
main gas transmission line. Surplus gas is placed in storage facilities or
transported to East Tennessee Natural Gas which serves Tennessee and Virginia.
Currently, we are selling oil and natural gas to the following
purchasers:
o Barrett Oil Purchasing purchases our crude oil at a purchase price
based on West Texas postings less $4.50. We do not have a written
agreement with Barrett Oil Purchasing.
o Sunoco Partners Marketing & Terminals, L.P. purchases our crude oil
at a purchase price which is negotiated on the date of delivery. We
have a monthly renewing agreement with Sunoco.
o Cumberland Valley Resources purchases our gas with a sales price
that is the Appalachian Index minus Columbia transportation and
fuel. Cumberland Valley Resources purchases approximately 80% of our
total natural gas sales. We do not have a written agreement with
Cumberland Valley Resources, and
o Powell Clinch Utility District purchases our gas with a sales price
that is based on the Inside FERC Tennessee Zone 0 index less $0.30
per mmbtu. We have a one-year agreement with Powell Clinch Utility
District that expires September 30, 2009.
OUR CONTRACT DRILLING OPERATIONS
We provide land drilling services on a contract basis in the domestic
market to customers that are primarily engaged in oil and natural gas
exploration and production. The market that we serve is primarily the
Appalachian Basin, which has unconventional natural gas bearing formations.
Natural gas production from unconventional formations, including tight sands,
shales and coalbed methane, is both the largest and fastest growing component of
U.S. natural gas production. In addition to vertical drilling, we anticipate the
need for horizontal drilling, which increases exposure of the wellbore to
gas-bearing formations and provides better drainage. The horizontal drilling
rigs contemplated for this are specially equipped for this type of work, as they
typically require air circulation systems for penetrating through hard rock and
enhanced fluid circulation systems for drilling horizontally into natural gas
bearing formations. We plan to either purchase a horizontal rig or to contract
one out in order to be able to provide this service.
8
Our services range from contract drilling by the foot or day rate to
offering turnkey services to our customers. Our services are typically limited
to the drilling portion of oil and gas extraction. Thus, when offering turnkey
solutions, we will contract out the non-drilling functions such as possibly
horizontal drilling and fracturing to non-affiliated third parties. We are
responsible for the costs of rig refurbishment.
During 2009, a wholly owned subsidiary of Miller Petroleum, Miller
Drilling TN, LLC ("Miller Drilling") expects to operate two rigs under contract
in connection with Miller Petroleum's agreement to satisfy the two year drilling
contract that it has with Atlas Energy. In accordance with the requirements of
the Atlas Energy drilling contract and after the issuance of Debentures upon
reaching the minimum offering hereunder, Miller Drilling will devote the two
drilling rigs it initially leases from its sister company, Miller Rig &
Equipment, LLC ("MRE") to drilling the wells required by that contract,
beginning a significant commitment to contract drilling. In addition, through
Miller Petroleum's relationship with Atlas Energy described above, Miller
Drilling will have the opportunity to bid on other drilling or service work that
Atlas Energy bids on in the State of Tennessee.
MILLER RIG & EQUIPMENT, LLC
MRE was formed on October 17, 2008 and is a wholly-owned subsidiary of
Miller Petroleum. When the minimum numbers of subscriptions have been received,
Miller Petroleum will make an initial contribution to MRE of the land
underlying, and the buildings which will constitute, our principal offices. MRE
is in the business of leasing oil and gas equipment. MRE currently has no
drilling rigs. The funds from this Offering will be used to purchase rigs and
other vehicles and equipment needed for drilling as described in the following
paragraph.
MRE's inventory of land drilling rigs initially is expected to consist
of two vertical land-based rigs. MRE will purchase those drilling rigs from its
parent company, Miller Petroleum. MRE has identified a horizontal drilling rig
for purchase from a third party which MRE expects, subject to available funds.
If the maximum gross proceeds of the debentures are realized, MRE expects to
purchase an additional horizontal drilling rig which it has identified, which
MRE expects to purchase in and place it into operation. The drilling rigs
contemplated to be purchased are land based. The types of land based rigs MRE is
currently considering acquiring consist generally of engines, a drawworks, a
mast (or derrick), pumps to circulate the drilling fluid (mud) under various
pressures, blowout preventers, drill string and related equipment. The engines
power the different pieces of equipment, including a rotary table or top drive
that turns the drill string, causing the drill bit to bore through the
subsurface rock layers. Rock cuttings are carried to the surface by the
circulating drilling fluid. The intended well depth, bore hole diameter and
drilling site conditions are the principal factors that determine the size and
type of rig most suitable for a particular drilling job. A land-based workover
or well-servicing rig consists of a mobile carrier, engine, drawworks and a
mast. The primary function of a workover or well-servicing rig is to act as a
hoist so that pipe, sucker rods and down-hole equipment can be run into and out
of a well. Because of size and cost considerations, well-servicing and workover
rigs are used for these operations rather than the larger drilling rigs.
Land-based drilling rigs are moved between well sites and between geographic
areas of operations by using our loaders and transport vehicles. Workover rigs
are either self-propelled or trailer mounted and include auxiliary equipment,
which is either transported on trailers or moved with trucks.
9
MRE will have a five-year master lease contract with its affiliate
Miller Drilling pursuant to which Miller Drilling is expected to fully utilize
all of the drilling rigs owned by MRE. The contract allows for unlimited
equipment additions, but will begin with the leasing by MRE of the two vertical
drilling rigs which MRE will purchase from Miller Petroleum. See "Description of
Other Documents." In addition, MRE may also purchase and lease equipment such as
water trucks, service rigs and other related vehicles and equipment.
Ultimately, if in the maximum funds are raised, MRE intends to use the
net proceeds from the offering to purchase up to a total of six workover rigs,
four of which it anticipates will be 500 horse-power rigs capable of servicing
wells with depths of up to 18,000 feet. The remaining two rigs MRE anticipates
will be less than 500 horse-power workover rigs capable of servicing wells with
depths of up to 12,000 feet. MRE also anticipates purchasing three swab units
and some flow back equipment. There are no assurances MRE will raise any
capital.
MILLER ENERGY DRILLING 2009-A, LP
Miller Energy Drilling 2009-A, LP is a newly formed privately-held
Delaware limited partnership ("MED"). MED was formed on March 31, 2009. MED is
undertaking a private offering of general partner units representing general
partner interests in MED and limited partner units representing limited partner
interests in MED. Provided that all units are sold, MED expects to use
substantially all of the net proceeds from this offering to drill oil and
natural gas development wells. There are no assurances MED will raise any
capital. .
MILLER ENERGY INCOME 2009-A, LP
Miller Energy Income 2009-A, LP is a newly formed privately-held
Delaware limited partnership ("MEI"). MEI is soliciting a private offering of
limited partner interests. The objective of the partnership is to provide the
capital required to invest in various types of oil and gas ventures including
the acquisition of oil and gas leases, royalty interests, overriding royalty
interests, working interests, mineral interests, real estate, producing and
non-producing wells, reserves, oil and gas related equipment including
transportation lines and potential investments in entities that invest in such
assets except for other investment partnerships sponsored by affiliates of MEI.
MEI anticipates it will drill new wells, including infield development wells and
will engage in the revitalization and enhancement of acquired wells to increase
production by using the latest techniques of well restimulation. MEI may also
monetize purchased real estate or interests and may incur debt to finance
activities. MEI will concentrate its efforts in the Appalachian basin. There are
no assurances MEI will raise any capital.
MILLER ENERGY GP, LLC
The Managing General Partner for MED and MEI is a newly-formed Delaware
corporation. The Managing General Partner is a wholly-owned subsidiary of Miller
Petroleum, Inc.
The Managing General Partner will also serve as the operator for MED
under the Drilling and Operating Agreement and will supervise the drilling,
completing and operating of the wells to be drilled by MED.
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COMPETITIVE BUSINESS CONDITIONS
Our oil and gas exploration activities in Tennessee are undertaken in a
highly competitive and speculative business environment. In seeking any other
suitable oil and gas properties for acquisition, we compete with a number of
other companies located in Tennessee and elsewhere, including large oil and gas
companies and other independent operators, many with greater financial resources
than us.
At the local level, we have several competitors in the areas of the
acreage which we have under lease in the State of Tennessee, five of which may
be deemed to be significant including Consol Energy, Inc., Can Argo Energy
Corporation, 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 OUR CUSTOMERS
We are dependent on local purchasers of hydrocarbons to purchase our
products in the areas where our properties are located. Barrett Oil Purchasing
purchases oil from the Koppers Fields. Barrett accounted for $191,503 and
$320,034 of the Company's total revenue, which was 12% and 38% of the Company's
total revenue, respectively for fiscal 2009 and 2008. Cumberland Valley
Resources purchases natural gas produced from the joint venture with Delta
Producers, Inc. in the Jellico East Field. Delta Producers Inc. accounted for
$332,597 and $355,641 of the Company's total revenue, which was 21% and 37% of
the Company's total revenue, respectively for fiscal 2009 and 2008.
In addition, we are dependent on local customers for drilling revenues.
Tri-Global Holdings, LLC, Montello Resources, LLC, Delta Producers Inc. and
Herman Gettelfinger accounted for $435,422 and $196,831, which was 47% and 75%
of the Company's service and drilling revenue, respectively for fiscal 2009 and
2008. Atlas America, LLC has contracted with us to perform drilling for them on
an as needed basis. During fiscal 2009, Atlas America, LLC accounted for
$436,935 and $0, which was 47% and 0% of the Company's service and drilling
revenue, respectively for fiscal 2009 and 2008. The loss of one or more of our
primary purchasers and drilling customers may have a substantial adverse impact
on our sales and on our ability to operate profitably.
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RECENT DEVELOPMENTS
On June 8, 2009 Miller Petroleum, Inc. acquired certain assets from
Ky-Tenn Oil, Inc., a Kentucky corporation ("KTO"), an unrelated third party,
including KTO's undivided interest in approximately 170 oil and gas wells in
Morgan, Scott and Fentress counties Tennessee, together with all property,
fixtures and improvements, leasehold interest and contract rights related to
these wells Assets purchased included oil well equipment such as pump jacks,
electric and gas motors and 100 bbl and 210 bbl oil tanks; gas well equipment
such as swedges, meter runs and meters and separators; and other equipment such
as compressors, motors, a workover rig, a wench truck, a diesel truck, a lowboy
and various other vehicles. In addition we received an undivided interest in
approximately 35,325 acres of oil and gas leases in Scott and Morgan counties,
Tennessee. We also received interest in an operating agreement with the Tenn.
State Energy Development Partnership, interest in a gas gathering pipeline
system and other rights related to these assets, including royalty and working
interests, licenses and permits and similar incidental rights. We issued one
million shares of our stock for KTO's assets, valued at $320,000. We granted the
seller piggy-back registration rights covering these shares. The shares were
issued in a private transaction exempt from registration under the Securities
Act of 1933 in reliance on an exemption provided by Section 4(2) of the act. On
June 12, 2009 we issued a press release announcing the closing of this
transaction.
On June 18, 2009 Miller Petroleum, Inc. acquired 100% of the stock of
East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of
the membership interests in East Tennessee Consultants II, LLC, a Tennessee
limited liability company ("LLC") from the owners of these entities. As
consideration for these companies we issued the sellers, who were unrelated
third parties, one million shares of our common stock valued at $250,000. We
granted the sellers registration rights covering these shares. The shares were
issued in a private transaction exempt from registration under the Securities
Act of 1933 in reliance on an exemption provided by Section 4(2) of the act.
ETC was formed in 1983 to provide oil and gas well operating services
and it represented various working interest owners and the LLC was formed in
1996. Following the closing, it is anticipated that these subsidiaries will
operate the wells they own as well as the recently purchased wells from KY-Tenn
Oil, Inc. It is also anticipated that the old wells will be reworked and that
new wells will be drilled from the extensive acreage now owned by us. The
Chattanooga Shale, which is present in a majority of the wells acquired, is a
candidate for stimulation. Completion and reworking of existing oil zones should
add to reserves at a relatively inexpensive price.
Under the terms of the stock purchase agreement, the sellers agreed not
to engage in oil and gas operations for a period of three years following the
closing date. We also agreed that each of the sellers, Messrs. Eugene D.
Lockyear, Douglas G. Melton and Jerry G. Southwood, would continue their
employment with the acquired companies for at least three years from the closing
date of the transaction at their same compensation and benefit levels to which
they were entitled in May 2009. In addition, as described later in this report,
Mr. Lockyear was appointed Vice President of Operations of our company. We also
agreed that if any or all of the sellers incur any income tax liability as a
result of the receipt of the above shares as consideration for the stock
purchase, we agreed to pay a bonus to such seller equal to the amount of his tax
liability within 30 days from the closing date.
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Following the closing of the acquisition, Mr. Eugene D. Lockyear, one
of the sellers, was appointed our Vice President of Operations. We have agreed
to retain him in this position for at least three years from closing. It is
anticipated that Mr. Lockyear will provide his geologic expertise which has been
developed from over 36 years of working in the oil and gas industry and he will
be responsible for supervision necessary to recomplete and rework the large
inventory of wells now owned by us. In addition, Mr. Lockyear will oversee water
plant projects, gas repressurization, gas storage, among others techniques to
extract oil from older wells. As compensation for his services, Mr. Lockyear
will receive an annualized base salary of $102,000 as well as customary
benefits. This compensation level is identical to the compensation he was
previously paid.
COMPETITIVE BUSINESS CONDITIONS
Our oil and gas exploration activities in Tennessee are undertaken in a
highly competitive and speculative business environment. In seeking any other
suitable oil and gas properties for acquisition, we compete with a number of
other companies located in Tennessee and elsewhere, including large oil and gas
companies and other independent operators, many with greater financial resources
than us.
At the local level, we have several competitors in the areas of the
acreage which we have under lease in the State of Tennessee, five of which may
be deemed to be significant including Consol Energy, Inc., Can Argo Energy
Corporation, 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.
GOVERNMENT 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 for 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 is 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
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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 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 Tennessee Gs and Oil 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.
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:
o restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities;
o limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas; and
o 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.
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As with the industry generally, compliance with existing regulations
increases our overall cost of business. The areas affected include:
o unit production expenses primarily related to the control and
limitation of air emissions and the disposal of produced water;
o 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
o 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:
o to remove or remediate previously disposed wastes, including wastes
disposed or released by prior owners or operators;
o to clean up contaminated property, including contaminated
groundwater; or to perform remedial operations to prevent future contamination.
o 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.
15
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.
16
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.
HISTORY OF OUR COMPANY
We were incorporated in the State of Delaware in November 1985
originally under the name Longhorn Development Company, Inc. for the purpose of
searching out and acquiring or participating in a business or business
opportunity. In August 1988 we changed our name to Single Chip Systems
International, Inc. In August 1998 we acquired all of the issued and outstanding
securities of Single Chip Systems, Inc., a California corporation, in exchange
for shares of our common stock. Our then current officers and directors resigned
and the officers and directors of Single Chip Systems, Inc. were appointed
officers and directors of our company. Prior thereto, on July 1, 1988, Single
Chip Systems, Inc. had entered into a technology utilization license agreement
with Ramtron International Corporation which granted Single Chip Systems, Inc.
the royalty-bearing, non-exclusive licenses to use the ferroelectric
technologies and the certain trademarks in production, manufacture and sales of
Single Chip Systems, Inc. products. We failed to receive any economic benefit
related to the license agreement and we recorded a $100,000 loss on the license
agreement in the period ended December 31, 1988.
Thereafter, we had no business or operations until the transaction in
January 1997 as hereinafter described. In May 1996 we changed our name to Triple
Chip Systems, Inc.
Mr. Deloy Miller formed Miller Petroleum, Inc. ("pre-merger Miller"), a
company which is the basis of our current operations, in January 1978. In
January 1997, we closed an Agreement and Plan of Reorganization with pre-merger
Miller whereby we issued 5,582,535 shares of our common stock in exchange for
all of the outstanding common stock of per-merger Miller. The acquisition was
accounted for as a recapitalization of our company because the shareholders of
pre-merger Miller controlled the company after the acquisition. Following the
transaction, in January 1997, pre-merger Miller was merged into our company and
we changed our name to Miller Petroleum, Inc. in conjunction with the
re-domestication of our company into the State of Tennessee.
In September 1998 we formed Miller Pipeline Corporation Inc. as a
wholly-owned subsidiary to manage the construction and operation of the
gathering system used to transport natural gas to market. This pipeline was sold
in December 2007 for our book value of $526,500 There was no gain or loss
recorded on the transaction.
EMPLOYEES
As of July 21, 2009 we had 19 full-time employees, including our
executive officers. None of our employees are covered by collective bargaining
agreements, and we believe our relationships with our employees to be good.
17
ITEM 1A. RISK FACTORS
An investment in our common stock involves a significant degree of
risk. You should not invest in our common stock unless you can afford to lose
your entire investment. You should consider carefully the following risk factors
and other information in this report before deciding to invest in our common
stock.
RISKS RELATING TO OVERALL BUSINESS OPERATIONS
WE HAVE A HISTORY OF LOSSES AND THERE ARE NO ASSURANCES WE WILL EVER REPORT
PROFITABLE OPERATIONS.
While we reported net income of approximately $8.4 million for fiscal
2009, these results include a one-time gain on sale of oil and gas properties of
approximately $11.7 million. Absent this one-time transaction, our net loss for
fiscal 2009 would have been approximately $3.3 million. In fiscal 2008 we
reported a net loss of approximately $2.4 million. Our operations are not
sufficient to fund our operating expenses. We reported operating losses of $3.2
million and $2.2 million for fiscal 2009 and fiscal 2008, respectively.
Management's 2010 forecast indicates positive trends from capital-raising,
increased production and related revenues, but it may not result in positive
operating income, net income, among others and positive cash flows. These
factors raise substantial doubt about our ability to continue as a going
concern. The ability of the Company to continue as a going concern is dependent
upon the successful completion of additional financing and/or generating
profitable operations in future periods.
THE PRICES FOR OIL AND GAS ARE SUBJECT TO VOLATILITY BASED UPON FACTORS OVER
WHICH WE HAVE NO CONTROL.
The success of our business largely depends on the level of activity in
oil and natural gas exploration, development and production, particularly in
Tennessee. Oil and natural gas prices, and market expectations of potential
changes in these prices, significantly affect the level of drilling activity. An
actual decline, or the perceived risk of a decline, in oil or natural gas prices
could cause oil and gas companies to reduce their overall level of spending, in
which case demand for our products and services may decrease and revenues may be
adversely affected. Prices for natural gas and crude oil fluctuate widely. For
example, in fiscal 2009, our average sales price per barrel of oil was $68.77 as
compared to $79.85 during fiscal 2008 and in fiscal 2009 our average sales price
per Mcf of natural gas was $8.00 as compared to $7.21 in fiscal 2008. We
anticipate continued fluctuations in the price of natural gas and oil These
fluctuations in oil and natural gas prices may result from relatively minor
changes in the supply of and demand for oil and natural gas, market uncertainty
and other factors that are beyond our control, including:
o worldwide and domestic supplies of oil and natural gas;
o weather conditions;
o the level of consumer demand;
o the price and availability of alternative fuels;
o the availability of drilling rigs and completion equipment;
o the proximity to, and capacity of transportation facilities;
18
o the price and level of foreign imports;
o the nature and extent of domestic and foreign governmental
regulation and taxation;
o the ability of the members of the Organization of Petroleum
Exporting Countries (OPEC) to agree to and maintain oil price and
production controls;
o worldwide economic and political conditions;
o the effect of worldwide energy conservation measures;
o political instability or armed conflict in oil-producing regions;
and
o the overall economic environment.
We have little or no control over any of the foregoing variables which
impact adversely our revenues in future periods.
APPROXIMATELY 47% OF OUR PROVED GAS RESERVES ARE CLASSIFIED AS PROVED
UNDEVELOPED.
Approximately 47% of our gas reserves are classified as proved
undeveloped reserves. The future development of these undeveloped reserves into
proved developed reserves is highly dependent upon our ability to fund an
estimated total capital development cost of approximately $1,174,300. If such
development costs are not incurred or are substantially reduced, our proved gas
undeveloped and total proved reserves could be substantially reduced. The
reduction in such reserves could have a materially negative impact on our
ability to produce profitable future operations. The successful conversion of
these proved undeveloped reserves into proved developed reserves is dependent
upon the following:
o The funding of the estimated proved undeveloped capital development
costs is highly dependent upon our ability to generate sufficient working
capital through operating cash flows, and our ability to borrow funds and/or
raise equity capital,
o Our ability to generate sufficient operating cash flows is highly
dependent upon successful and profitable future operations and cash flows which
could be negatively impacted by fluctuating prices and increased operating
costs. No assurance can be given that we will have successful and profitable
future operations and positive future cash flows, and
o Projections for proved undeveloped reserves are largely based on
their analogy to similar producing properties and to volumetric calculations.
Reserves projections based on analogy are subject to change due to subsequent
changes in the analogous properties. Volumetric calculations are often based
upon limited log and/or core analysis data and incomplete reservoir fluid and
formation rock data. Since these limited data must frequently be extrapolated
over an assumed drainage area, subsequent production performance trends or
material balance calculations may cause the need for significant revisions to
the estimates of reserves.
19
ESTIMATES OF OIL AND NATURAL GAS DEPEND ON MANY ASSUMPTIONS THAT MAY VARY
SUBSTANTIALLY FROM ACTUAL PRODUCTION.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
expenditures, including many factors beyond our control. The reserve information
relating to proved reserves set forth in this report represents only estimates
based on reports of proved reserves prepared as of April 30, 2009 by Lee Keeling
and Associates, Inc., independent petroleum consultants. Lee Keeling and
Associates, Inc. was not engaged to evaluate and prepare reports relating to the
probable reserves on our properties and interests as these are more uncertain
than evaluations of proved reserves. Petroleum engineering is not an exact
science. Information relating to our proved oil and natural gas reserves is
based upon engineering estimates. Estimating quantities of proved crude oil and
natural gas reserves is a complex process. It requires interpretations of
available technical data and various assumptions, including assumptions relating
to economic factors. Any significant inaccuracies in these interpretations or
assumptions or changes of conditions could cause the quantities of our reserves
to be overstated.
To prepare estimates of economically recoverable crude oil and natural
gas reserves and future net cash flows, engineers analyze many variable factors,
such as historical production from the area compared with production rates from
other producing areas. It is also necessary to analyze available geological,
geophysical, production and engineering data, and the extent, quality and
reliability of this data can vary. The process also involves economic
assumptions relating to commodity prices, production costs, severance and excise
taxes, capital expenditures and workover and remedial costs. For these reasons,
estimates of the economically recoverable quantities of oil and natural gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net cash flows
expected there from prepared by different engineers or by the same engineers at
different times may vary substantially. Actual production, revenues and
expenditures with respect to our reserves will likely vary from estimates, and
such variations may be material.
OUR OPERATIONS ENTAIL INHERENT CASUALTY RISKS WHICH MAY NOT BE COVERED BY
ADEQUATE INSURANCE.
Our operations are subject to inherent casualty risks such as fires,
blowouts, cratering and explosions. Other risks include pollution, the
uncontrollable flows of oil, natural gas, brine or well fluids. These risks may
result in injury or loss of life, suspension of operations, environmental damage
or property and equipment damage, all of which would cause us to experience
substantial financial loss. There were no catastrophic events in fiscal 2009 or
2008.
Our drilling operations involve risks from high pressures and from
mechanical difficulties such as stuck pipes, collapsed casings and separated
cables. In accordance with customary industry practice, we maintain insurance
against some, but not all, of these risks. There can be no assurance that any
insurance will be adequate to cover any losses or liabilities. We cannot predict
the continued availability of insurance, or its availability at premium levels
that justify its purchase. In addition, we may be liable for environmental
damages caused by previous owners of properties that we purchased, which
liabilities would not be covered by our insurance.
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OUR OPERATIONS ALSO ENTAIL SIGNIFICANT OPERATING RISKS.
Our drilling activities involve risks, such as drilling non-productive
wells or dry holes, which are beyond our control. The cost of drilling and
operating wells and of installing production facilities and pipelines is
uncertain. Cost overruns are common risks that often make a project
uneconomical. The decision to purchase and to exploit a property depends on the
evaluations made by reserve engineers, the results of which are often
inconclusive or subject to multiple interpretations. We may also decide to
reduce or cease its drilling operations due to title problems, weather
conditions, noncompliance with governmental requirements or shortages and delays
in the delivery or availability of equipment or fabrication yards.
WE ARE DEPENDENT ON LIMITED CUSTOMERS
We are dependent on local purchasers of hydrocarbons to purchase our
products in the areas where our properties are located. During the fiscal years
ended April 30, 2009 and 2008, one customer purchasing oil represented
approximately 12% and 38%, respectively of our total revenue and another
customer purchasing natural gas from the joint venture with Delta Products, Inc.
represented approximately 40% and 37% of our total revenue from fiscal years
2009 and 2008, respectively. 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.
OUR OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS THAT REQUIRE
COMPLIANCE THAT CAN BE BURDENSOME AND EXPENSIVE.
Our oil and natural gas operations are subject to extensive federal,
state and local governmental regulations that may be changed from time to time
in response to economic and political conditions. Matters subject to regulation
relate to the general population's health and safety and are associated with
compliance and permitting obligations including regulations related to discharge
from drilling operations, use, storage, handling, emission and disposal,
drilling bonds, reports concerning operations, the spacing of wells, unitization
and pooling of properties and taxation. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and natural gas wells below actual production capacity to
conserve supplies of oil and natural gas. In addition, the production, handling,
storage, transportation and disposal of oil and natural gas, by-products thereof
and other substances and materials produced or used in connection with oil and
natural gas operations are subject to regulation under federal, state and local
laws and regulations primarily relating to protection of human health and the
environment. These laws and regulations have continually imposed increasingly
strict requirements for water and air pollution control and solid waste
management, and compliance with these laws may cause delays in the additional
drilling and development of our properties. Significant expenditures may be
required to comply with governmental laws and regulations applicable to us. We
believe the trend of more expansive and stricter environmental legislation and
regulations will continue. While, historically, we have not experienced any
material adverse effect from regulatory delays, there can be no assurance that
such delays will not occur for us in the future. We incurred less than $2,500
for government compliance in fiscal 2009 and fiscal 2008, primarily for safety
items such as notices, hardhats and other small items.
21
PRICE DECLINES HAVE RESULTED IN AND MAY IN THE FUTURE RESULT IN WRITE-DOWNS OF
OUR ASSET CARRYING VALUES.
Commodity prices have a significant impact on the present value of our
proved reserves. Recent declines in oil and gas prices have resulted in material
downward revisions in the estimated present value of our proved reserves. Total
reserves declined from a present worth value at April 30, 2008 of $9,774,116 to
$2,224,361 at April 30, 2009. This was primarily due to a drop on commodity
prices as the price for a barrel of oil declined from $103.31 as of April 30,
2008 to $40.35 as of April 30, 2009. Accounting rules require us to write down,
as a non-cash charge to earnings, the carrying value of our oil and gas
properties for impairments. We are required to perform impairment tests on our
assets periodically and whenever events or changes in circumstances warrant a
review of our assets. To the extent such tests indicate a reduction of the
estimated useful life or estimated future cash flows of our assets, the carrying
value may not be recoverable and therefore requires a write-down. We may incur
impairment charges in the future, which could have a material adverse effect on
our results of operations in the period incurred. We had no impairment charges
for the years ended April 30, 2008 and 2009.
RISKS RELATED TO OWNERSHIP OF OUR SECURITIES
CERTAIN OF OUR OUTSTANDING WARRANTS CONTAIN CASHLESS EXERCISE PROVISIONS WHICH
MEANS WE WILL NOT RECEIVE ANY CASH PROCEEDS UPON THEIR EXERCISE.
At June 30, 2009 we have common stock warrants outstanding to purchase
an aggregate of 1,000,000 shares of our common stock with an exercise price of
$0.50 per share, 1,000,000 shares of our common stock with an exercise price of
$1.00 per share and 1,640,000 shares of our common stock with an exercise price
of $1.15 per share. All of these warrants are exercisable on a cashless basis
which means that the holders, rather than paying the exercise price in cash, may
surrender a number of warrants equal to the exercise price of the warrants being
exercised. It is possible that the warrant holders will utilize the cashless
exercise feature which will deprive us of additional capital which might
otherwise be obtained if the warrants did not contain a cashless feature.
WE HAVE NOT VOLUNTARILY IMPLEMENTED VARIOUS CORPORATE GOVERNANCE MEASURES, IN
THE ABSENCE OF WHICH, SHAREHOLDERS MAY HAVE MORE LIMITED PROTECTIONS AGAINST
INTERESTED DIRECTOR TRANSACTIONS, CONFLICTS OF INTEREST AND SIMILAR MATTERS.
Federal legislation, including the Sarbanes-Oxley Act of 2002, has
resulted in the adoption of various corporate governance measures designed to
promote the integrity of the corporate management and the securities markets.
Some of these measures have been adopted in response to legal requirements.
Others have been adopted by companies in response to the requirements of
national securities exchanges, such as the NYSE or the NASDAQ Stock Market, on
which their securities are listed. Among the corporate governance measures that
are required under the rules of national securities exchanges are those that
address board of directors' independence, audit committee oversight, and the
adoption of a code of ethics. Although we have adopted a Code of Conduct, two of
our directors are independent and our Board has established an Audit Committee,
we have not adopted many of these other corporate governance measures and, since
our securities are not listed on a national securities exchange, we are not
required to do so. It is possible that if we were to adopt some or all of these
corporate governance measures, including the requirement that a majority of our
Board be independent, shareholders would benefit from somewhat greater
assurances that internal corporate decisions were being made by disinterested
directors and that policies had been implemented to define responsible conduct.
Prospective investors should bear in mind our current lack of corporate
governance measures in formulating their investment decisions.
22
BECAUSE OUR STOCK CURRENTLY TRADES BELOW $5.00 PER SHARE, AND IS QUOTED ON IN
THE OVER THE COUNTER MARKET, OUR STOCK IS CONSIDERED A "PENNY STOCK" WHICH CAN
ADVERSELY AFFECT ITS LIQUIDITY.
Our common stock is currently quoted in the over the counter market on
the OTC Bulletin Board. As the trading price of our common stock is less than
$5.00 per share, our common stock is considered a "penny stock," and trading in
our common stock is subject to the requirements of Rule 15g-9 under the
Securities Exchange Act of 1934. Under this rule, broker/dealers who recommend
low-priced securities to persons other than established customers and accredited
investors must satisfy special sales practice requirements. The broker/dealer
must make an individualized written suitability determination for the purchaser
and receive the purchaser's written consent prior to the transaction.
SEC regulations also require additional disclosure in connection with
any trades involving a "penny stock," including the delivery, prior to any penny
stock transaction, of a disclosure schedule explaining the penny stock market
and its associated risks. These requirements severely limit the liquidity of
securities in the secondary market because few broker or dealers are likely to
undertake these compliance activities. In addition to the applicability of the
penny stock rules, other risks associated with trading in penny stocks could
also be price fluctuations and the lack of a liquid market.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable to a smaller reporting company.
ITEM 2. PROPERTIES.
Our executive offices presently comprise approximately 4,968 square
feet for the main office building and 6,600 square feet for the shop building on
14.05 acres of land in Huntsville, Tennessee that we own. The Company also
leases accounting office space on a month-to-month basis at a monthly rate of
$900 per month. The rental expense incurred for fiscal 2009 and 2008 was $8,027
and $0, respectively.
Oil and Gas Leases
We are an exploration and production company that utilizes seismic
data, and other technologies for geophysical exploration and development of oil
and gas wells. In addition to our engineering and geological capabilities, we
have work-over rigs, dozers, roustabout crews and equipment to set pumping
units, tanks and lay flow lines, winch trucks and trailers for traveling
support, backhoes, ditchers, fusion machines and welders for pipeline and
compression installation, as well as other equipment necessary to take a
drilling program from the development stage to completion. We also sell rigs,
oilfield trailers, compressors and other miscellaneous oil and gas production
equipment.
At April 30, 2009 we had approximately 14,489 acres of oil and gas
leases, all located in Anderson, Campbell, Roane and Scott Counties in
Tennessee. These four counties are geographically situated in East Tennessee,
with both Campbell and Roane counties sharing borders with Anderson county and
Scott county sharing borders with Campbell and Anderson counties. As described
elsewhere herein, on June 13, 2008 we sold approximately 30,000 acres of leases
which were located in Campbell County, Tennessee and generally known as Koppers
North and Koppers South to Atlas America LLC for $19.625 million.
23
Of the approximately 14,489 acres of oil and gas leases we held at
April 30, 2009, approximately 5,707 acres are located in Anderson County,
Tennessee, approximately 3,936 acres are located in Campbell County, Tennessee,
approximately 845 acres are located in Roane County Tennessee and approximately
4,001 acres are located in Scott County Tennessee. There is no production at the
Anderson County, Tennessee sites. The following table provides information on
the oil and gas production from the remaining acreage during the fiscal years
ended April 30, 2009 and 2008:
Total All Wells Our %
--------------- ------
Oil Production (Bbls)
Produced April 30, 2008 ... 9,264 4,984
Produced April 30, 2009 ... 8,021 4,580
Gas Production (Mcf)
Produced April 30, 2008 ... 206,388 39,507
Produced April 30, 2009 ... 140,944 50,073
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 at April 30, 2009 by Lee Keeling and Associates, Inc., independent
petroleum consultants, 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 (Bbl) Gas (Mcf)
--------- ----------
Proved Reserves
Balance, April 30, 2007 ................................. 61,404 701,810
Discoveries and extensions ........................... - -
Revisions of previous estimates ...................... 17,993 475,894
Return of proved undeveloped properties to company ... - 1,037,857
Sale of minerals in place ............................ - (324,195)
Production ........................................... (4,984) (39,508)
------- ---------
Balance, April 30, 2008 ................................. 74,413 1,851,858
Discoveries and extensions ........................... - -
Revisions of previous estimates ...................... (16,390) 58,892
Production ........................................... (4,580) (50,073)
------- ---------
Balance, April 30, 2009 ................................. 53,443 1,860,677
24
Finally, the following table provides information at each of April 30,
2008 and 2009 regarding our developed and undeveloped reserves:
Oil (Bbl) Gas (Mcf)
--------- ----------
Proved developed producing reserves at April 30, 2009 ... 42,657 562,600
Proved developed producing reserves at April 30, 2008 ... 63,068 510,825
Proved developed non-producing reserves at April 30, 2009 10,786 29,879
Proved developed non-producing reserves at April 30, 2008 11,345 81,002
Proved undeveloped reserves at April 30, 2009 ........... - 1,271,058
Proved undeveloped reserves at April 30, 2008 ........... - 1,260,031
As described elsewhere herein, the return of the proved undeveloped
properties resulted from the return of the leases from Wind City to our
settlement of all litigation.
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, 2009 and April 30, 2008 are calculated using weighted average prices
in effect as of those dates. Those prices were $3.19 and $9.36, respectively,
per Mcf of natural gas, and $40.35 and $103.31, respectively, per barrel of oil.
The resulting estimated future cash inflows are reduced by estimated future
costs to develop and produce the estimated proved reserves based on year-end
cost levels. Future income taxes are based on year-end statutory rates, adjusted
for any operating loss carry forwards and tax credits. The future net cash flows
are reduced to present value by applying a 10% discount rate.
Standardized measures of discounted future net cash flows at April 30,
2009 and 2008 are as follows:
2009 2008
------------ ------------
Future cash flows .............................. $ 7,981,612 $ 25,456,619
Future production costs and taxes .............. (1,812,885) (3,597,397)
Future development costs ....................... (1,185,201) (1,471,400)
Future income tax expense ...................... (1,544,893) (6,320,225)
------------ ------------
Future cash flows .............................. 3,438,633 $ 14,067,597
Discount at 10% for timing of cash flows ....... (1,903,824) (7,323,458)
------------ ------------
Discounted future net cash flows from proved
reserves ..................................... $ 1,534,809 $ 6,744,139
============ ============
25
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, 2009 and
2008.
2009 2008
------------ ------------
Balance, beginning of year ..................... $ 6,744,139 $ 1,999,640
Sales, net of production costs and taxes ....... (399,705) (504,265)
Changes in prices and production costs ......... (2,775,928) 2,134,824
Revisions of quantity estimates and return of
proved undeveloped properties ................ (1,338,495) 6,853,630
Sales of minerals in place ..................... - (714,788)
Development costs incurred ..................... - -
Net changes in income taxes .................... (695,202) (3,024,902)
------------ ------------
Balances, end of year .......................... $ 1,534,809 $ 6,744,139
============ ============
ITEM 3. LEGAL PROCEEDINGS
In June 2008 CNX Gas Company, LLC commenced litigation in the Chancery
Court of Campbell County, State of Tennessee style CNX Gas Company, LLC vs.
Miller Petroleum Inc., Civil Action No. 08-071, to enjoin us from assigning or
conveying certain leases described in the letter of intent signed dated May 30,
2008 between CNX Gas Company, LLC and our company, to compel us to specifically
perform the assignments as described in the letter of intent and for damages. A
Notice of Lien Lis Pendens was issued June 11, 2008. We moved for entry of
summary judgment dismissing the claims asserted against us by CNX Gas Company,
LLC and on January 30, 2009 the court found that the claims of CNX had no merit.
The court granted our motion and dismissed all claims asserted by CNX Gas
Company, LLC in that action. CNX Gas Company, LLC has appealed the ruling.
On May 20, 2009 Gunsight Holdings, LLC, a Florida limited liability
company, filed a complaint in the United States District Court for the Eastern
District of Tennessee, Northern Division, that surrounds certain rights related
to approximately 6,800 acres in Scott County, Tennessee. The Plaintiff is
alleging that Miller Petroleum has failed or refused to pay royalties due to the
Plaintiff's predecessors and have breached the implied duty of further
exploration by failing to drill required wells, failing to reasonably develop or
explore the property, failing to maintain an active interest in further
development of the property and otherwise failing to act as a prudent operator
of the property thereby causing damages to the Plaintiff exceeding $75,000. The
Plaintiff is seeking a declaratory judgment of its allegations, removal of
Miller Petroleum from the property, a full accounting of activities related to
the property and all monies received from those activities, damages and costs of
action. We have filed an answer denying the various claims and asserting
affirmative defenses including that there has been continuous production from
the subject lease. We intend to vigorously defend this action.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
26
PART II
ITEM 5. STOCKHOLDER MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is quoted in the over the counter market on the OTC
Bulletin Board under the symbol MILL. The reported high and low sales prices for
the common stock are shown below for the periods indicated. The quotations
reflect inter-dealer prices, without retail mark-up, markdown or commission, and
may not represent actual transactions.
High Low
----- -----
Fiscal 2008
Quarter ended July 31, 2007 ............ $0.25 $0.25
Quarter ended October 31, 2007 ......... $0.07 $0.07
Quarter ended January 31, 2008 ......... $0.08 $0.08
Quarter ended April 30, 2008 ........... $0.22 $0.10
Fiscal 2009
Quarter ended July 31, 2008 ............ $0.75 $0.10
Quarter ended October 31, 2008 ......... $0.52 $0.12
Quarter ended January 1, 2009 .......... $0.40 $0.15
Quarter ended April 30, 2009 ........... $0.40 $0.15
On July 17, 2009, the last sale price of our common stock as reported
on the OTC Bulletin Board was $0.30. As of July 17, 2009, there were
approximately 358 record owners of our common stock.
DIVIDEND POLICY
We have never paid cash dividends on our common stock and we do not
anticipate that we will declare or pay dividends in the foreseeable future.
Payment of dividends, if any, is within the sole discretion of our Board of
Directors and will depend, among other factors, upon our earnings, capital
requirements and our operating and financial condition. In addition under
Tennessee law, we may not pay a dividend if, after giving effect, we would be
unable to pay our debts as they become due in the usual course of business or if
our total assets would be less than the sum of our total liabilities plus the
amount that would be needed if we were to be dissolved at the time of the
payment of the dividend to satisfy the preferential rights upon dissolution of
shareholders whose preferential rights were superior to those receiving the
dividend.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
None.
RECENT SALES OF UNREGISTERED SECURITIES
On June 1, 2009 we sold 225,000 shares of our common stock to Empire
Securities, Corp DBPRP for $0.34 per share. Also on June 1, 2009 we sold 125,000
shares of our common stock to The Rodriguez Family for $0.34 per share. Both
sales involve issuance of our shares to sophisticated investors who had access
to select information concerning the company, accordingly, both issuances were
exempt under Section 4(2) of the Securities Act of 1933.
27
ITEM 6. SELECTED FINANCIAL DATA.
Not applicable to a smaller reporting company.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
EXECUTIVE SUMMARY
We are an exploration and production company that utilizes seismic
data, and other technologies for geophysical exploration and development of oil
and gas wells. We have partial ownership in 20 producing oil wells and 32
producing gas wells. In addition to our engineering and geological capabilities,
we have work-over rigs, dozers, roustabout crews and equipment to set pumping
units, tanks and lay flow lines, winch trucks and trailers for traveling
support, backhoes, ditchers, fusion machines and welders for pipeline and
compression installation, as well as other equipment necessary to take a
drilling program from the development stage to completion. We also sell rigs,
oilfield trailers, compressors and other miscellaneous oil and gas production
equipment.
During fiscal 2009 we completed two transactions which we believe had
both a positive impact on our balance sheet and removed certain historical
obstacles in our continued growth. These transactions included:
SALES OF LEASES AND WELLS TO ATLAS ENERGY RECOURSES, LLC
Effective as of June 13, 2008 we entered into an agreement with Atlas
Energy Resources, LLC pursuant to which we assigned to Atlas Energy:
o An unencumbered, undivided 100% working interest and an 80% net
revenue interest in and to the oil and gas lease comprising 27,620
acres known as Koppers North and Koppers South and located in
Campbell County, Tennessee; and an unencumbered, undivided 100%
interest and an 82.5% net revenue interest (net of a 5% overriding
royalty interest to us) in and to the oil and gas lease comprising
1,952 acres adjacent to Koppers North and Koppers South and located
in Campbell County, Tennessee; and
o An unencumbered, undivided 100% working interest and an 80% net
revenue interest in eight gas wells on Koppers South. We have the
option to repurchase the wells within one year form the closing date
or within 30 days after the pipeline to be built by Atlas Energy has
been completed and is ready to accept gas for transport.
The transaction is subject to unwinding pursuant to a pending
litigation between our company and CNX Gas Company LLC as previously disclosed.
Transferring any of the leases or any interest thereon was also subject to a
60-day standstill period which has since expired.
The aggregate consideration for the assignment of the leases and wells
to Atlas Energy was $19,625,000, $9,025,000 of which was paid us and the
remaining $10,600,000 of which was paid directly to Wind City Oil & Gas, LLC in
consideration of a settlement of claims between Wind City and our company
described below.
28
As part of the transaction, we also agreed to contract with Atlas
Energy for two rigs for two years to drill wells, commencing a significant
commitment to contract drilling. To give Atlas Energy the level of service
required, during the first quarter of fiscal 2009 we acquired a 2007 COPCO Model
RD III drilling rig and related equipment drilling rig from Atlas to assist in
drilling the wells. This rig has been mobilized to the site and has commenced
drilling operations. We borrowed $1,850,125, secured by a certificate of
deposit, to purchase this drilling rig.
For two years after the closing date, Atlas Energy granted us the
opportunity to bid on any other drilling or service work that Atlas Energy bids
on in the State of Tennessee. In addition, we entered into:
o a natural gas transportation agreement with Atlas Energy which
provides us access to the Atlas Volunteer Pipeline, to the extent
that capacity is available, on substantially the same terms as those
offered to the producers delivering into the system; and
o a natural gas processing agreement pursuant to which Atlas Energy
will provide gas processing services to us on substantially the same
terms as those services are provided to other producers delivering
gas into the Atlas Volunteer Pipeline and deliver back to us gas
with a heating value of 1,100 BTUs per cubic foot.
SETTLEMENT OF WIND CITY LITIGATION
Effective as of June 13, 2008, we also settled all issues and
controversies with Wind City Oil & Gas, LLC ("Wind City"), Wind Mill Oil & Gas,
LLC ("Wind Mill") and Wind City Oil & Gas Management, LLC ("WCOG") pending in
the previously disclosed Tennessee litigation, Tennessee arbitration, and
litigation in the Southern District of New York. Pursuant to the settlement, we
paid Wind City and/or WCOG $10,600,000 for the re-purchase of the 2,900,000
shares of our common stock and reacquisition of all leases previously assigned
by us to Wind City, Wind Mill or WCOG, all wells and equipment associated with
these leases, all pipeline rights and rights of way, all contract rights, and
all other equipment, property and real property rights. As set forth above, we
used a portion of the proceeds from the Atlas Energy transaction to pay the
settlement amounts.
OUR CURRENT FOCUS
During fiscal 2009 we acquired leases for an additional 4,682 acres for
aggregate consideration of approximately $580,512 bringing the total leases
acquired as of April 30, 2009 to 14,489 acres for an approximate total cost of
$976,000. The terms of these leases which have a net revenue interest of 87.5%
run from one to five years. We are presently reviewing these leases, as well as
our other existing leases, to determine the capital requirements and timing for
drilling additional wells. To expand our operations by drilling on these leases
will require additional capital. At present we have approximately 14,489 acres
of oil and gas leases. During fiscal 2009 we leased an additional 4,682 acres,
and allowed 3,328 acres of marginal leases to expire in Roane and Campbell
Counties in Tennessee. The expired leases were primarily from Campbell County.
We drilled three wells in the Harriman Prospect in Campbell County and from the
geological data provided by these wells, we determined that the northeastern
29
third of our previous leasing activity was no longer a viable area to be in and
we allowed these leases to expire on their 5-year anniversary. As a part of the
previously mentioned sale to Atlas Energy, we retained a 5% royalty interest on
a 1,930 acre tract that we expect to be the subject of Atlas Energy drilling.
When wells are developed on this acreage, we stand to share in any profit they
create. Additionally, we retained the right to participate in up to ten wells
with a 25% working interest without promote.
With the closing of Atlas Energy transaction and the settlement of the
Wind City litigation our management is now able to focus the majority of its
efforts on growing our company. During fiscal 2009 we have augmented our senior
management through the hiring of Mr. Scott M. Boruff to serve as our CEO and Mr.
Paul W. Boyd to serve as our Chief Financial Officer. We are also continuing to
focus our short-term efforts on five distinct areas, including:
o Investment partnership management pursuant to which we will seek to
drill additional wells, concentrating on the East Tennessee portion
of the Southern Appalachian Basin with emphasis in horizontal
drilling in Devonian Shale,
o Organically growing production through drilling for own benefit on
existing leases, leveraging our 100,000 plus well log database with
a view towards retaining the majority of working interest in the new
wells,
o Expanding our contract drilling and service capabilities and
revenues, including through our drilling contract with,
o Expand our leasing capabilities by implementing strategies unique to
the gas and oil industry to secured leases and enter into new
partnerships to increase monetary capabilities, and
o Increase our overall production through economically viable
acquisitions of additional wells.
Our ability, however, to implement one or more of these goals is
dependent both upon the availability of additional capital. To fully expand our
operations as set forth above, we will need up to $50 million to fund the
balance of our expansion plans. To provide the expansion capital, we intend to
leverage our existing assets as well as seek to raise additional capital through
the sale of equity and/or debt securities. To facilitate these capital raising
efforts, we have retained a broker-dealer and member of FINRA to assist us and
are attempting to raise capital in a private offering. While our management has
devoted significant time to these efforts during 2009, we have not been
successful in raising any of these funds. Our ability to fully implement our
expanded business model, however, is dependent on our ability to raise the
additional capital on a timely basis so as to take advantage of the
opportunities we presently have available to us. We face a number of obstacles,
however, in raising the additional capital, including the relative size of our
company, the low trading price of our stock and the lack of liquidity in the
capital markets in general and small-cap companies in particular. If we are not
able to raise the capital as required, we will be unable to fully implement our
expanded business model and will need to delay future expansion as well as
further purchases of leases.
30
RESULTS OF OPERATIONS
REVENUE
-------
The following table shows the components of our revenues for the years
ended April 30, 2009 and 2008, together with their percentages of total revenue
in 2009 and percentage change on a year-over-year basis.
YEAR ENDED APRIL 30,
---------------------------------------------------
% OF %
REVENUE 2009 REVENUE 2008 CHANGE
---------- ---------- ---------- -----------
Oil and gas .............. $ 640,094 41% $ 566,478 13%
Service and drilling ..... 927,210 59% 262,864 253%
---------- ----------
Total revenue ............ $1,567,304 100% $ 829,342 89%
Oil and gas revenue represents revenues generated from the sale of oil
and natural gas produced from the wells in which we have a partial ownership
interest. Oil and gas revenue is recognized as income as production is extracted
and sold. We reported a 13% increase in oil and gas revenues for the year ended
April 30, 2009 over the year ended April 30, 2008. The increase in oil and gas
revenue was due to the Company having more wells producing oil and gas,
notwithstanding the end of year decrease in both oil and gas prices. At April
30, 2009 oil was priced at $40.35 per barrel versus $77.25 at April 30, 2008 and
at April 30, 2009 natural gas was $3.19 per Mcf as compared to $7.29 per Mcf at
April 30, 2008.
For the year ended April 30, 2009 we sold 8,311 barrels of oil and
116,600 Mcf of natural gas as compared to 9,025 barrels of oil and 137,232 Mcf
of natural gas during the year ended April 30, 2008. For the year ended April
30, 2009 our average sales price per barrel of oil was $68.77 as compared to
$77.25 during the year ended April 30, 2008. For the year ended April 30, 2009
as compared to the year ended April 30, 2008 our average sales price per Mcf of
natural gas was $8.00 as compared to $7.29.
For the year ended April 30, 2009 we produced 4,580 barrels of oil and
50,073 Mcf of natural gas as compared to 4,984 barrels of oil and 39,507 Mcf of
natural gas during the year ended April 30, 2008.
Service and drilling revenue represents revenues generated from
drilling, maintenance and repair of third party wells. Service and drilling
income is recognized at the time it is both earned and we have a contractual
right to receive the revenue. Our service and drilling revenue increased 253%
for the year ended April 30, 2009 as compared to the year ended April 30, 2008.
During the year ended April 30, 2009 we drilled six wells for Atlas Energy,
representing $437,000 of revenue, as part of our two-year drilling contract with
them. According to Atlas Energy's road construction schedule, we expect to
resume drilling in the next three to six months.
31
DIRECT AND OTHER EXPENSES
-------------------------
The following tables show the components of our direct and other
expenses for the years ended April 30, 2009 and 2008. Percentages listed in the
table reflect margins for each component of direct expenses and percentages of
total revenue for each component of other expenses.
YEAR ENDED APRIL 30,
--------------------------------------------
DIRECT EXPENSES 2009 MARGIN 2008 MARGIN
---------- ------ ---------- ------
Oil and gas ..................... $ 240,389 62% $ 62,213 89%
Service and drilling ............ 1,184,901 (28)% 297,942 (13)%
Impairment loss ................. - n/a 666,073 n/a
Depletion expense................ 221,465 n/a 157,153 n/a
---------- ----------
Total direct expenses............ $1,646,755 (5)% $1,183,381 (43)%
YEAR ENDED APRIL 30,
--------------------------------------------------
% %
OTHER EXPENSES (REVENUES) 2009 REVENUE 2008 REVENUE
------------ ------- ------------ -------
Selling, general and administrative .... $ 2,712,943 173% $ 1,747,659 211%
Depreciation and amortization .......... 427,605 27% 70,821 9%
Interest expense, net of interest income 24,785 2% 365,397 44%
Loan fees and costs .................... 124,085 8% - n/a
Gain on sale of equipment .............. (10,450) (1)% (102,119) (12)%
Gain on sale of oil and gas properties . (11,715,570) n/a - n/a
------------ ------------
Total other expenses (revenues) ........ $ (8,436,602) $ 2,081,758
We follow the successful efforts method of accounting for our oil and
gas activities. Accordingly, costs associated with the acquisition, drilling and
equipping of successful exploratory wells are capitalized. During the year ended
April 30, 2009 we capitalized approximately $975,992 of costs associated with
the acquisition, drilling and equipping of these wells as compared to none
during fiscal year 2008. However, geological and geophysical costs, delay and
surface rentals and drilling costs of unsuccessful exploratory wells are charged
to expense as incurred and are included in the cost of service and drilling
revenue. Finally, costs of drilling development wells are capitalized; however,
we did not drill any development wells during fiscal 2008. 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.
The cost of oil and gas revenue also represents costs associated with
contract fees we pay third parties to monitor the oil wells and record
production. Gas production is metered and read monthly by third party companies
which are specialists. We increased the number of oil and gas wells that we have
partial ownership in this fiscal year. Total producing oil wells grew from 15 as
of April 30, 2008 to 20 as of April 30, 2009 and gas wells grew from 25 on April
30, 2008 to 32 as of April 30, 2009. As a percentage of oil and gas revenue,
costs of oil and gas had a margin of 62% for the year ended April 30, 2009 as
compared to 89% for the year ended April 30, 2008. Completion costs associated
32
with the new wells is primarily responsible for this margin decrease. We
anticipate that the costs of oil and gas revenues will proportionality increase
as additional wells are connected.
The cost of service and drilling revenue represents direct labor costs
of employees associated with these services, as well as costs associated with
equipment, parts and repairs. The cost of service and drilling revenue has risen
significantly for the year ended April 30, 2009 as compared to the year ended
April 30, 2008. As previously discussed, we drilled six wells for Atlas Energy
during the year ended April 30, 2009 and expense increased accordingly. In
addition, in preparation for the Atlas Energy drilling contract, we spent
significant time and expense maintaining and repairing our drilling equipment.
These costs increased approximately $264,000 from fiscal 2008 to fiscal 2009.
Depletion of capitalized costs of proved oil and gas properties is provided on a
pooled basis using the units-of-production method based upon proved reserves.
Acquisition costs of proved properties are amortized by using total estimated
units of proved reserves as the denominator. All other costs are amortized using
total estimated units of proved developed reserves. During the year ended April
30, 2009 depletion expense was $221,465 or 14% of total revenue as compared to
19% for the year ended April 30, 2008. As a result of these components, total
direct expenses reflected a margin of (5)% for fiscal 2009, an improvement from
the (43)% margin experienced in fiscal 2008.
OTHER EXPENSES (REVENUES)
------------------------
Selling, general and administrative expense includes salaries, general
overhead expenses, insurance costs, professional fees and consulting fees. The
increase for the year ended April 30, 2009 as compared to the year ended April
30, 2008 primarily reflects legal and professional fees associated with the
sales of the leases to Atlas Energy and the settlement of the Wind City
litigation, together with increased compensation expense, resulting from the
addition of executive management as previously discussed. As a percentage of
total revenue, selling, general and administrative expense decreased to
approximately 173% for the year ended April 30, 2009 as compared to
approximately 211% for fiscal 2008.
Depreciation and amortization expenses reflect the usage of our fixed
assets over time. The increase in depreciation and amortization for the year
ended April 30, 2009 as compared to the year ended April 30, 2008 reflects an
increase in the amount of depreciation due to the purchase of equipment.
The decrease in interest expense, net of interest income for the year
ended April 30, 2009 as compared to fiscal 2008 reflects the satisfaction of
certain loans during the year ended April 30, 2008 as well as an increase on
interest income from larger investible funds associated with the Atlas Energy
transaction in June, 2008 as previously discussed.
Loan fees and costs of $124,085 in the year ended April 30, 2009
represents non-cash expenses related to the fair value of warrants owed in
connection with a prior financing transaction.
During the year ended April 30, 2009 we recorded a gain of $11,715,570
on the sale of the oil and gas leases to Atlas Energy and the concurrent
settlement of the Wind City litigation as described elsewhere herein. As part of
the settlement we repurchased 2,900,000 shares of our common stock for
$4,350,000 which is reflected on our balance sheet as shares subject to
redemption. As a result of these one-time transactions, while we reported a net
loss of $2,435,797 for the year ended April 30, 2008 we reported net income of
$8,356,373 for the year ended April 30, 2009. We do not anticipate that we will
enter into similar transactions in future periods.
33
LIQUIDITY
Liquidity is the ability of a company to generate funds to support its
current and future operations, satisfy its obligations and otherwise operate on
an ongoing basis. At April 30, 2009 we had a working capital deficit of $370,955
as compared to a working capital deficit of $5,431,365 at April 30, 2008. This
decrease in deficit primarily reflects the net cash to us from the sale of the
leases and wells to Atlas Energy and the concurrent settlement of Wind City
litigation and the satisfaction of the liability for stock repurchase.
Net cash used by operating activities in fiscal 2009 of $1,054,646 primarily
reflects the increased cash paid for costs and expenses, primarily from the
previously discussed increase in "Selling, General & Administrative" of
$965,284, the increased costs of oil and gas revenues of $178,176,excluding
depletion, and the increased costs of service and drilling revenues of $886,959,
which were only partially offset by the increase in revenue of $737,962. In
fiscal 2008 we also used cash to pay professional and other fees associated with
the then ongoing Wind City litigation.
Net cash provided by investing activities of $6,760,273 in fiscal 2009 reflects
the net cash we received from the Atlas Energy transaction of $12,519,713,
partially offset by the purchase of additional drilling equipment and vehicles
of $4,408,998 and funds used for the purchase of a lease and capitalized costs
associated with the purchase of oil and gas properties of $1,268,942 and land of
$110,000. During the year ended April 30, 2008, we had cash provided by
investing activities of $719,851. This was primarily derived by proceeds from
the sale of equipment, well equipment and supplies of $135,451 and proceeds from
the sale of our pipeline of $576,500.
Net cash used in financing activities of $5,701,497 for fiscal 2009 primarily
reflects the repurchase of 2,900,000 shares of our common stock from Wind Mill
for $4,350,000 due to the settlement of Wind Mill litigation as previously
discussed. In addition, we used cash to pay off certain notes payable of
$726,630 and paid for financing costs of $666,475 during fiscal 2009. During
fiscal 2008 cash provided by financing activities represented the proceeds from
short-term borrowings partially offset by payments on notes payable.
As of April 30, 2009, we had a working capital deficit of $370,811. Our business
involves significant capital requirements. The rate of production from oil and
gas properties declines as reserves are depleted. Without successful development
activities, our proved reserves would decline as oil and gas is produced from
our proved developed reserves. Our long-term performance and profitability is
dependent not only on recovering existing oil and gas reserves, but also on our
ability to find or acquire additional reserves and fund related infrastructure
build-outs on terms that are economically and operationally advantageous.
In order to implement our business strategy to expand our operations we will
need to raise additional capital. During fiscal 2009 we also commenced a capital
raising effort to raise funds to purchase drilling and work over rigs and other
equipment. The additional equipment is expected to be used to fulfill the Atlas
Energy agreement as well as for proprietary drilling. These private offering,
however, are being conducted on a best efforts basis and there are no assurances
we will raise any capital thereunder or that any funds we do receive will be
sufficient to enable us to purchase the additional equipment. In that event, we
would be required to seek alternative sources of financing for the purchase of
the additional rigs and equipment and there are no assurances that this capital
would be available to us.
34
In addition, 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. An 11% drop
in oil prices has reduced our liquidity somewhat this year. For the year ended
April 30, 2009 our average sales price per barrel of oil was $68.77 as compared
to $77.25 during the year ended April 30, 2008. Also, a reduction in reserves
would reduce our operating results in future periods. Reserves dropped from a
present value of $9,774,116 on April 30, 2008 to a present value of $2,224,361
on April 30, 2009. However, to counteract this we transacted two acquisitions
subsequent to year-end which should offset this decrease. 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.
OFF-BALANCE SHEET ARRANGEMENTS
As of the date of this report, we do not have any off-balance sheet
arrangements that have or are reasonably likely to have a current or future
effect on our financial condition, changes in financial condition, revenues or
expenses, results of operations, liquidity, capital expenditures or capital
resources that are material to investors. The term "off-balance sheet
arrangement" generally means any transaction, agreement or other contractual
arrangement to which an entity unconsolidated with us is a party, under which we
have: (i) any obligation arising under a guarantee contract, derivative
instrument or variable interest; or (ii) a retained or contingent interest in
assets transferred to such entity or similar arrangement that serves as credit,
liquidity or market risk support for such assets.
CRITICAL ACCOUNTING POLICIES
OIL AND GAS ACTIVITIES
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
Depreciation, depletion and amortization of capitalized costs of proved
oil and gas properties is provided on a pooled basis using the
units-of-production method based upon proved reserves. Acquisition costs of
proved properties are amortized by using total estimated units of proved
reserves as the denominator. All other costs are amortized using total estimated
units of proved developed reserves.
35
SHARE BASED PAYMENTS
The Company adopted SFAS No. 123R, "Share Based Payments." SFAS No.
123R requires companies to expense the value of employee stock options and
similar awards and applies to all outstanding and vested stock-based awards.
In computing the impact, the fair value of each option is estimated on
the date of grant based on the Black-Scholes options-pricing model utilizing
certain assumptions for a risk free interest rate; volatility; and expected
remaining lives of the awards. The assumptions used in calculating the fair
value of share-based payment awards represent management's best estimates, but
these estimates involve inherent uncertainties and the application of management
judgment. As a result, if factors change and the Company uses different
assumptions, the Company's stock-based compensation expense could be materially
different in the future. In addition, the Company is required to estimate the
expected forfeiture rate and only recognize expense for those shares expected to
vest. In estimating the Company's forfeiture rate, the Company analyzed its
historical forfeiture rate, the remaining lives of unvested options, and the
amount of vested options as a percentage of total options outstanding. If the
Company's actual forfeiture rate is materially different from its estimate, or
if the Company reevaluates the forfeiture rate in the future, the stock-based
compensation expense could be significantly different from what we have recorded
in the current period. The impact of applying SFAS No. 123R approximated
$247,425 and $0 in additional compensation expense during the years ended April
30, 2009, and 2008, respectively. Such amount is included general and
administrative expenses on the statement of operations.
IMPAIRMENT OF LONG-LIVED ASSETS AND LONG-LIVED ASSETS TO BE DISPOSED OF
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," requires that an asset be evaluated for impairment when the carrying
amount of an asset exceeds the sum of the undiscounted estimated future cash
flows of the asset. In accordance with the provisions of SFAS 144, the Company
reviews the carrying values of its long-lived assets whenever events or changes
in circumstances indicate that such carrying values may not be recoverable. If,
upon review, the sum of the undiscounted pretax cash flows is less than the
carrying value of the asset group, the carrying value is written down to
estimated fair value. Individual assets we grouped for impairment purposes at
the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets, generally on a
field-by-field basis. The fair value of impaired assets is determined based on
quoted market prices in active markets, if available, or upon the present values
of expected future cash flows using discount rates commensurate with the risks
involved in the asset group. The long-lived assets of the Company, which are
subject to evaluation, consist primarily of oil and gas properties.
For the year ended April 30, 2008, the Company expensed assets of
approximately $179,000 for impaired oil and gas wells and approximately $77,000
for old unused equipment. Collectively, these write-offs are included in the
Company's statement of income for the year ended April 30, 2008 under the
caption "Impairment Loss". We incurred no impairment loss for the year ended
April 30, 2009.
36
RECENT ACCOUNTING PRONOUNCEMENTS
In December 2007, the Financial Accounting Standards Board (FASB)
issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial
Statements - an amendment of ARB No. 51". This statement improves the relevance,
comparability, and transparency of the financial information that a reporting
entity provides in its consolidated financial statements by establishing
accounting and reporting standards that require; the ownership interests in
subsidiaries held by parties other than the parent and the amount of
consolidated net income attributable to the parent and to the noncontrolling
interest be clearly identified and presented on the face of the consolidated
statement of income, changes in a parent's ownership interest while the parent
retains its controlling financial interest in its subsidiary be accounted for
consistently, when a subsidiary is deconsolidated, any retained noncontrolling
equity investment in the former subsidiary be initially measured at fair value,
entities provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling
owners.
SFAS No. 160 affects those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary. SFAS No. 160 is effective for fiscal years, and interim periods
within those fiscal years, beginning on or after December 15, 2008. Early
adoption is prohibited. The adoption of this statement is not expected to have a
material effect on the Company's financial statements.
In March 2008, the FASB issued SFAS No. 161, "Disclosures about
Derivative Instruments and Hedging Activities, an amendment of FASB Statement
No. 133" (SFAS 161). This statement is intended to improve transparency in
financial reporting by requiring enhanced disclosures of an entity's derivative
instruments and hedging activities and their effects on the entity's financial
position, financial performance, and cash flows. SFAS 161 applies to all
derivative instruments within the scope of SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133) as well as related hedged items,
bifurcated derivatives, and nonderivative instruments that are designated and
qualify as hedging instruments. Entities with instruments subject to SFAS 161
must provide more robust qualitative disclosures and expanded quantitative
disclosures. SFAS 161 is effective prospectively for financial statements issued
for fiscal years and interim periods beginning after November 15, 2008, with
early application permitted.
In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally
Accepted Accounting Principles." SFAS No. 162 identifies the sources of
accounting principles and provides entities with a framework for selecting the
principles used in preparation of financial statements that are presented in
conformity with GAAP. The current GAAP hierarchy has been criticized because it
is directed to the auditor rather than the entity, it is complex, and it ranks
FASB Statements of Financial Accounting Concepts, which are subject to the same
level of due process as FASB Statements of Financial Accounting Standards, below
industry practices that are widely recognized as generally accepted but that are
not subject to due process. The Board believes the GAAP hierarchy should be
directed to entities because it is the entity (not its auditors) that is
responsible for selecting accounting principles for financial statements that
are presented in conformity with GAAP. SFAS 162 is effective 60 days following
the SEC's approval of PCAOB Auditing Standard No. 6, Evaluating Consistency of
Financial Statements (AS/6). The adoption of FASB 162 is not expected to have a
material impact on the Company's financial position.
37
In May 2008, the FASB issued SFAS No. 163, "Accounting for Financial
Guarantee Insurance Contracts-an interpretation of FASB Statement No. 60."
Diversity exists in practice in accounting for financial guarantee insurance
contracts by insurance enterprises under FASB Statement No. 60, Accounting and
Reporting by Insurance Enterprises. This results in inconsistencies in the
recognition and measurement of claim liabilities. This Statement requires that
an insurance enterprise recognize a claim liability prior to an event of default
(insured event) when there is evidence that credit deterioration has occurred in
an insured financial obligation. This Statement requires expanded disclosures
about financial guarantee insurance contracts. The accounting and disclosure
requirements of the Statement will improve the quality of information provided
to users of financial statements. SFAS 163 is effective for financial statements
issued for fiscal years beginning after December 15, 2008, and interim periods
within those fiscal years. The adoption of FASB 163 is not expected to have a
material impact on the Company's financial position.
In May 2009, the FASB issued SFAS No.165, Subsequent Events (SFAS 165).
SFAS165 establishes general standards for accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are available to be issued (subsequent events). More specifically, SFAS165 sets
forth the period after the balance sheet date during which management of a
reporting entity should evaluate events or transactions that may occur for
potential recognition in the financial statements, identifies the circumstances
under which an entity should recognize events or transactions occurring after
the balance sheet date in its financial statements and the disclosures that
should be made about events or transactions that occur after the balance sheet
date. SFAS 165 provides largely the same guidance on subsequent events which
previously existed only in auditing literature. The Company does not anticipate
that the adoption of this statement will have a material impact on its
consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable to a smaller reporting company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Our financial statements are contained in pages F-1 through F-25, which
appear at the end of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM 9A(T). CONTROLS AND PROCEDURES.
DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer are responsible
for establishing and maintaining disclosure controls and procedures for our
company. Disclosure controls and procedures are controls and procedures designed
to reasonably assure that information required to be disclosed in our reports
filed under the Securities Exchange Act of 1934, such as this report, is
recorded, processed, summarized and reported within the time periods prescribed
by SEC rules and regulations, and to reasonably assure that such information is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, to allow timely decisions regarding
required disclosure.
38
Our management does not expect that our disclosure controls or our
internal controls will prevent all error and fraud. A control system, no matter
how well conceived and operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met. In addition, the
design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their
costs. Because of the inherent limitations in all control systems, no evaluation
of controls can provide absolute assurance that all control issues and instances
of fraud, if any, within a company have been detected. These inherent
limitations include the realities that judgments in decision-making can be
faulty, and that breakdowns can occur because of simple error or mistake.
Additionally, controls can be circumvented by the individual acts of some
persons, by collusion of two or more people or by management override of the
control. The design of any systems of controls also is based in part upon
certain assumptions about the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its stated goals under all
potential future conditions. Over time, controls may become inadequate because
of changes in conditions, or the degree of compliance with the policies or
procedures may deteriorate. Because of these inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and
not be detected.
As required by Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as of April 30, 2009, the end of the period covered by
this report, our management concluded its evaluation of the effectiveness of the
design and operation of our disclosure controls and procedures. As of the
evaluation date, our Chief Executive Officer and Chief Financial Officer
concluded that we maintain disclosure controls and procedures that are effective
in providing reasonable assurance that information required to be disclosed in
our reports under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods prescribed by SEC rules and
regulations, and that such information is accumulated and communicated to our
management to allow timely decisions regarding required disclosure.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934. Our management assessed the effectiveness of
our internal control over financial reporting as of April 30, 2009. In making
this assessment, our management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission ("COSO") in Internal
Control-Integrated Framework. Our management has concluded that as of April 30,
2009 our internal control over financial reporting is effective based on this
criteria.
This annual report does not include an attestation report of our
independent registered public accounting firm regarding internal control over
financial reporting. Our management's report was not subject to attestation by
our independent registered public accounting firm pursuant to temporary rules of
the SEC that permit us to provide only management's report in this annual
report.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in our internal control over financial reporting
identified in connection with the evaluation that occurred during our last
fiscal quarter (our fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, its
internal control over financial reporting.
39
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
NAME AGE POSITION
---- --- --------
Deloy Miller 62 Chairman of the Board of Directors
Scott M. Boruff 46 Chief Executive Officer and director
Paul W. Boyd 51 Chief Financial Officer
Charles M. Stivers 47 Director
Herman E. Gettelfinger 76 Director
DELOY MILLER. Mr. Miller has been Chairman of the Board of Directors
since December 1996, and was Chief Executive Officer from December 1997 to
August 2008. From 1967 to 1997, Mr. Miller was the founder and Chief Executive
Officer of our company. He is a seasoned gas and oil professional with more than
40 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. Mr. Miller served two terms as president of the
Tennessee Oil & Gas Association and in 1978 the organization named him the
Tennessee Oil Man of the Year. He continues to serve on the board of that
organization. Mr. Miller was appointed in 1978 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. Mr. Miller is
the father-in-law of Mr. Boruff.
SCOTT M. BORUFF. Mr. Boruff has served as a director and our Chief
Executive Officer since August 2008. Prior to joining our company, Mr. Boruff
has been a licensed investment banker and was a director from 2006 to 2007 with
Cresta Capital Strategies, LLC a New York investment banking firm that was
responsible for closing transactions in the $150 to $200 million category. Mr.
Boruff specialized in investment banking consulting services that included
structuring of direct financings, recapitalizations, mergers and acquisitions
and strategic planning with an emphasis in the gas and oil field. As a
commercial real estate broker for over 20 years Mr. Boruff developed condominium
projects, hotels, convention centers, golf courses, apartments and residential
subdivisions. As a consultant to us, Mr. Boruff led the last three major
financial transactions completed by the company. Mr. Boruff holds a Bachelor of
Science in Business Administration from East Tennessee State University. Mr.
Boruff is the son-in-law of Mr. Miller.
PAUL W. BOYD. Mr. Boyd has served as our Chief Financial Officer since
September 2008. Prior to joining our company, from 2001 until August 2008 Mr.
Boyd was Chief Financial Officer and Treasurer of IdleAire Technologies
Corporation, a Knoxville, Tennessee company which provides a patented system
that enables long haul truck drivers to park their trucks for extended periods
of time while still using the heat, air conditioning and many other amenities.
From 1999 to 2000 Mr. Boyd was Chief Financial Officer of United States
Internet, Inc., a Knoxville, Tennessee company which was a subsidiary of
Earthlink Company. From 1996 to 1999 he was Treasurer of Clayton Homes, Inc., a
manufacturer of manufactured housing which is a subsidiary of Berkshire
Hathaway, Inc. Mr. Boyd received a B.B.A. in Accounting from the University of
Houston and is a certified public accountant.
40
CHARLES M. STIVERS. Mr. Stivers has been a member of our Board of
Directors since 2004. He also served as our Chief Financial Officer from 2004
until January 2006. Mr. Stivers has over 18 years accounting experience and over
12 years of experience within the energy industry. He owns and operates Charles
M. Stivers, C.P.A., which specializes in the oil and gas industry and has
clients located in eight different states. Mr. Stivers served as Treasurer and
Chief Financial Officer 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.
HERMAN E. GETTELFINGER. Mr. Gettelfinger has been a member of our Board
of Directors since 1997. Mr. Gettelfinger, who has been active in the gas and
oil drilling and exploration business for more than 35 years, is a co-owner and
President of Kelso Oil Company, Knoxville Tennessee . Kelso is one of eastern
Tennessee's largest distributors of motor oils, fuels and lubricants to the
industrial and commercial market.
Each director is elected at our annual meeting of shareholders and
holds office until the next annual meeting of shareholders, or until his
successor is elected and qualified.
KEY EMPLOYEES
NAME AGE POSITION
---- --- --------
Dr. Gary G. Bible 59 Vice President of Geology
David B. Wright 57 Vice President of Land
Eugene D. Lockyear 63 Vice President of Operations
DR. GARY G. BIBLE. Dr. Bible was appointed Vice President of Geology in
September 1997. Dr. Bible came from Alamco Inc., where he had served since May,
1991 as manager of geology and senior geologist. Dr. Bible earned his BS in
geology from Kent State University and his MS and PhD degrees in geology from
Iowa State University.
DAVID B. WRIGHT. Mr. Wright has served as head of our Land Department
since January 2002. Prior to joining our company, from 1998 to 2002, Mr. Wright
was a contract landman working for various oil and gas companies including
Miller Petroleum, Inc. From 1982-1998, Mr. Wright directed the day-to-day
activities associated with leasing, management, and exploration of more than
50,000 acres in Tennessee and Kentucky for Towner Petroleum. Mr. Wright received
B.S. degrees in both Geology and Geography from Tennessee Tech University; and
is a Registered Professional Geologist in the State of Tennessee, a member of
the American Institute of Professional Geologists, as well as a member of the
American Association of Professional Landmen.
EUGENE D. LOCKYEAR. Mr. Lockyear has served as our Vice President of
Operations since June 2009. From 1983 to 2009, Mr. Lockyear, 63, has been the
President of ETC and a Partner in LLC since its formation in 1996. He holds a
B.A. in Geology from Vanderbilt University and a M.S. in Geology and related
work in Engineering also from Vanderbilt University. Mr. Lockyear is a
Registered Professional Geologist - State of Tennessee and a former Registered
Professional Environmentalist - State of Tennessee as well as a member of Phi
Beta Kappa. On June 24, 2009 we issued a press release announcing the closing of
this transaction.
41
DIRECTOR COMPENSATION
We have not established standard compensation arrangements for our
directors and the compensation payable to each individual for their service on
our Board is determined from time to time by our Board of Directors based upon
the amount of time expended by each of the directors on our behalf. Currently,
executive officers of our company who are also members of the Board of Directors
do not receive any compensation specifically for their services as directors.
During fiscal 2009 we did not hold any in person meetings and thus did not pay
our outside directors attendance fees of $500 per meeting. All meetings were
held electronically or via telephone and there is no compensation for these
types of meetings. However, both outside directors received shares of our common
stock during fiscal 2009. Mr. Stivers received 100,000 shares and Mr.
Gettelfinger received 200,000 shares. The compensation from each can be seen
below:
DIRECTOR COMPENSATION
---------------------
FEES NON-EQUITY NON-QUALIFIED
EARNED OR STOCK OPTION INCENTIVE PLAN DEFERRED ALL OTHER
PAID IN AWARDS AWARDS COMPENSATION COMPENSATION COMPENSATION
NAME CASH ($) ($) ($) ($) EARNINGS ($) ($) TOTAL ($)
---- --------- ------ ------ -------------- ------------- ------------ ---------
Charles M. Stivers - 33,000 - - - - $ 33,000
Herman Gettelfinger - 66,000 - - - - $ 66,000
CODE OF CONDUCT
We have adopted a Code of Conduct that applies to our President, Chief
Executive Officer, Chief Financial Officer Chief Accounting Officer or
Controller and any other persons performing similar functions. This Code
provides written standards that we believe are reasonably designed to deter
wrongdoing and promote honest and ethical conduct, including the ethical
handling of actual or apparent conflicts of interest between personal and
professional relationships, and full, fair, accurate, timely and understandable
disclosure in reports we file with the Securities Exchange Commission.
Copies of our Code of Conduct may be obtained without charge by written
request to us at Miller Petroleum, Inc., 3651 Baker Highway, Huntsville,
Tennessee 37756, Attention: Corporate Secretary.
COMMITTEES OF THE BOARD OF DIRECTORS
Our Board of Directors has established an Audit Committee. The Audit
Committee duties are to (1) pre-approve audit and nonaudit services.(2) receive
reports from auditor on critical accounting policies; receive reports from
auditor on discussions with management on alternative GAAP, their effects, and
the auditor's reference; receive reports from auditor on material communications
with management. (3) oversee the auditor engagement (engaging, compensation, and
resolving disagreements with management on financial reporting). and (4) provide
procedures to receive, retain, and treat complaints; provide procedures to
confidentially handle employee complaints (whistle-blower protection). Messrs.
Boruff, Gettelfinger and Stivers are currently the members of the Audit
Committee. Mr. Stivers is an "audit committee financial expert" within the
meaning of Item 401(e) of Regulation S-K. In general, an "audit committee
financial expert" is an individual member of the audit committee or Board of
Directors who:
42
o understands generally accepted accounting principles and financial
statements,
o is able to assess the general application of such principles in
connection with accounting for estimates, accruals and reserves,
o has experience preparing, auditing, analyzing or evaluating
financial statements comparable to the breadth and complexity to our
financial statements,
o understands internal controls over financial reporting, and
o understands audit committee functions.
Our Board of Directors has not yet established a Compensation Committee
or a Nominating Committee, or any committees performing a similar function. The
functions of those committees are being undertaken by the entire board as a
whole. Because we have only two independent directors, our Board of Directors
believes that the establishment of committees of the Board would not provide any
benefits to our company and could be considered more form than substance.
We do not have a policy regarding the consideration of any director
candidates which may be recommended by our shareholders, including the minimum
qualifications for director candidates, nor has our Board of Directors
established a process for identifying and evaluating director nominees. We have
not adopted a policy regarding the handling of any potential recommendation of
director candidates by our shareholders, including the procedures to be
followed. Our Board has not considered or adopted any of these policies as we
have never received a recommendation from any shareholder for any candidate to
serve on our Board of Directors. Given the operational size of our company , we
do not anticipate that any of our shareholders will make such a recommendation
in the near future. While there have been no nominations of additional directors
proposed, in the event such a proposal is made, all members of our Board will
participate in the consideration of director nominees.
ITEM 11. EXECUTIVE COMPENSATION.
The following table summarizes all compensation recorded by us in the
last completed year for:
o our principal executive officer or other individual serving in a
similar capacity,
o our two most highly compensated executive officers other than our
principal executive officer who were serving as executive officers
at April 30, 2009 as that term is defined under Rule 3b-7 of the
Securities Exchange Act of 1934, and
o up to two additional individuals for whom disclosure would have been
required but for the fact that the individual was not serving as an
executive officer at April 30, 2009.
43
For definitional purposes, these individuals are sometimes referred to
as the "named executive officers." The value attributable to any option awards
in the following table is computed in accordance with FAS 123R.
SUMMARY COMPENSATION TABLE
--------------------------
NON-
NONEQUITY QUALIFIED
INCENTIVE DEFERRED ALL
PLAN COMPEN- OTHER
STOCK OPTION COMPEN- SATION COMPEN-
NAME AND PRINCIPAL SALARY BONUS AWARDS AWARDS SATION EARNINGS SATION TOTAL
POSITION YEAR ($) ($) ($) ($) ($) ($) ($) ($)
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)
------------------- ---- ------- ------- ------ ------ --------- --------- ------- -------
Scott M. Boruff (1) 2009 182,755 250,000 53,625 - - - 9,059 486,439
Deloy Miller (2) 2009 200,000 - - - - - 2,244 202,244
2008 200,000 - - - - - - 200,000
Paul W. Boyd (3) 2009 69,231 - - 17,800 - - 4,000 91,031
(1) Mr. Boruff has served as our Chief Executive Officer since August 2008. His
bonus of $250,000 was net of certain expenses and had an accrual of $186,452 on
April 30, 2009. All other compensation included an auto allowance of $1,000 per
month plus $59 of compensation derived from personal use of a Company vehicle.
(2) Mr. Miller served as our Chief Executive Officer from December 1997 to
August 2008. All other compensation included $2,244 of compensation derived from
personal use of a Company vehicle in 2009 and $0 in 2008.
(3) Mr. Boyd has served as our Chief Financial Officer since September 2008. All
other compensation included an auto allowance of $500 per month.
EXECUTIVE COMPENSATION ARRANGEMENTS
EMPLOYMENT AGREEMENT WITH MR. BORUFF
Effective August 1, 2008, we entered into an employment agreement with
Mr. Scott M. Boruff pursuant to which Mr. Boruff will serve as our Chief
Executive Officer for an initial term of five years, subject to additional
one-year renewal periods. Under the terms of the agreement, as amended, Mr.
Boruff's compensation consists of the following:
o 10 year options to purchase 250,000 shares of our common stock at an
exercise price per share of $0.33, with vesting in equal annual
installments over a period of four years, or immediately upon a
change of control of our company as described in the agreement, and
o a restricted stock grant of 250,000 shares of common stock, with
vesting in equal annual installments over a period of four years, or
on an accelerated basis in the event of a change of control of our
company also as described in the agreement.
44
Mr. Boruff is also entitled to receive certain incentive compensation
in the form of cash and shares of our common stock based upon, and subject to,
two performance benchmarks, gross revenue and earnings before income taxes,
depreciation and amortization (EBITDA), as follows:
o 100% of his base salary and 100,000 shares of our common stock in
the event that our gross revenues for fiscal 2009 (annualized
beginning on the date of the agreement) were not less than
$2,000,000 and EBITDA for such period was not less than $200,000,
Mr. Boruff earned $250,000 in cash bonuses and 100,000 shares in
stock bonuses for fiscal 2009.
o 100% of his base salary and 100,000 shares of our common stock in
the event that our gross revenues for fiscal 2010 are not less than
$4,000,000 and EBITDA for such period was not less than $400,000,
o 100% of his base salary and 100,000 shares of our common stock in
the event that our gross revenues for fiscal 2011 are not less than
$8,000,000 and EBITDA for such period was not less than $800,000,
o 100% of his base salary and 100,000 shares of our common stock in
the event that our gross revenues for fiscal 2012 are not less than
$16,000,000 and EBITDA for such period was not less than $1,600,000,
and
o 100% of his base salary and 100,000 shares of our common stock in
the event that our gross revenues for fiscal 2013 are not less than
$30,000,000 and EBITDA for such period was not less than $3,000,000.
One half of each element of incentive compensation is earned if the
gross revenue benchmark is achieved, and the other half of each element is
earned if the EBITDA benchmark is achieved.
Mr. Boruff is also entitled to a $1,000 per month automobile allowance.
The employment agreement also provides that Mr. Boruff is entitled to
participate in the employee benefit plans, programs and arrangements we have in
effect during the employment term which are generally available to our senior
executives. The agreement also contains indemnification, confidentiality and
non-solicitation clauses.
The agreement may be terminated by us for cause, as defined in the
agreement, or upon his death or disability, or for no cause. In the event the
agreement is terminated for either reason, if Mr. Boruff should terminate the
agreement for any reason or if the agreement is not renewed, he is only entitled
to receive his base salary through the date of termination. We may also
terminate the agreement without cause, in which event Mr. Boruff will be
entitled to his base salary through the date of termination and, should we
terminate the agreement during the initial term, as severance, his base salary
for one year. If we should terminate the agreement as a result of a change of
control as defined in the agreement, he is entitled to a lump sum payment equal
to 2.99 times Mr. Boruff's then base salary.
45
HOW MR. MILLER'S COMPENSATION WAS DETERMINED
Mr. Miller, who served as our principal executive officer until
December 1997 to August 1, 2008, was not a party to an employment agreement with
our company. His compensation was determined by the Board of Directors, of which
he is a member. The Board considered a number of factors in determining Mr.
Miller's compensation including the scope of his duties and responsibilities to
our company and the time he devotes to our business. The Board of Directors did
not consult with any experts or other third parties in fixing the amount of Mr.
Miller's compensation. During fiscal 2009, Mr. Miller's compensation package
included a base salary of $200,000.
HOW MR. BOYD' COMPENSATION WAS DETERMINED
Mr. Boyd has served as our Chief Financial Officer since September
2008. We are not a party to an employment agreement with Mr. Boyd. His
compensation is determined by the Board of Directors. The Board considered a
number of factors in determining Mr. Boyd's compensation including the scope of
his duties and responsibilities to our company and the time he devotes to our
business. The Board of Directors did not consult with any experts or other third
parties in fixing the amount of Mr. Boyd's compensation. In 2009 we paid Mr.
Boyd a base salary of $120,000 on an annualized basis. In addition, we granted
Mr. Boyd options to purchase 250,000 shares of our common stock with an exercise
price of $0.40 per share, vesting as follows:
o options to purchase 125,000 shares which vested in December 2008,
o options to purchase 62,500 shares that vest at such time as we have
raised at least $7.5 million in capital, and
o options to purchase the remaining 62,500 options that vest at such
time as we have raised at least $15 million in capital.
Mr. Boyd is also entitled to a $500 per month automobile allowance and
reimbursement of CPA related expenses and health insurance premiums.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table provides information concerning unexercised
options, stock that has not vested and equity incentive plan awards for each
named executive officer outstanding as of April 30, 2009.
46
OPTION AWARDS STOCK AWARDS
------------------------------------------------------------- -------------------------------------------
Equity
Equity incentive
incentive plan
plan awards:
awards: market
number or
Equity of payout
incentive unearned value of
plan shares, unearned
awards: Number Market units or shares,
Number of Number of Number of of shares value of other units or
securities securities securities or units shares or rights other
underlying underlying underlying of stock units of that rights
unexercised unexercised unexercised Option that have stock that have that have
options options unearned exercise Option not have not not not
(#) (#) options price expiration vested vested vested vested
Name exercisable unexercisable (#) ($) date (#) ($) (#) (#)
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
-------- ----------- ------------- ----------- -------- ---------- --------- ---------- --------- ---------
Scott M.
Boruff - 250,000 - $0.33 8/1/2018 - - - -
Deloy
Miller - - - - - - - - -
Paul W.
Boyd 125,000 125,000 - $0.40 9/23/2011 - - - -
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
We do not have a class of securities registered under Section 12 of the
Securities Exchange Act of 1934. Accordingly, our directors, officers and 10% or
greater shareholders are not required to file ownership reports pursuant to
Section 16(a) of the Securities Exchange Act of 1934.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
At July 17, 2009 we had 18,161,856 shares of our common stock issued
and outstanding. The following table sets forth information regarding the
beneficial ownership of our common stock as of July 17, 2009 by:
o each person known by us to be the beneficial owner of more than 5%
of our common stock;
o each of our directors;
o each of our named executive officers; and
o our named executive officers, directors and director nominees as a
group.
47
Unless otherwise indicated, the business address of each person listed
is in care of 3651 Baker Highway, Huntsville, TN 37756. The percentages in the
table have been calculated on the basis of treating as outstanding for a
particular person, all shares of our common stock outstanding on that date and
all shares of our common stock issuable to that holder in the event of exercise
of outstanding options, warrants, rights or conversion privileges owned by that
person at that date which are exercisable within 60 days of that date. Except as
otherwise indicated, the persons listed below have sole voting and investment
power with respect to all shares of our common stock owned by them, except to
the extent that power may be shared with a spouse.
AMOUNT AND NATURE OF
NAME OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP % OF CLASS
------------------------ -------------------- ----------
Deloy Miller (1) ......................... 4,075,343 19.9%
Scott M. Boruff (2) ...................... 3,000,500 14.6%
Paul W. Boyd ((3)) ....................... 125,000 *
David B. Wright .......................... 200,000 *
Charles M. Stivers ....................... 100,000 *
Herman E. Gettelfinger ................... 556,537 2.7%
All officers and directors as a group
(six persons)(1)(2)((3)) ................ 8,057,380 39.3%
Prospect Energy Corporation ((4)) ........ 2,160,000 10.5%
* represents less than 1%
(1) The number of shares beneficially owned by Mr. Miller includes 100 shares
held with his wife.
(2) The number of shares beneficially owned by Mr. Boruff includes 38,000 shares
held with his late wife and 62,500 stock options.
(3) The number of shares beneficially owned by Mr. Boyd includes 125,000 stock
options.
(4) The number of shares beneficially owned by Prospect Energy Corporation
represents shares of our common stock underlying presently exercisable
warrants. 1,000,000 of these warrants have an exercise price of $0.50 per
share and 1,160,000 of these warrants have an exercise price of $1.15 per
share. Prospect Energy Corporation's address is U.S. Bank Trust Security
Services, 1555 North Rivercenter Drive, MK-WI-S302, Milwaukee, WI 53212.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth securities authorized for issuance under
any equity compensation plans approved by our stockholders as well as any equity
compensation plans not approved by our stockholders as of April 30, 2009.
48
NUMBER OF
SECURITIES
REMAINING
AVAILABLE FOR
NUMBER OF FUTURE
SECURITIES WEIGHTED ISSUANCE
TO BE ISSUED AVERAGE UNDER EQUITY
UPON EXERCISE COMPENSATION
EXERCISE OF PRICE OF PLANS
OUTSTANDING OUTSTANDING (EXCLUDING
OPTIONS, OPTIONS, SECURITIES
WARRANTS AND WARRANTS AND REFLECTED IN
RIGHTS (A) RIGHTS (B) COLUMN (A))(C)
------------ ------------ --------------
Plan category
Plans approved by stockholders: ............. - - -
Plans not approved by stockholders:
Employment agreement with Scott M. Boruff (1) - $0.33 500,000
Option agreement with Paul W. Boyd (2) ...... 125,000 $0.40 -
(1) Pursuant to the terms of the employment agreement entered into with Mr.
Boruff in August 2008, we agreed to issue him as partial consideration for his
services to us:
o 10 year options to purchase 250,000 shares of our common stock at an
exercise price per share of $0.33, with vesting in equal annual
installments over a period of four years, or immediately upon a
change of control of our company as described in the agreement, and
o a restricted stock grant of 250,000 shares of common stock, with
vesting in equal annual installments over a period of four years, or
on an accelerated basis in the event of a change of control of our
company also as described in the agreement.
Through April 30, 2009 options to purchase 125,000 shares of our common
stock have vested and the number of shares reflected in column (a) above
represents the shares underlying the vested options. The number of shares
appearing in column (c) above includes shares underlying unvested options and
the unvested portion of the restricted stock grant, but excludes any shares of
our common stock which may be issued to Mr. Boruff as incentive compensation
upon our company meeting certain revenue and earnings thresholds. See Item 11.
Executive Compensation - Executive Compensation Arrangements - Employment
Agreement with Mr. Boruff appear earlier in this report.
(2) As partial compensation for his services, we granted Mr. Boyd options to
purchase 250,000 shares of our common stock with an exercise price of $0.40. Of
this amount options to purchase 125,000 shares of our common stock vested in
December 2008 and are represented in column (a) above. Of the remaining options
granted to him, options to purchase 62,500 shares vest at such time as we have
raised at least $7.5 million in capital, and options to purchase the remaining
62,500 options vest at such time as we have raised at least $15 million in
capital. Because these options are conditioned upon our company raising capital,
and, accordingly, may not be issued, they are excluded from this table. See Item
11. Executive Compensation - Executive Compensation Arrangements - How Mr.
Boyd's Compensation Was Determined appear earlier in this report.
49
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE.
The Company had an account receivable from Herman Gettelfinger, a
member of the Board of Directors, and his wife, at April 30, 2009 and April 30,
2008 in the amount of $19,882 and $5,145, respectively for work performed on oil
and gas wells.
The Company had an account payable to Charles Stivers, a member of the
Board of Directors, at April 30, 2009 and April 30, 2008 in the amount of $2,200
and $0, respectively for work performed on tax returns.
There are no assurances that the terms of the transactions with the
related parties are comparable to terms we could have obtained from unaffiliated
third parties.
DIRECTOR INDEPENDENCE
Two of our directors, Messrs. Stivers and Gettelfinger, are independent
within The NASDAQ Stock Market's director independence standards pursuant to
Marketplace Rule 4200.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Sherb & Co., LLP served as our independent registered public accounting
firm for 2009 and Rodefer Moss & Co., PLLC served as our independent registered
public accounting firm for 2008. The following table shows the fees that were
billed for the audit and other services provided by such firm for 2009 and 2008:
2009 2008
------- -------
Audit Fees ..................... $65,000 $70,341
Audit-Related Fees ............. $ 1,500 -
Tax Fees ....................... - -
All Other Fees ................. - -
------- -------
Total ................. $66,500 $70,341
Audit Fees -- This category includes the audit of our annual financial
statements, review of financial statements included in our Form 10-Q Quarterly
Reports and services that are normally provided by the independent auditors in
connection with engagements for those fiscal years. This category also includes
advice on audit and accounting matters that arose during, or as a result of, the
audit or the review of interim financial statements.
Audit-Related Fees -- This category consists of assurance and related
services by the independent auditors that are reasonably related to the
performance of the audit or review of our financial statements and are not
reported above under "Audit Fees." The services for the fees disclosed under
this category include consultation regarding our correspondence with the SEC and
other accounting consulting.
Tax Fees -- This category consists of professional services rendered by
our independent auditors for tax compliance and tax advice. The services for the
fees disclosed under this category include tax return preparation and technical
tax advice.
50
All Other Fees -- This category consists of fees for other
miscellaneous items.
Our Board of Directors has adopted a procedure for pre-approval of all
fees charged by our independent auditors. Under the procedure, the Board
approves the engagement letter with respect to audit, tax and review services.
Other fees are subject to pre-approval by the Board, or, in the period between
meetings, by a designated member of Board. Any such approval by the designated
member is disclosed to the entire Board at the next meeting. The audit and tax
fees paid to our independent registered public accounting firm with respect to
2009 were pre-approved by the entire Board of Directors.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
The following documents are filed as a part of this report or are
incorporated by reference to previous filings, if so indicated:
EXHIBIT
NO. DESCRIPTION
------- -----------
2.1 Agreement and Plan of Reorganization dated December 20, 1996 between
Triple Chip Systems, Inc. and Miller Petroleum, Inc. (1)
3.1 Certificate of Incorporation (2)
3.2 Certificate of Amendment of Certificate of Incorporation (2)
3.3 Certificate of Amendment of Certificate of Incorporation (2)
3.4 Certificate of Ownership and Merger and Articles of Merger between
Triple Chip Systems, Inc. and Miller Petroleum, Inc. (3)
3.5 Bylaws (2)
4.1 Form of Stock Purchase Warrant issued May 4, 2005 to Prospect Energy
Corporation (4)
4.2 Form of Stock Purchase Warrant issued May 4, 2005 to Petro Capital III,
L.P. (4)
4.3 Form of Stock Purchase Warrant issued May 4, 2005 to Petrol Capital
Advisors, LLC (4)
4.4 Form of Stock Purchase Warrant issued December 31, 2005 to Petro
Capital III, L.P. (5)
4.5 Form of Stock Purchase Warrant issued December 31, 2005 to Prospect
Energy Corporation (5)
4.6 Form of Stock Purchase Warrant issued December 31, 2005 to Petro
Capital Advisors, LLC (5)
4.7 Form of warrant issued to Cresta Capital Corporation *
51
4.8 Form of Option granted to Mr. Paul W. Boyd *
10.1 Purchase and Sale Agreement dated December 16, 1997 between AKS Energy
Corporation and Miller Petroleum, Inc. (6)
10.2 Assumption Agreement dated December 16, 1997 between AKS Energy
Corporation and Miller Petroleum, Inc. (6)
10.3 Purchase and Sale Agreement dated September 6, 2000 between NAMI
Resources Company, LLC and Miller Petroleum, Inc. (7)
10.4 Employment Agreement as of August 1, 2008 with Scott M. Boruff (8)
10.5 Amendment to Employment Agreement with Scott M. Boruff dated September
9, 2008 (9)
10.6 Form of Registration Rights Agreement dated May 4, 2005 by and among
Miller Petroleum, Inc., Petro Energy Corporation, Petrol Capital III,
L.P. and Petro Capital Advisors, LLC. (4)
10.7 Farmout Agreement dated September 3, 1999 between Tengasco, Inc. and
Miller Petroleum, Inc. (3)
10.8 Registration Rights Agreement dated May 4, 2005 (4)
10.9 Purchase and Sale Agreement dated June 13, 2008 between Atlas Energy
Resources, LLC and Miller Petroleum, Inc. (8)
10.10 Termination Agreement, General Release and Covenant Not To Sue Dated
June 13, 2008 with Cresta Capital Strategies, LLC*
14.1 Code of Conduct (10)
16.1 Letter from Rodefer Moss & Co., PLLC (11)
21.1 Subsidiaries of the registrant *
31.1 Rule 13a-14(a)/15d-14(a)certificate of Chief Executive Officer *
31.2 Rule 13a-14(a)/15d-14(a)certificate of Chief Financial Officer *
32.1 Section 1350 certification of Chief Executive Officer *
32.2 Section 1350 certification of Chief Financial Officer*
* filed herewith
(1) Incorporated by reference to the Current Report on Form 8-K dated
January 15, 1997.
(2) Incorporated by reference to the Annual Report on Form 10-KSB for the
year ended December 31, 1995.
(3) Incorporated by reference to the exhibits filed with the registration
statement on Form SB-2, SEC File No. 333-53856, as amended.
52
(4) Incorporated by reference to the Current Report on Form 8-K dated May
9, 2005.
(5) Incorporated by reference to the Quarterly Report on Form 10-QSB for
the period ended January 31, 2006.
(6) Incorporated by reference to the Current Report on Form 8-K dated March
17, 1998.
(7) Incorporated by reference to the Current Report on Form 8-K dated
September 21, 2000.
(8) Incorporated by reference to the Annual Report on Form 10-KSB for the
year ended April 30, 2008
(9) Incorporated by reference to the Current Report on Form 8-K dated
September 12, 2008.
(10) Incorporated by reference to the Annual Report on Form 10-KSB for the
year ended April 30, 2007.
(11) Incorporated by reference to the Current Report on Form 8-K dated
August 21, 2008.
53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Miller Petroleum, Inc.
Date: August 7, 2009 By: /s/ Scott M. Boruff
-------------------
Chief Executive Officer
Pursuant to the requirements of 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.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Deloy Miller Chairman of the Board August 7, 2009
---------------- of Directors
Deloy Miller
/s/ Scott M. Boruff Chief Executive Officer August 7, 2009
------------------- and director, principal
Scott M. Boruff executive officer
/s/ Paul W. Boyd Chief Financial Officer, August 7, 2009
---------------- principal financial
Paul W. Boyd and accounting officer
/s/ Charles M. Stivers Director August 7, 2009
----------------------
Charles M. Stivers
/s/ Herman E. Gettelfinger Director August 7, 2009
--------------------------
Herman E. Gettelfinger
54
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm .................. F-1
Report of Independent Registered Public Accounting Firm .................. F-2
Consolidated Balance Sheets .............................................. F-3
Consolidated Statements of Operations .................................... F-5
Consolidated Statements of Stockholders' Equity .......................... F-6
Consolidated Statements of Cash Flows .................................... F-7
Notes to the Consolidated Financial Statements ........................... F-9
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Miller Petroleum, Inc.
We have audited the accompanying consolidated balance sheet of Miller
Petroleum, Inc. as of April 30, 2009 and the related consolidated statements of
operations, stockholders' equity (deficit), and cash flows for the year ended
April 30, 2009. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
the Company as of April 30, 2009, and the results of its operations and cash
flows for the year ended April 30, 2009, in conformity with generally accepted
accounting principles in the United States.
The accompanying consolidated financial statements have been prepared assuming
that Miller Petroleum, Inc. will continue as a going concern. As more fully
described in Note 2, the Company has incurred recurring operating losses and
will have to obtain additional financing to sustain operations. These conditions
raise substantial doubt about the Company's ability to continue as a going
concern. Management's plans in regard to these matters are also described in
Note 2. The financial statements do not include any adjustments to reflect the
possible effects on the recoverability and classification of assets or the
amounts and classification of liabilities that may result from the outcome of
this uncertainty.
/s/ Sherb & Co., LLP
SHERB & CO, LLP
Certified Public Accountants
New York, New York
July 30, 2009
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors Miller Petroleum, Inc. and Subsidiary
Huntsville, Tennessee
We have audited the accompanying consolidated balance sheet of Miller Petroleum,
Inc. and its Subsidiary as of April 30, 2008 and the related consolidated
statements of operations, changes in stockholders' equity (deficit) and cash
flows for the year then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. The Company
has determined that it is not required to have, nor was it engaged to perform,
an audit of internal control over financial reporting. Our audits included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referenced above present
fairly, in all material respects, the financial position of Miller Petroleum,
Inc. and its Subsidiary as of April 30, 2008, and the results of its operations
and cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States of America.
/s/ Rodefer Moss & Co, PLLC
Knoxville, Tennessee
August 13, 2008
F-2
MILLER PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
April 30, April 30,
2009 2008
----------- -----------
CURRENT ASSETS
Cash ............................................. $ 46,566 $ 42,436
Cash - restricted ................................ 1,982,552 -
Accounts receivable, net ......................... 124,815 131,302
Accounts receivable - related parties ............ 19,882 5,144
Inventory ........................................ 87,120 65,856
----------- -----------
Total Current Assets ............................. 2,260,935 244,738
Fixed Assets ..................................... 5,751,017 1,161,019
Less: accumulated depreciation ................... (1,022,017) (595,362)
----------- -----------
Net Fixed Assets ................................. 4,729,000 565,657
OIL AND GAS PROPERTIES
(On the basis of successful efforts accounting) .. 1,787,911 1,544,577
Land ............................................. 406,500 496,500
Deferred Interest ................................ 6,892 -
Prepaid Offering Cost ............................ 666,476 -
Cash - restricted long-term ...................... 84,019 83,000
----------- -----------
Total Other Assets ............................... 1,163,887 579,500
----------- -----------
TOTAL ASSETS ..................................... $ 9,941,733 $ 2,934,472
=========== ===========
(continued)
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
MILLER PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
(continued)
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
April 30, April 30,
2009 2008
----------- -----------
CURRENT LIABILITIES
Accounts payable - trade ......................... $ 301,082 $ 389,275
Accrued expenses ................................. 271,099 164,982
Asset retirement liability ....................... 57,246 45,216
Unearned revenue ................................. 131,587 -
Notes payable - related parties .................. - 80,200
Current portion of notes payable ................. 1,870,732 646,430
Shares subject to redemption ..................... - 4,350,000
----------- -----------
Total Current Liabilities ........................ 2,631,746 5,676,103
LONG-TERM LIABILITIES
Deferred income taxes payable .................... 778 -
Notes payable - other ............................ 88,473 -
----------- -----------
Total Long-term Liabilities ...................... 89,251 -
----------- -----------
Total Liabilities ........................... 2,720,997 5,676,103
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock, 500,000,000 shares authorized st
$0.0001 par value, 15,974,356 and 11,666,856
shares issued and outstanding, respectively .... 1,597 1,166
Additional paid-in capital ....................... 8,555,324 6,949,761
Accumulated (deficit) ............................ (1,336,185) (9,692,558)
----------- -----------
Total Stockholders' Equity (Deficit) ............. 7,220,736 (2,741,631)
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ....... $ 9,941,733 $ 2,934,472
=========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended
--------------------------
April 30, April 30,
2009 2008
----------- -----------
REVENUES
Oil and gas revenue .............................. $ 640,094 $ 566,478
Service and drilling revenue ..................... 927,210 262,864
----------- -----------
Total Revenue .................................... 1,567,304 829,342
COSTS AND EXPENSES
Cost of oil and gas revenue ...................... 240,389 62,213
Cost of service and drilling revenue ............. 1,184,901 297,942
Selling, general and administrative .............. 2,712,943 1,747,659
Depreciation, depletion and amortization ......... 649,070 227,974
Impairment loss .................................. - 666,073
----------- -----------
Total Costs and Expenses ......................... 4,787,303 3,001,861
----------- -----------
LOSS FROM OPERATIONS ............................. (3,219,999) (2,172,519)
OTHER INCOME (EXPENSE)
Interest income .................................. 62,741 2,099
Interest expense ................................. (87,526) (367,496)
Loan fees and costs .............................. (124,085) -
Gain on sale of equipment ........................ 10,450 102,119
Gain on sale of oil and gas properties ........... 11,715,570 -
----------- -----------
Total Other Income (Expense) ..................... 11,577,150 (263,278)
----------- -----------
NET INCOME (LOSS) BEFORE INCOME TAXES ............ 8,357,151 (2,435,797)
INCOME TAX EXPENSE (BENEFIT) ..................... 778 -
----------- -----------
NET INCOME (LOSS) ................................ $ 8,356,373 $(2,435,797)
=========== ===========
BASIC AND DILUTED - INCOME (LOSS) PER SHARE ...... $ 0.56 $ (0.17)
BASIC AND DILUTED - WEIGHTED AVERAGE
SHARES OUTSTANDING ............................. 14,827,877 14,454,288
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Additional Accumulated
Common Shares Paid-in Earnings
Shares Amount Capital (Deficit) Total
----------- ----------- ----------- ----------- -----------
Balance, April 30, 2007 .................... 11,466,856 $ 1,146 $ 6,349,691 $(7,256,761) $ (905,924)
Amortization of unearned compensation ...... - - 375,321 - 375,321
Amortization of financing cost warrants .... - - 22,759 - 22,759
Issuance of warrants for financing cost .... - - 153,010 - 153,010
Issuance of stock for financing cost ....... 200,000 20 48,980 - 49,000
Net loss for the year ended April 30, 2008 . - - - (2,435,797) (2,435,797)
----------- ----------- ----------- ----------- -----------
Balance, April 30, 2008 .................... 11,666,856 1,166 6,949,761 (9,692,558) (2,741,631)
Issuance of warrants ....................... - - 174,000 - 174,000
Issuance of stock for compensation ......... 3,762,500 376 1,153,249 - 1,153,625
Stock option expense ....................... - - 17,800 - 17,800
Issuance of warrants for financing cost .... - - 122,818 - 122,818
Issuance of stock for financing cost ....... 350,000 35 136,965 - 137,000
Exercise of warrants ....................... 195,000 20 731 - 751
Net income for the year ended April 30, 2009 - - - 8,356,373 8,356,373
----------- ----------- ----------- ----------- -----------
Balance, April 30, 2009 .................... 15,974,356 $ 1,597 $ 8,555,324 $(1,336,185) $ 7,220,736
=========== =========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
F-6
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended
----------------------------
April 30, April 30,
2009 2008
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) ................................... $ 8,356,373 $ (2,435,797)
Depreciation, depletion and amortization ......... 649,070 227,974
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided (Used) by Operating Activities:
Gain on sale of equipment ........................ (10,450) (102,119)
Gain on sale of oil and gas properties ........... (11,715,570) -
Warrants issued .................................. 174,000 -
Issuance of stock for compensation ............... 1,153,625 -
Impairment loss .................................. - 666,073
Amortization of unearned compensation ............ - 375,321
Issuance of warrants for financing cost .......... 122,818 175,769
Issuance of stock for financing cost ............. 137,000 49,000
Issuance of stock options for services ........... 17,800 -
Warrant cost ..................................... 751 -
Changes in Operating Assets and Liabilities:
Accounts receivable .......................... (8,251) 111,529
Inventory .................................... (21,264) 48,835
Bank overdraft ............................... - (16,933)
Accounts payable ............................. (154,168) 23,683
Accrued expenses ............................. 118,147 116,324
Unearned revenue ............................. 131,587 -
Income taxes payable ......................... 778 -
Deferred interest ............................ (6,892) -
------------ ------------
Net Cash Used by Operating Activities ............ (1,054,646) (760,341)
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of equipment and improvements ........... (4,408,998) -
Sale of oil and gas properties ................... 12,519,713 -
Purchase of oil and gas properties ............... (1,268,942) -
Purchase of land ................................. (110,000) -
Proceeds from sale of equipment .................. 28,500 117,451
Proceeds from sale of well equipment and supplies - 18,000
Proceeds from sale of pipeline ................... - 576,500
Changes in note receivable ....................... - 7,900
------------ ------------
Cash Provided by Investing Activities ............ 6,760,273 719,851
------------ ------------
(continued)
The accompanying notes are an integral part of these consolidated financial statements.
F-7
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(continued)
Year Ended
----------------------------
April 30, April 30,
2009 2008
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on notes payable ........................ (726,630) (267,550)
Proceeds from borrowing .......................... 2,025,180 350,476
Restricted cash .................................. (1,982,552) -
Restricted cash non-current ...................... (1,019) -
Stock repurchase ................................. (4,350,000) -
Prepaid offering cost ............................ (666,476) -
------------ ------------
Net Cash Provided (Used) by Financing Activities . (5,701,497) 82,926
------------ ------------
NET INCREASE IN CASH ................................ 4,130 42,436
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR ........ 42,436 -
------------ ------------
CASH AND CASH EQUIVALENTS, END OF YEAR .............. $ 46,566 $ 42,436
============ ============
CASH PAID FOR:
INTEREST ......................................... $ 87,526 $ 52,652
============ ============
INCOME TAXES ..................................... $ - $ -
============ ============
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND
FINANCING ACTIVITIES:
Financing costs from issuance of warrants and stock . $ 259,783 $ 224,769
============ ============
The accompanying notes are an integral part of these consolidated financial statements.
F-8
MILLER PETROLEUM, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
APRIL 30, 2009 AND 2008
(1) ORGANIZATION AND DESCRIPTION OF BUSINESS
These consolidated financial statements include the accounts of Miller
Petroleum, Inc. and the accounts of its subsidiaries, Miller Drilling TN, LLC,
Miller Rig & Equipment, LLC and Miller Energy Services,.
The Company's principal business consists of oil and gas exploration,
production and related property management in the Appalachian region of eastern
Tennessee. The Company's corporate offices are in Huntsville, Tennessee. The
Company operates as one reportable business segment, based on the similarity of
activities.
(2) ACCOUNTING POLICIES
GOING CONCERN
The accompanying consolidated financial statements have been prepared
assuming we are a going concern, which assumption contemplates the realization
of assets and satisfaction of liabilities in the normal course of business.
Although we recorded net income for the fiscal year, we did record a loss from
operations and may lack sufficient liquidity to continue operations over the
next year. Management's 2010 forecast indicates positive trends from
capital-raising, increased production and related revenues, but it may not
result in positive operating income, net income and positive cash flows. These
factors raise substantial doubt about our ability to continue as a going
concern. The ability of the Company to continue as a going concern is dependent
upon the successful completion of additional financing.
OIL AND GAS ACTIVITIES
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 and accumulated depreciation or depletion are
removed from the accounts and any gain or loss is credited or charged to
operations.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization of capitalized costs of proved
oil and gas properties is provided on a pooled basis using the
units-of-production method based upon proved reserves. Acquisition costs of
proved properties are amortized by using total estimated units of proved
reserves as the denominator. All other costs are amortized using total estimated
units of proved developed reserves.
F-9
IMPAIRMENT OF LONG-LIVED ASSETS AND LONG-LIVED ASSETS TO BE DISPOSED OF
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," requires that an asset be evaluated for impairment when the carrying
amount of an asset exceeds the sum of the undiscounted estimated future cash
flows of the asset. In accordance with the provisions of SFAS 144, the Company
reviews the carrying values of its long-lived assets whenever events or changes
in circumstances indicate that such carrying values may not be recoverable. If,
upon review, the sum of the undiscounted pretax cash flows is less than the
carrying value of the asset group, the carrying value is written down to
estimated fair value. Individual assets we grouped for impairment purposes at
the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets, generally on a
field-by-field basis. The fair value of impaired assets is determined based on
quoted market prices in active markets, if available, or upon the present values
of expected future cash flows using discount rates commensurate with the risks
involved in the asset group. The long-lived assets of the Company, which are
subject to evaluation, consist primarily of oil and gas properties.
For the year ended April 30, 2008 the Company expensed $409,948 of
equipment and well supplies in inventory to reflect the new, significant
emphasis on drilling activities. The Company also expensed assets of
approximately $179,000 for impaired oil and gas wells and approximately $77,000
for old unused equipment. Collectively, these write-offs are included in the
Company's statement of income for the year ended April 30, 2008 under the
caption "Impairment Loss". No equipment was considered impaired and written off
during the year ended April 30, 2009.
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 of 3,840,000, such as those issuable upon the exercise of stock
options and warrants, were issued during the period.
CASH EQUIVALENTS
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company, and its wholly-owned subsidiaries Miller Drilling TN, LLC, Miller Rig &
Equipment, LLC and Miller Energy Services, LLC. All significant intercompany
transactions have been eliminated.
ACCOUNTS RECEIVABLE
At April 30, 2009 and 2008 accounts receivable consists of amounts due
from the sale of oil. The Company deems all accounts receivable collectible at
April 30, 2009 and 2008 after deducting $10,475 and $15,000, respectively, for
an allowance for doubtful accounts.
F-10
INVENTORY
Inventory consists primarily of crude oil in tanks and is carried at
cost.
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 in Years
----- --------------
Building ................... 40
Machinery and equipment .... 5-20
Vehicles ................... 5-7
Office equipment ........... 5
PREPAID OFFERING COST
Prepaid offering costs, primarily consisting of legal, accounting,
printing and filing fees relating to an offering have been capitalized. The
prepaid offering costs will be offset against offering proceeds in the event the
offering is successful. In the event the offering is unsuccessful or is
abandoned, the prepaid offering costs will be expensed.
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
2009 and 2008. Sales of various parts and equipment is immaterial for the years
ended April 30, 2009 and 2008 and has been combined with service and drilling
revenue.
CONCENTRATIONS OF CREDIT RISK
Financial instruments which potentially subject the Company to
concentrations of credit risk are primarily 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 $10,475 at
April 30, 2009 and $15,000 at April 30, 2008. Accounts receivable more than 90
days old were $14,410 at April 30, 2009 and $18,971 at April 30, 2008. Bad debt
expense for the year ended April 30, 2009 and 2008 was $15,081 and $51,066,
respectively.
F-11
Financial instruments, which potentially subject us to concentration of
credit risk, consist principally of cash described below.
For the year ended April 30, 2009 we had $1,732,552 in balances in
excess of the $250,000 limit insured by the Federal Deposit Insurance
Corporation of $250,000.
MAJOR CUSTOMERS
The Company depends upon local purchasers of hydrocarbons to purchase
our products in the areas where its properties are located.
Currently, we are selling oil and natural gas to the following purchasers:
Oil:
Barrett Oil Purchasing purchases oil from the Koppers Fields. Barrett
accounted for $191,503 and $320,034 of the Company's total revenue,
which was 12% and 38% of the Company's total revenue, respectively for
fiscal 2009 and 2008.
Gas:
Cumberland Valley Resources purchases natural gas produced from the
joint venture with Delta Producers, Inc. in the Jellico East Field.
Delta Producers Inc. accounted for $629,298 and $355,641 of the
Company's total revenue, which was 40% and 37% of the Company's total
revenue, respectively for fiscal 2009 and 2008.
Drilling:
Tri-Global Holdings, LLC, Montello Resources, LLC, Delta Producers Inc.
and Herman Gettelfinger accounted for $435,422 and $196,831, which was
47% and 75% of the Company's service and drilling revenue, respectively
for fiscal 2009 and 2008.
Atlas America, LLC has contracted with us to perform drilling for them
on an as needed basis. During fiscal 2009, Atlas America, LLC accounted
for $436,935 and $0, which was 47% and 0% of the Company's service and
drilling revenue, respectively for fiscal 2009 and 2008.
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 Lee Keeling & Associates, Inc. of Tulsa, Oklahoma for
the years ended April 30, 2009 and 2008, respectively.
RECLASSIFICATIONS
Certain amounts and balances pertaining to the April 30, 2008 financial
statements have been reclassified to conform to the April 30, 2009 financial
statement presentations.
F-12
STOCK WARRANTS AND OPTIONS
The Company measures its equity transactions with employees using the
fair value based method of accounting prescribed by Statement of Financial
Accounting Standards No. 123R.
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.
We record deferred income tax using enacted tax laws and rates for the
years in which we expect the tax to be paid. We provide deferred income tax when
there is a temporary difference in recording such items for financial reporting
and income tax reporting. The temporary differences that may give rise to
deferred tax assets primarily are depletion, depreciation and impairments, which
we reduced by a like amount because we are uncertain as to whether we will
realize the deferred tax assets.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts reported in the balance sheet for cash,
receivables, accounts payable and accrued expenses approximate fair value based
on the short-term maturity of these instruments.
RECENT ACCOUNTING PRONOUNCEMENTS
In December 2007, the Financial Accounting Standards Board (FASB)
issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial
Statements - an amendment of ARB No. 51". This statement improves the relevance,
comparability, and transparency of the financial information that a reporting
entity provides in its consolidated financial statements by establishing
accounting and reporting standards that require; the ownership interests in
subsidiaries held by parties other than the parent and the amount of
consolidated net income attributable to the parent and to the noncontrolling
interest be clearly identified and presented on the face of the consolidated
statement of income, changes in a parent's ownership interest while the parent
retains its controlling financial interest in its subsidiary be accounted for
consistently, when a subsidiary is deconsolidated, any retained noncontrolling
equity investment in the former subsidiary be initially measured at fair value,
entities provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling
owners.
SFAS No. 160 affects those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary. SFAS No. 160 is effective for fiscal years, and interim periods
within those fiscal years, beginning on or after December 15, 2008. Early
adoption is prohibited. The adoption of this statement is not expected to have a
material effect on the Company's financial statements.
F-13
In March 2008, the FASB issued SFAS No. 161, "Disclosures about
Derivative Instruments and Hedging Activities, an amendment of FASB Statement
No. 133" (SFAS 161). This statement is intended to improve transparency in
financial reporting by requiring enhanced disclosures of an entity's derivative
instruments and hedging activities and their effects on the entity's financial
position, financial performance, and cash flows. SFAS 161 applies to all
derivative instruments within the scope of SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133) as well as related hedged items,
bifurcated derivatives, and nonderivative instruments that are designated and
qualify as hedging instruments. Entities with instruments subject to SFAS 161
must provide more robust qualitative disclosures and expanded quantitative
disclosures. SFAS 161 is effective prospectively for financial statements issued
for fiscal years and interim periods beginning after November 15, 2008, with
early application permitted. The adoption of SFAS No. 161 is not expected to
have a material impact on the Company's financial position.
In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally
Accepted Accounting Principles." SFAS No. 162 identifies the sources of
accounting principles and provides entities with a framework for selecting the
principles used in preparation of financial statements that are presented in
conformity with GAAP. The current GAAP hierarchy has been criticized because it
is directed to the auditor rather than the entity, it is complex, and it ranks
FASB Statements of Financial Accounting Concepts, which are subject to the same
level of due process as FASB Statements of Financial Accounting Standards, below
industry practices that are widely recognized as generally accepted but that are
not subject to due process. The Board believes the GAAP hierarchy should be
directed to entities because it is the entity (not its auditors) that is
responsible for selecting accounting principles for financial statements that
are presented in conformity with GAAP. SFAS 162 is effective 60 days following
the SEC's approval of PCAOB Auditing Standard No. 6, Evaluating Consistency of
Financial Statements (AS/6). The adoption of FASB 162 is not expected to have a
material impact on the Company's financial position.
In May 2008, the FASB issued SFAS No. 163, "Accounting for Financial
Guarantee Insurance Contracts-an interpretation of FASB Statement No. 60."
Diversity exists in practice in accounting for financial guarantee insurance
contracts by insurance enterprises under FASB Statement No. 60, Accounting and
Reporting by Insurance Enterprises. This results in inconsistencies in the
recognition and measurement of claim liabilities. This Statement requires that
an insurance enterprise recognize a claim liability prior to an event of default
(insured event) when there is evidence that credit deterioration has occurred in
an insured financial obligation. This Statement requires expanded disclosures
about financial guarantee insurance contracts. The accounting and disclosure
requirements of the Statement will improve the quality of information provided
to users of financial statements. SFAS 163 is effective for financial statements
issued for fiscal years beginning after December 15, 2008, and interim periods
within those fiscal years. The adoption of FASB 163 is not expected to have a
material impact on the Company's financial position.
F-14
In May 2009, the FASB issued SFAS No.165, Subsequent Events (SFAS 165).
SFAS165 establishes general standards for accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are available to be issued (subsequent events). More specifically, SFAS165 sets
forth the period after the balance sheet date during which management of a
reporting entity should evaluate events or transactions that may occur for
potential recognition in the financial statements, identifies the circumstances
under which an entity should recognize events or transactions occurring after
the balance sheet date in its financial statements and the disclosures that
should be made about events or transactions that occur after the balance sheet
date. SFAS 165 provides largely the same guidance on subsequent events which
previously existed only in auditing literature. The Company does not anticipate
that the adoption of this statement will have a material impact on its
consolidated financial statements.
(3) SALE OF OIL AND GAS PROPERTIES AND EQUIPMENT PURCHASES
On June 13, 2008 we sold approximately 30,000 acres of oil and gas
leases and eight drilled but not completed wells to Atlas America, LLC ("Atlas")
for $19.625 million. At that time Wind City Oil & Gas, LLC and related entities
were paid $10.6 million for 2.9 million shares of the Company's common stock,
eight drilled but not completed gas wells, two producing gas wells, and a RD20
drilling rig and related equipment in settlement of all litigation between the
parties.
On November 10, 2008, the Company finalized a drilling contract with
Atlas Energy Resources, LLC, an affiliate of Atlas. This is a two year agreement
that will utilize two of the Company's drilling rigs operating in the East
Tennessee area of the Appalachian Basin. We acquired a 2007 COPCO Model RD III
drilling rig and related equipment drilling rig from Atlas to assist in drilling
the wells. This rig has been mobilized to the site and has commenced drilling
operations. The Company borrowed $1,850,125, secured by a certificate of
deposit, to purchase this drilling rig.
After the sale was completed, the Company paid off all notes, all
undisputed payables, transaction fees of $600,000 to Cresta Capital/Consortium,
and paid a transaction fee of $300,000 and issued 2,500,000 shares of common
stock valued at $825,000 to Scott Boruff, a former associate of Cresta Capital.
Boruff was subsequently hired effective August 1, 2008 as the new CEO of the
Company (see Commitments note below). He is a son-in-law of Deloy Miller the
former CEO and current Chairman of the Board of Directors. Cresta was also
granted a warrant to purchase one million shares of the Company's common stock
for $1.00 per share for a period expiring three years after the grant date and
cancelled the five million performance warrants that it held.
The net gain on this sale of oil and gas property transaction was
$11,715,570.
A third party interested in aforementioned sale of the oil and gas
properties is contesting the sale, see the Litigation note below.
F-15
(4) PARTICIPANT RECEIVABLES AND RELATED PARTY RECEIVABLES
Participant and related party receivables consist of receivables
contractually due from our various joint venture partners in connection with
routine exploration, betterment and maintenance activities. Our collateral for
these receivables generally consists of lien rights over the related oil
producing properties at both April 30, 2008 and 2009.
(5) RELATED PARTY TRANSACTIONS
The Company had an account receivable from a member of the Board of
Directors, and his wife, at April 30, 2009 and April 30, 2008 in the amount of
$19,882 and $5,144, respectively for work performed on oil and gas wells. This
board member and his wife own partial interests in the oil and gas wells the
Company also owns.
(6) FIXED ASSETS
Fixed assets consist of the following:
April 30, 2009 April 30, 2008
-------------- --------------
Machinery & Equipment .......... $ 4,218,556 $ 571,318
Vehicles ....................... 938,624 248,062
Buildings ...................... 544,546 315,835
Office Equipment ............... 49,291 25,804
-------------- --------------
5,751,017 1,161,019
Less: accumulated depreciation . (1,022,017) (595,362)
-------------- --------------
Net Fixed Assets ............... $ 4,729,000 $ 565,657
Machinery and equipment was $4,218,556 at April 30, 2009 as compared to
$571,319 at April 30, 2008. This increase resulted from the purchase of two
drilling rigs, one of which was associated with the settlement of all litigation
with Wind City Oil & Gas, LLC (Note 3). Vehicles was $938,624 at April 30, 2009
as compared to $248,062 at April 30, 2008. This increase resulted from the
purchase of several large trucks. At April 30, 2009 Buildings increased from
$315,835 at April 30, 2008 to $554,546 at April 30, 2009. This resulted from the
purchase of a property in Scott County, Tennessee and from the reclassification
of our office buildings in Huntsville, Tennessee. Office equipment was $49,291
at April 30, 2009 as compared to $25,804 at April 30, 2008. This increase
resulted from the purchase of several new computers. Depreciation expense for
the years ended April 30, 2009 and 2008 was $427,605 and $70,821 respectively.
F-16
(7) LONG-TERM DEBT, WARRANTS, LOAN FEES AND RESTRICTED CASH
The Company had the following debt obligations at April 30, 2009 and
April 30, 2008
April 30, April 30,
2009 2008
---------- ----------
Notes Payable - Related Parties:
Note payable to the Company's Chairman of the Board of Directors,
Deloy Miller, secured by equipment and truck titles,
interest at 10.752%, due October 18, 2008 .............................. $ - $ 80,200
---------- ----------
- 80,200
Notes Payable - Other
Note payable to American Fidelity Bank, secured by a trust deed on
property, bearing interest at prime, due in monthly payments
of $2,500, with the final payment due in August 2008 ................... - 346,430
Note payable to Jade Special Strategy, LLC, unsecured, dated March 7,
2007, bearing interest based on a sliding scale approximating
120% and due April 30, 2008 ............................................ - 110,000
Note payable to Jade Special Strategy, LLC, unsecured, dated April 17,
2007, bearing interest based on a sliding scale approximating
120% and due April 30, 2008 ............................................ - 40,000
Note payable to Jade Special Strategy, LLC, unsecured, dated August 2,
2007, bearing interest based on a sliding scale approximating
120% and due April 30, 2008 ............................................ - 65,000
Note payable to Petro Capital Securities, unsecured, dated May 24, 2007,
bearing interest at 10% and due June 30, 2008 .......................... - 35,000
Note payable to P & J Resources, Inc., unsecured, dated April 2, 2008,
bearing interest at 8% ................................................. - 50,000
Note payable to Commercial Bank, secured by a certificate of deposit,
Bearing interest at 3.75%, due December 22, 2008 ....................... 1,850,000 -
Note payable to Commercial Bank, secured by vehicle, dated March 31,
2009, bearing interest at 7.50%, due in monthly payments of
$1,376.22, with the final payment due March 31, 2013 ................... 55,786 -
Note payable to GMAC Financing, secured by vehicle, dated June 27,
2008, bearing zero interest, due in monthly payments of
$861.58, with the final payment due June 27, 2012 ...................... 53,419 -
---------- ----------
1,959,205 646,430
---------- ----------
Total Notes Payable ............................................... 1,959,205 726,630
Less current maturities on related party notes payable ............ - 80,200
Less current maturities on other notes payable .................... 1,870,732 646,430
---------- ----------
Notes Payable - Long-term ......................................... $ 88,473 $ -
========== ==========
F-17
The five-year maturities of long-term debt is as follows:
Year ended April 30,
--------------------
2010 ............. $ 1,870,732
2011 ............. 24,821
2012 ............. 25,900
2013 ............. 25,689
2014 ............. 10,338
Cash - restricted short term at April 30, 2009 consisted of a
certificate of deposit held at Commercial Bank as collateral for debt. Cash -
restricted long-term at April 30, 2009 and 2008 consisted of several
certificates of deposits pledged to the state for reclamation bonds.
(8) ASSET RETIREMENT OBLIGATION
In 2001, the Financial Accounting Standards Board approved the issuance
of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS143
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
estimated costs to capitalize a well and site remediation once a well is
abandoned. Over time, accretion of the liability is recognized as an operating
expense and the capitalized cost is depreciated over the expected useful life of
the related asset.
The changes in the Company's liability for the years ended April 30, 2008 and
2007 as follows:
Asset retirement obligation as of April 30, 2007 .. $ 29,216
Accretion expense for 2008 ........................ 16,000
--------
Asset retirement obligation as of April 30, 2008 .. 45,216
Accretion expense for 2009 ........................ 12,030
--------
Asset retirement obligation as of April 30, 2009 .. $ 57,246
(9) STOCKHOLDERS' EQUITY (DEFICIT)
On April 30, 2007 the Company engaged Cresta Capital/Consortium to
assist in the unwind of the Wind City agreement (note 3) in exchange for options
to acquire 5,000,000 shares of the Company's common stock. The options were to
be issued upon board approval of the services and were exercisable at $0.21 per
share. However, during the year ended April 30, 2009, these options were
cancelled and in June, 2008 we issued one million warrants exercisable at $1.00
per share for a period of three years to Cresta Capital/Consortium attributed as
a cost of the sale of oil and gas properties transaction. Compensation expense
for these options were valued using the Black-Scholes method and was calculated
to be $174,000 and was included in the Statement of Operations for the year
ended April 30, 2009.
On February 14, 2008 a note holder agreed to extend the notes to April
30, 2008 at an interest rate of 18% per annum, the re-pricing of 200,000
warrants from $0.33 and $0.29 to $0.01, and the issuance of an additional
100,000 shares of stock at grant-date fair value. The warrants represent loan
fees and were valued at $59,000.
F-18
In July 2008 we issued 300,000 shares for past services to our
directors valued and expensed at $99,000. These shares were valued at the July
2008 market price of such shares issued.
In May 2005 the Company entered into a $4.15 million credit agreement
which had terms that specified that the Company would prepare, and file a
Registration Statement that would cover the resale of all of the Registrable
Securities, which Registration Statement, to the extent allowable under the 1933
Act and the rules and regulations promulgated hereunder (including Rule 416),
shall state that such Registration Statement also covers such indeterminate
number of additional shares of Common Stock as may become issuable upon
conversion of or otherwise pursuant to the Notes and Warrants to prevent
dilution resulting from stock splits, stock dividends or similar transactions.
Company would agree to provide certain registration rights under the Securities
Act of 1933, as amended, and the rules and regulations thereunder, or any
similar successor statute, and applicable state securities laws. The Company is
required to issue 40,000 penalty warrants each month. The Company has not
registered the aforementioned underlying securities. The shares are not
registered and throughout the year the Company issued 480,000 penalty warrants
at an average exercise price of $1.15 per share with a five-year term valued and
expensed at $122,818 and $94,010 during the years ended April 30, 2009 and
2008, respectively.
In August 2008 we engaged a broker-dealer and member of FINRA to assist
us in raising capital by means of a private placement of securities. As initial
compensation for their services, we paid 250,000 shares of our common stock,
valued at $115,000. These shares were valued at the August 2008 market price of
such shares issued.
In September 2008 we recorded stock-based compensation expense of
$17,800 related to stock options granted.
During the fiscal year, we repurchased 2,900,000 shares of common stock
at $4,350,000, which was previously recorded as equity subject to being
repurchased as of April 30, 2008.
In October 2008 we issued 800,000 shares to employees and a consultant
as compensation, which in the aggregate were valued at $825,000 and $176,000
expensed, respectively;
Also, in October 2008 we issued 100,000 shares of our common stock to
two individuals as compensation for a finder's fee related to the introduction
of our company to a broker-dealer, and expensed at $22,000. These shares were
valued at the October 2008 market price of such shares issued.
In February 2009, a warrant holder exercised 200,000 warrant options
using a cashless exercise option which netted them 195,000 common shares.
During the year ended April 30, 2009, we issued 2,662,500 shares of
common stock to our Chief Executive Officer, Mr. Boruff, and expensed $878,625.
2,500,000 shares of this stock was issued to Mr. Boruff as a transaction fee for
the sale to Atlas America of approximately 30,000 acres of oil and gas leases
and eight drilled but not completed wells for $19,625 million on June 13, 2008.
162,500 shares of stock are to be issued to Mr. Boruff as part of his employment
agreement. During the year, Mr. Boruff was also issued 250,000 stock options
with a grant price of $0.33 which vest over a four year period.
F-19
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. 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 year ended April 30,
2008, the assumed effects from the exercise of outstanding options and warrants
would have been anti-dilutive, and, therefore only basic earnings per share is
presented.
There were no dilutive effects of the common stock equivalents for the
outstanding vested stock options and warrants for the year ended April 30, 2009
since the exercise price of such warrants and options were at or above the
market price of the Company's common stock at April 30, 2009.
(10) STOCK OPTIONS
We record share-based payments at fair value and record compensation
expense for all share-based awards granted, modified, repurchased or cancelled
after the effective date, in accord with FASB Statement 123(R), Share-Based
Payments. We record compensation expense for outstanding awards for which the
requisite service had not been rendered as of the effective date over the
remaining service period. We adopted Statement 123(R) using a modified
prospective application.
We estimated the fair value of options granted during the years ended
April 30, 2009 and 2008 on the date of grant, using the Black-Scholes pricing
model with the following assumptions:
2009 2008
-------- ------
Weighted average of expected risk-free interest
rates (Approximate 3 year Treasury Bill rate) ... 1.85% 4.50%
Expected years from vest date to exercise date ... 2.4 2.5
Expected stock volatility ........................ 293-527% 300%
Expected dividend yield .......................... 0% 0%
The Company recorded $247,425 and $0 of compensation expense, net of
related tax effects, relative to stock options for the years ended April 30,
2009 and 2008, respectively in accordance with SFAS 123R. Net loss per share
basic and diluted for this expense is $0.02 and $0.00.
The Company has adopted SFAS No. 123R, "Share Based Payments". SFAS No.
123R requires companies to expense the value of employee stock options and
similar awards and applies to all outstanding and vested stock-based awards. In
computing the impact, the fair value of each option is estimated on the date of
grant based on the Black-Scholes options-pricing model utilizing certain
assumptions for a risk free interest rate; volatility; and expected remaining
lives of the awards. The assumptions used in calculating the fair value of
share-based payment awards represent management's best estimates, but these
estimates involve inherent uncertainties and the application of management
judgment. As a result, if factors change and the Company uses different
assumptions, the Company's stock-based compensation expense could be materially
different in the future. In addition, the Company is required to estimate the
expected forfeiture rate and only recognize expense for those shares expected to
vest. In estimating the Company's forfeiture rate, the Company analyzed its
historical forfeiture rate, the remaining lives of unvested options, and the
F-20
amount of vested options as a percentage of total options outstanding. If the
Company's actual forfeiture rate is materially different from its estimate, or
if the Company reevaluates the forfeiture rate in the future, the stock-based
compensation expense could be significantly different from what we have recorded
in the current period. The impact of applying SFAS No. 123R approximated
$247,425 in additional compensation expense during the year ended April 30, 2009
and none in 2008. Such amount is included in general and administrative expenses
on the statement of operations.
The aggregate intrinsic value is calculated as the difference between
the exercise price of the underlying awards and the quoted price of our common
stock for those awards that have an exercise price currently below the closing
price. During the year ended April 30, 2009 and 2008, the aggregate intrinsic
value of stock options and warrants exercised was $46,800 and none,
respectively, determined as of the date of exercise.
A summary of the stock options and warrants as of April 30, 2009 and
2008 and changes during the periods is presented below:
2009 2008
----------------------------- -----------------------------
Number of Weighted Number of Weighted
Options Average Options Average
and Warrants Exercise Price and Warrants Exercise Price
------------ -------------- ------------ --------------
Balance at beginning of year ..... 7,535,000 $0.40 7,055,000 $0.37
Granted .......................... 1,855,000 0.91 480,000 1.15
Exercised ........................ 200,000 0.01
Expired ..........................
Cancelled ........................ 5,100,000 0.23
--------- ---------
Balance at end of year ........... 4,090,000 0.88 7,535,000 0.40
Options exercisable at April 30 .. 3,840,000 $0.91 2,535,000 $0.78
========= =========
The following table summarizes information concerning stock options and warrants
outstanding and exercisable at April 30, 2009:
Options and Warrants
Options and Warrants Outstanding Exercisable
----------------------------------------------------- ----------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Number Contractual Exercise Number Exercise
Exercise Price Outstanding Life Price Exercisable Price
-------------- ----------- ----------- -------- ----------- --------
$ 0.33 to 0.44 375,000 7.0 $ 0.37 125,000 $ 0.44
0.50 1,000,000 1.0 0.50 1,000,000 0.50
0.80 to 0.86 75,000 0.5 0.82 75,000 0.82
1.00 to 1.15 2,640,000 2.9 1.09 2,640,000 1.09
----------- ----------
4,090,000 2.7 0.88 3,840,000 0.91
=========== ==========
All options and warrants were issued at the fair market of common stock on the
date of grant.
F-21
(11) INCOME TAX
At April 30, 2009, we had federal net operating loss carryforwards amounting to
approximately $1,688,821, which expire through 2029. We have recorded a full
valuation allowance against deferred tax assets (approximately $574,199 using a
tax rate of 34%) resulting from the net operating loss carryforwards, because we
do not consider the realization of such deferred tax assets to be more likely
than not.
A reconciliation of our net operating loss carryforwards (NOL) is as follows:
Federal State
----------- -----------
NOL at April 30, 2007 ...................... $(7,974,494) $(7,576,079)
Loss for the year ended April 30, 2008 ..... (2,002,029) (2,002,299)
----------- -----------
NOL at April 30, 2008 ...................... (9,976,523) (9,578,378)
Adjusted Pre-tax income at April 30, 2009 .. 9,591,444 9,591,444
----------- -----------
Taxable income (loss) ...................... (385,079) 13,066
Income tax expense and deferred income tax . - 778
Tax depreciation in excess of book
depreciation ............................... (1,303,742) (901,358)
----------- -----------
NOL at April 30, 2009 ...................... (1,688,821) (888,292)
=========== ===========
Federal income tax at 34% and
state tax benefit net of federal benefit .. $ (574,199) $ (38,108)
=========== ===========
The difference between the recorded income tax benefit and the computed tax
benefit using a 34% federal tax rate is:
April 30, 2009 April 30, 2008
-------------------------- --------------------------
Federal State Federal State
----------- ----------- ----------- -----------
Pre-tax book income (loss) .... $ 8,357,151 $ 8,357,151 $(2,435,796) $(2,435,796)
Non-timing Schedule M items
Stock for services .......... 1,153,625 1,153,625 375,321 375,321
Other non-timing items ...... 80,668 80,668 58,426 58,426
----------- ----------- ----------- -----------
1,234,293 1,234,293 433,747 433,747
----------- ----------- ----------- -----------
Pre-tax net income(loss) after
Non-timing Schedule M's ..... 9,591,444 9,591,444 (2,002,049) (2,002,049)
Federal tax (benefit)at 34% and
State tax (benefit) at 6.5% 3,261,091 623,444 (680,696) (130,133)
Income tax benefit from
NOL carryforwards ........... (3,261,091) (622,666) - -
Valuation reserve ............. - - 680,696 130,133
----------- ----------- ----------- -----------
Deferred tax .................. - 778 - -
=========== =========== =========== ===========
F-22
Income tax benefits from net operating loss carryforwards are as follows:
April 30,
--------------------------
2009 2008
----------- -----------
Expected income tax (benefit) ..... $ (574,197) $(3,392,021)
State taxes, net of federal benefit (38,108) (410,912)
Valuation allowance ............... 612,305 3,802,933
----------- -----------
Deferred tax asset ................ $ - $ -
=========== ===========
(12) COMMITMENTS
On August 6, 2008 the Board of Directors employed Scott M. Boruff as
CEO of the Company. The employment contract, as amended, provided for the
following compensation:
o Base salary of $250,000 per annum, with provision for cost-of-living
increases.
o Options to purchase 250,000 shares of the Company's common stock at
an exercise price per share of $0.33, with vesting in equal annual
installments over a period of four years.
o A restricted stock grant of 250,000 shares of common stock, with
vesting in equal annual installments over a period of four years.
o Incentive Compensation - For each year of the employment term, (i)
cash up to 100% of base salary and (ii) up to 100,000 shares of
restricted common stock, in both instances based upon, and subject
to, two performance benchmarks, gross revenue and EBITDA. One half
of each element of incentive compensation is earned if the gross
revenue benchmark is achieved, and the other half of each element is
earned if the EBITDA benchmark is achieved.
Based on this employment agreement, bonuses, net of certain expenses,
were accrued for $186,452 on April 30, 2009. Also as part of this agreement, we
will issue 100,000 shares of restricted common stock and expense $53,625 as
compensation expense in 2009.
In August 2008 we engaged a broker-dealer and member of FINRA to assist
us in raising capital by means of a private placement of securities. As initial
compensation for their services, we paid a $25,000 retainer, and issued 250,000
shares of our common stock, valued at $115,000 and agreed to pay a monthly
consulting fee of $5,000. Upon the successful completion of the private offering
we will be obligated to pay the firm certain cash compensation and issue them up
to an additional 150,000 shares of our common stock in amounts to be determined
based upon the gross proceeds received by us from the financing.
The Company leases office space on a month-to-month basis. The rental
expense incurred for fiscal 2009 and 2008 was $8,027 and $0, respectively.
F-23
(13) SFAS NO. 69 SUPPLEMENTAL DISCLOSURES (UNAUDITED)
a. Capitalized Costs Relating to Oil and Gas Producing Activities at April 30,
2009 and 2008 are as follows:
2009 2008
----------- -----------
Proved oil and gas properties and related lease
equipment
Developed ..................................... $ 2,227,191 $ 2,736,509
Non-developed ................................. - -
2,227,191 2,736,509
Accumulated depletion ............................ (1,415,271) (1,191,931)
----------- -----------
Net Capitalized Costs ............................ $ 811,920 $ 1,544,578
=========== ===========
b. Costs Incurred in Oil and Gas Property Acquisition, Exploration, and
Development Activities:
2009 2008
--------- ---------
Acquisition of Properties Proved and Unproved ........ $ - $ -
Exploration Costs .................................... - -
Development Costs .................................... - -
--------- ---------
Total ................................................ $ - $ -
========= =========
c. Results of Operations for Producing Activities:
2009 2008
--------- ---------
Production revenues .................................. $ 640,094 $ 566,478
Production costs ..................................... (240,389) (62,213)
Depreciation and amortization ........................ (221,465) (157,153)
--------- ---------
Results of operations for producing activities
(excluding corporate overhead and interest costs) .... $ 178,240 $ 347,112
========= =========
d. 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.
F-24
Oil (Bbls) Gas (Mcf)
---------- ----------
Proved reserves
Balance, April 30, 2007 ................................. 61,404 701,810
Discoveries and extensions ........................... - -
Revisions of previous estimates ...................... 17,993 475,894
Return of proved undeveloped properties to the Company - 1,037,857
Sale of minerals in place ............................ - (324,195)
Production ........................................... (4,984) (39,508)
---------- ----------
Balance, April 30, 2008 ................................ 74,413 1,851,858
Discoveries and extensions ........................... - -
Revisions of previous estimates ...................... (16,390) 58,892
Production ........................................... (4,580) (47,213)
---------- ----------
Balance, April 30, 2009 ................................. 53,443 1,863,537
========== ==========
Proved developed producing reserves at April 30, 2009 ...... 42,657 562,600
========== ==========
Proved developed producing reserves at April 30, 2008 ...... 63,068 510,825
========== ==========
The return of the proved undeveloped properties resulted from the
return of the leases from Wind Mill to the Company due to settlement of all
litigation.
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 Lee Keeling and Associates, Inc. for
the years ended April 30, 2009 and April 30, 2008. Although wells have been
drilled and completed in each of these 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 as soon as possible.
However, such timing as well as the actual financing arrangements that will be
secured by the Company is uncertain at this time.
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, 2009 and 2008. Estimated future cash flows were
based on independent reserves evaluation from Lee Keeling and Associates, Inc.
for the years ended April 30, 2009 and April 30, 2008. Because the standardized
measure of future net cash flows was prepared using the prevailing economic
conditions existing at April 30, 2009 and 2008, 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, 2008 and 2007 were $40.35 and
$103.31 per barrel of oil and $3.19 and $9.36 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.
F-25
Income tax expense is computed based on applying the appropriate
statutory tax rate to the excess of future cash inflows less future production
and development costs over the current tax basis of the properties involved.
The future net revenue information assumes no escalation of costs or
prices, except for gas sales made under terms of contracts which include fixed
and determinable escalation. Future costs and prices could significantly vary
from current amounts and, accordingly, revisions in the future could be
significant.
Standardized measures of discounted future net cash flows at April 30,
2009 and 2008 are as follows:
2009 2008
------------ ------------
Future cash flows .............................. $ 7,981,612 $ 25,456,619
Future production costs and taxes .............. (1,812,885) (3,597,397)
Future development costs ....................... (1,185,201) (1,471,400)
Future income tax expense ...................... (1,544,893) (6,320,225)
------------ ------------
Future cash flows .............................. 3,438,633 14,067,597
Discount at 10% for timing of cash flows ....... (1,903,824) (7,323,458)
------------ ------------
Discounted future net cash flows from proved
reserves ...................................... $ 1,534,809 $ 6,744,139
============ ============
Of the Company's total proved reserves as of April 30, 2009 and 2008,
approximately 46% and 83%, respectively, were classified as proved developed
producing, 7% and 17%, respectively, were classified as proved developed
non-producing and 47% and 0%, 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, 2009 and
2008.
April 30,
----------------------------
2009 2008
------------ ------------
Balance, beginning of year ..................... $ 6,744,139 $ 1,999,640
Sales, Net of production costs and taxes ....... (399,705) (504,265)
Changes in prices and production costs ......... (2,775,928) 2,134,824
Revisions of quantity estimates and return of
proved undeveloped properties ................. (1,338,495) 6,853,630
Sale of minerals in place ...................... - (714,788)
Development costs incurred ..................... - -
Net changes in income taxes .................... (695,202) (3,024,902)
------------ ------------
Balances, end of year .......................... $ 1,534,809 $ 6,744,139
============ ============
Among "revisions of quantity estimates", the Company has accounted for
the effects of changed economic circumstances, including the effects of the
change in the Company's relationship with Wind City, which was the subject of
final arbitration in March of 2008. The resolution of the Wind City dispute
resulted in the reclassification of several proved undeveloped properties from
the Company's "Investment in Joint Venture" on the April 2007 Balance Sheet,
including discounted reserves of approximately $4,648.000.
F-26
(14) LITIGATION
CNX Gas Company, LLC (CNX) commenced litigation in the Chancery Court
of Campbell County, State of Tennessee on June 11, 2008 (CNX Gas Company, LLC
vs. Miller Petroleum Inc., Civil Action No. 08-071) to enjoin the Registrant
from assigning or conveying certain leases described in the Letter of Intent
signed by CNX and the Company on May 30, 2008 (the "Letter of Intent"); to
compel the Company to specifically perform the assignments as described in the
Letter of Intent; and for damages. A Notice of Lien Lis Pendens was issued June
11, 2008. The Registrant moved for entry of summary judgment dismissing the
claims asserted against it by CNX and on January 30, 2009 the court found that
the claims of CNX had no merit. The court granted the Registrant's motion and
dismissed all claims asserted by CNX in that action. CNX has appealed the
ruling.
On May 20, 2009 Gunsight Holdings, LLC, a Florida limited liability
company, filed a complaint in the United States District Court for the Eastern
District of Tennessee, Northern Division, that surrounds certain rights related
to approximately 6,800 acres in Scott County, Tennessee. The Plaintiff is
alleging that Miller Petroleum has failed or refused to pay royalties due to the
Plaintiff's predecessors and have breached the implied duty of further
exploration by failing to drill required wells, failing to reasonably develop or
explore the property, failing to maintain an active interest in further
development of the property and otherwise failing to act as a prudent operator
of the property thereby causing damages to the Plaintiff exceeding $75,000. The
Plaintiff is seeking a declaratory judgment of its allegations, removal of
Miller Petroleum from the property, a full accounting of activities related to
the property and all monies received from those activities, damages and costs of
action. We have filed an answer denying the various claims and asserting
affirmative defenses including that there has been continuous production from
the subject lease. We intend to vigorously defend this action.
(15) SUBSEQUENT EVENTS
On June 8, 2009 Miller Petroleum, Inc. acquired certain assets from
Ky-Tenn Oil, Inc., a Kentucky corporation ("KTO"), an unrelated third party,
including KTO's undivided interest in approximately 170 oil and gas wells in
Morgan, Scott and Fentress counties Tennessee, together with all property,
fixtures and improvements, leasehold interest and contract rights related to
these wells Assets purchased included oil well equipment such as pump jacks,
electric and gas motors and 100 bbl and 210 bbl oil tanks; gas well equipment
such as swedges, meter runs and meters and separators; and other equipment such
as compressors, motors, a workover rig, a wench truck, a diesel truck, a lowboy
and various other vehicles. In addition we received an undivided interest in
approximately 35,325 acres of oil and gas leases in Scott and Morgan counties,
Tennessee. We also received interest in an operating agreement with the Tenn.
State Energy Development Partnership, interest in a gas gathering pipeline
system and other rights related to these assets, including royalty and working
interests, licenses and permits and similar incidental rights. We issued one
million shares of our stock for KTO's assets, valued at $320,000. We granted the
seller piggy-back registration rights covering these shares. The shares were
issued in a private transaction exempt from registration under the Securities
Act of 1933 in reliance on an exemption provided by Section 4(2) of the act. On
June 12, 2009 we issued a press release announcing the closing of this
transaction. The Company is currently pursuing an appraisal of KTO's assets and
reserves and determining any contingent liabilities.
F-27
On June 18, 2009 Miller Petroleum, Inc. acquired 100% of the stock of
East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of
the membership interests in East Tennessee Consultants II, LLC, a Tennessee
limited liability company ("LLC") from the owners of these entities. As
consideration for these companies we issued the sellers, who were unrelated
third parties, one million shares of our common stock valued at $250,000. We
granted the sellers registration rights covering these shares. The shares were
issued in a private transaction exempt from registration under the Securities
Act of 1933 in reliance on an exemption provided by Section 4(2) of the act. ETC
was formed in 1983 to provide oil and gas well operating services and it
represented various working interest owners and the LLC was formed in 1996.
Following the closing, it is anticipated that these subsidiaries will operate
the wells they own as well as the recently purchased wells from KY-Tenn Oil,
Inc. It is also anticipated that the old wells will be reworked and that new
wells will be drilled from the extensive acreage now owned by us. The
Chattanooga Shale, which is present in a majority of the wells acquired, is a
candidate for stimulation. Completion and reworking of existing oil zones should
add to reserves at a relatively inexpensive price.
Under the terms of the stock purchase agreement, the sellers agreed not
to engage in oil and gas operations for a period of three years following the
closing date. We also agreed that each of the sellers, Messrs. Eugene D.
Lockyear, Douglas G. Melton and Jerry G. Southwood, would continue their
employment with the acquired companies for at least three years from the closing
date of the transaction at their same compensation and benefit levels to which
they were entitled in May 2009. In addition, as described later in this report,
Mr. Lockyear was appointed Vice President of Operations of our company. We also
agreed that if any or all of the sellers incur any income tax liability as a
result of the receipt of the above shares as consideration for the stock
purchase, we agreed to pay a bonus to such seller equal to the amount of his tax
liability.
Following the closing of the acquisition, Mr. Eugene D. Lockyear, one
of the sellers, was appointed our Vice President of Operations. We have agreed
to retain him in this position for at least three years from closing. It is
anticipated that Mr. Lockyear will provide his geologic expertise which has been
developed from over 36 years of working in the oil and gas industry and he will
be responsible for supervision necessary to recomplete and rework the large
inventory of wells now owned by us. In addition, Mr. Lockyear will oversee water
plant projects, gas repressurization, gas storage, among others techniques to
extract oil from older wells. As compensation for his services, Mr. Lockyear
will receive an annualized base salary of $102,000 as well as customary
benefits. This compensation level is identical to the compensation he was
previously paid. From 1983 to 2009, Mr. Lockyear, 63, has been the President of
ETC and a Partner in LLC since its formation in 1996. He holds a B.A. in Geology
from Vanderbilt University and a M.S. in Geology and related work in Engineering
also from Vanderbilt University. Mr. Lockyear is a Registered Professional
Geologist - State of Tennessee and a former Registered Professional
Environmentalist - State of Tennessee as well as a member of Phi Beta Kappa. On
June 24, 2009 we issued a press release announcing the closing of this
transaction. The Company is currently conducting an evaluation of the fair value
of the assets and liabilities acquired in these acquisitions under the
accounting guidelines of SFAS 141R.
On June 1, 2009 we sold 225,000 shares of our common stock to Empire
Securities, Corp DBPRP for $0.34 per share. Also on June 1, 2009 we sold 125,000
shares of our common stock to The Rodriguez Family for $0.34 per share. Both
sales involve issuance of our shares to sophisticated investors who had access
to select information concerning the company, accordingly, both issuances were
exempt under Section 4(2) of the Securities Act of 1933.
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