UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-KSB
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF
1934
For The Fiscal Year Ended June 30, 2006
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF SECURITIES EXCHANGE
ACT OF 1934
For the transition period _________ to _________
Commission File Number: 0-27862
EVOLUTION PETROLUEM CORPORATION
(Exact name of registrant as specified in charter)
Nevada 41-1781991
(State of incorporation) (I.R.S. employer identification number)
820 Gessner, Suite 1340, Houston, Texas 77024
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code: (713) 935-0122
Securities registered pursuant to Section 12(b) of the Exchange Act:
Common Stock, $.001 Par Value
(Title of class and shares outstanding)
Securities registered pursuant to Section 12(g) of the Exchange Act:
None.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-B is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB.
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 |_|
Issuer's revenues for its most recent fiscal year: $2,861,414
As of September 1, 2006, the aggregate market value of common stock held by
non-affiliates of the registrant was approximately $37 million, assuming solely
for purposes of this calculation that all directors and executive officers of
the registrant and all stockholders beneficially owning more than 10% of the
registrant's common stock are "affiliates." This determination of affiliate
status is not necessarily a conclusive determination for other purposes.
The number of shares of common stock outstanding on September 1, 2006 was
26,651,997 shares.
DOCUMENTS INCORPORATED BY REFERENCE into Part III hereof Portions of the Proxy
Statement to be filed with the Commission in connection with the Company's 2006
Annual Meeting.
Transitional Small Business Format (Check One): Yes |_| No |X|
EVOLUTION PETROLEUM
CORPORATION AND SUBSIDIARIES
2006 ANNUAL REPORT ON 10-KSB
TABLE OF CONTENTS
Page
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PART I
ITEM 1. Business ..................................................... 4
ITEM 1A. Risk Factors ................................................. 7
ITEM 2. Properties ................................................... 12
ITEM 3. Legal Proceedings ............................................ 15
ITEM 4. Submission of Matters to a Vote of Security Holders .......... 16
PART II
ITEM 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issue Purchases of Equity Securities ........... 16
ITEM 6. Management's Discussion and Analysis of Financial Condition
and Results of Operations .................................. 17
ITEM 7. Financial Statements and Supplementary Data .................. 21
ITEM 8. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure ................................... 40
ITEM 8A. Controls and Procedures ...................................... 40
ITEM 8B. Other information ............................................ 40
PART III
ITEM 9. Directors and Executive Officers of the Registrant ........... 40
ITEM 10. Executive Compensation ....................................... 40
ITEM 11. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters ............................ 40
ITEM 12. Certain Relationships and Related Transactions ............... 41
ITEM 13. Exhibits ..................................................... 41
ITEM 14. Principal Accountant Fees and Services ...................... 42
SIGNATURES
Glossary of Selected Petroleum Terms
The following abbreviations and definitions are terms commonly used in the oil
and natural gas industry and throughout this Form 10-KSB:
"BBL." A standard measure of volume for crude oil and liquid petroleum products;
one barrel equals 42 U.S. gallons.
"BCF." Billion Cubic Feet of natural gas at standard temperature and pressure.
"BOE." Barrels of oil equivalent. BOE is calculated by converting 6 MCF of
natural gas to 1 BBL of oil.
"BTU" or "British Thermal Unit." The standard unit of measure of energy equal to
the amount of heat required to raise the temperature of one pound of water 1
degree Fahrenheit. One Bbl of crude is typically 5.8 MMBTU, and one standard Mcf
is typically 1 MMBTU.
"CO2." Carbon dioxide, a gas that can be found in naturally occurring
reservoirs, typically associated with ancient volcanoes, and also is a major
byproduct from manufacturing and power production, also utilized in enhanced oil
recovery through injection into an oil reservoir.
"EOR." Enhanced Oil Recovery projects involve injection of heat, miscible or
immiscible gas, or chemicals into oil reservoirs, typically following full
primary and secondary waterflood recovery efforts, in order to gain incremental
recovery of oil from the reservoir.
"field." An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geologic structural feature and/or
stratigraphic feature.
"farmout." Sale or transfer of all or part of the operating rights from the
working interest owner (the assignor or farmout party), to an assignee (the
farmin party) who assumes all or some of the burden of development, in return
for an interest in the property. The assignor may retain an overriding royalty
or any other type of interest. For Federal tax purposes, a farmout may be
structured as a sale or lease, depending on the specific rights and carved out
interests retained by the assignor.
"gross acres or gross wells." The total acres or number of wells participated
in, regardless of the amount of working interest owned.
"MBOE." One thousand barrels of oil equivalent.
"MCF." One thousand cubic feet of natural gas at standard conditions, being
approximately sea level pressure and 60 degrees Fahrenheit temperature. Standard
pressure in the state of Louisiana is deemed to be 15.025 psi by regulation, but
varies in other states.
"MMBTU." One million British thermal units (BTU's).
"MMCF." One million cubic feet of natural gas at standard temperature and
pressure.
"net acres or net wells." The sum of the fractional working interests owned in
gross acres or gross wells.
"NGL." Natural gas liquids, being the combination of ethane, propane, butane and
natural gasoline's that can be removed from natural gas through processing,
typically through refrigeration plants that utilize low temperatures, or through
J-T plants that utilize compression, temperature reduction and expansion to a
lower pressure.
"NYMEX." New York Mercantile Exchange.
"overriding royalty." A royalty interest that is created out of the operating or
working interest. Unlike a royalty interest, an overriding royalty interest
terminates with the operating interest from which it was created or carved out
of. See "royalty interest".
"permeability." The measure of ease with which petroleum can move through a
reservoir.
"porosity" (of sand or sandstone). The relative volume of the pore space (or
open area) compared to the total bulk volume of the reservoir.
"proved developed reserves." Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as "proved developed reserves"
only after testing by pilot project or after the operation of an installed
program has confirmed through production responses that increased recovery will
be achieved.
"proved reserves." 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.
"proved undeveloped reserves." Reserves that are expected to be recovered from
new wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. 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
can be claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Proved
undeveloped reserves may not include estimates attributable to any acreage for
which an application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
"psi," or pounds per square inch, a measure of pressure. Pressure is typically
measured as "psig", or the pressure in excess of standard atmospheric pressure.
"present value" or "PV-10." When used with respect to oil and gas reserves,
present value means the estimated future net revenues computed by applying
current prices of oil and gas reserves (with consideration of price changes only
to the extent provided by contractual arrangements) to estimated future
production of proved oil and gas reserves as of the date of the latest balance
sheet presented, less estimated future expenditures (based on current costs to
be incurred in developing and producing the proved reserves computed using a
discount factor of ten percent and assuming continuation of existing economic
conditions. PV-10 means a present value, discounted at 10% per annum.
"productive well." A well that is producing oil or gas or that is capable of
production.
"royalty" or "royalty interest." The mineral owner's share of oil or gas
production (typically 1/8, 1/6 or 1/4), free of costs, but subject to severance
taxes unless the lessor is a government. In certain circumstances, the royalty
owner bears a proportionate share of the costs of making the natural gas
saleable, such as processing, compression and gathering. A royalty interest that
is coterminous with an operating or working interest is an "overriding royalty"
interest.
"shut-in well." A well that is not on production, but has not yet been plugged
and abandoned. Wells may be shut-in in anticipation of future utility as a
producing well, plugging and abandonment or other use.
"standardized measure." The standardized measure is an estimate of future net
reserves from a property, and is calculated in the same exact same fashion as a
PV-10 value, except that the projected revenue stream is adjusted to account for
the estimated amount of federal income tax that must be paid.
"working interest." The interest in the oil and gas in place which is burdened
with the cost of development and operation of the property. Also called the
operating interest.
"workover." A remedial operation on a completed well to restore, maintain or
improve the well's production.
PART I
Item 1. Description of Business
The terms "we," "us," "our," "our Company" and "EPM" refer to Evolution
Petroleum Corporation, a Nevada corporation formerly known as Natural Gas
Systems, Inc., and, unless the context indicates otherwise, also includes our
wholly-owned subsidiaries. "Old NGS" refers to Natural Gas Systems, Inc., a
private Delaware corporation formed in 2003.
General
Our petroleum operations began in September of 2003. We acquire established
crude oil and natural gas resources and exploit them through the application of
conventional and specialized technology, with the objective of increasing
production, ultimate recoveries, or both. We currently own oil and gas
properties in four crude oil and natural gas producing fields in the State of
Louisiana, all of which are referred to as our Delhi Field or our Tullos Field
(Area).
Our team is broadly experienced in oil and gas operations, development,
acquisitions and financing. We follow a strategy of outsourcing most of our
property accounting, human resources, administrative and non-core functions.
Our principal executive offices are located at 820 Gessner, Suite 1340, Houston,
Texas 77024, and our telephone number is (713) 935-0122. We maintain a website
at www.EvolutionPetroleum.com, but information contained on our website does not
constitute part of this document.
Our stock is traded on the American Stock Exchange under the ticker symbol EPM.
Prior to July 17, 2006, our stock was quoted on the OTC Bulletin Board under the
symbol NGSY.OB. Prior to May 26, 2004, our stock was quoted on the OTC Bulletin
Board under the symbol RLYI.OB.
Corporate History of Reverse Merger
Reality Interactive, Inc. ("Reality"), a Nevada corporation that traded on the
OTC Bulletin Board under the symbol RLYI.OB and the predecessor of Natural Gas
Systems, Inc., now Evolution Petroleum Corporation, was incorporated on May 24,
1994, for the purpose of developing technology-based knowledge solutions for the
industrial marketplace. On April 30, 1999, Reality ceased business operations,
sold substantially all of its assets and terminated all of its employees.
Subsequent to ceasing operations, Reality explored other potential business
opportunities to acquire or merge with another entity, while continuing to file
reports with the SEC.
On May 26, 2004, Natural Gas Systems, Inc., a privately owned Delaware
corporation formed in September 2003 ("Old NGS"), was merged into a wholly owned
subsidiary of Reality. Reality was thereafter renamed Natural Gas Systems, Inc.
and adopted a June 30 fiscal year end. As part of the merger, the officers and
directors of Reality resigned, the officers and directors of Old NGS became the
officers and directors of our Company, and the crude oil and natural gas
business of Old NGS became that of our Company. Concurrently with the listing of
our shares on the AMEX during July, 2006, Natural Gas Systems was renamed
Evolution Petroleum Corporation to avoid confusion with similar names traded on
the AMEX and to better reflect our business model.
All regulatory filings and other historical information prior to May 26, 2004
that applied to Reality continue to apply to us after the merger.
Business Activities
We are focused on an overall strategy of acquiring controlling working interests
in oil and gas resources within established fields and redeveloping those fields
through the application of capital and technology to convert the oil and gas
resources into profitable producing reserves. Within this overall strategy, we
have established three specific business initiatives:
o Enhanced oil recovery (EOR) projects in mature oil reservoirs;
o Redevelopment of mature oil and gas fields using modern and/or
proprietary technology; and
o Development of low permeability resource plays using modern
stimulation and completion technologies, including horizontal
drilling.
Our strategy is designed to generate scalable development opportunities at
relatively shallow depths, exhibiting relatively low completion risk, generally
longer and more predictable production lives, less expenditures on
infrastructure and lower operational risks. We believe that the benefits of this
approach include:
o Reduced exposure to the risk of whether resources are present;
o Reduced capital expenditures per net BOE for infrastructure, such as
roads, water handling facilities and pipelines;
o Large inventory of development opportunities, which provides a more
predictable future stream of drilling activity and production, as
well as potentially reducing risks from short-term oil and gas price
volatility;
o Reduced operational risks and costs associated with lower pressures
and lower temperatures; and
o Control of operations, development timing and technology selection.
We purchased our first oil and gas property in September 2003 through the
acquisition of all of the active working interests and the corresponding 80% net
revenue interest in property and wells in the Delhi Field, located in
northeastern Louisiana.This acquisition included the purchase of six producing
wells, one salt water disposal well and 37 shut-in wells with minimal crude oil
production per day and no natural gas sales. The Delhi Field encompasses
approximately 13,636 acres, and the primary Paluxy and Tuscaloosa producing
reservoirs in the field were unitized in the 1950's as the Delhi Holt Bryant
Unit. Our acquisition included the Delhi Holt Bryant Unit and certain other
depths, excluding a separate reservoir contained in the Mengel Unit in the Delhi
Field. We conducted various development activities in the Delhi Field since the
acquisition. Between January and July 2006, we also acquired royalty and
overriding royalty interests in the Delhi Holt Bryant Unit aggregating ~7.4%.
In June 2006, we conveyed a farmout to Denbury Resources that included all of
our working interests in the Delhi Holt Bryant Unit and 75% of our working
interests in other depths of the Delhi Field, for which we received
approximately $50 million in cash, a 25% back-in working interest in the Delhi
Holt Bryant Unit and a commitment by Denbury Resources to install a CO2 EOR
project in the Delhi Holt Bryant Unit (the "Delhi Farmout").
For a more detailed discussion, please see "Item 2. - Properties."
In September 2004, we completed the acquisition of a 100% working interest and
an approximate 78% average net revenue interest in producing crude oil wells,
equipment and improvements located in the Tullos Urania, Colgrade and Crossroads
Fields in LaSalle and Winn Parishes, Louisiana, which we refer to collectively
as the "Tullos Field Area". The purchased assets included approximately 124 oil
wells, 9 water disposal wells, and all associated infrastructure, including
water disposal facilities, crude oil and water tanks, flow lines and pumping
units. The purchase also included 15 wells without leases. We subsequently
acquired new leases for ten of these wells.
In early February 2005, we completed the acquisition of a 100% working interest
and an approximate 79% average net revenue interest in similar properties in our
Tullos Field Area. The purchased assets included approximately 121 oil wells, 8
salt water disposal wells and associated infrastructure and equipment.
Since the acquisitions of the Tullos Field assets, we have conducted various
development activities, primarily to improve operations, bring operations up to
industry standards, and increase produced water disposal capacity.
Markets and Customers
To date all of our crude oil has been produced and sold from our Delhi Field and
Tullos Field Areas in Louisiana. All of our natural gas has been produced and
sold from our Delhi Field in Louisiana.
Marketing of crude oil and natural gas production is influenced by many factors
that are beyond our control, the exact effect of which is difficult to predict.
These factors include changes in supply and demand, market prices, government
regulation and actions of major foreign producers.
Over the past 20 years, crude oil price fluctuations have been extremely
volatile, with crude oil prices varying from less than $10.00 to in excess of
$75 per barrel. Worldwide factors such as geopolitical, macroeconomic, supply
and demand, refining capacity, petrochemical production and derivatives trading,
among others, influence prices for crude oil. Local factors also influence
prices for crude oil and include quality differences, regulation and
transportation issues unique to certain producing regions and reservoirs.
Also over the past 20 years, domestic natural gas prices have also been
volatile, ranging from $1 to $15 per MMBTU. The spot market for natural gas,
changes in supply and demand, derivatives trading, pipeline availability, BTU
content of the natural gas and weather patterns, among others, cause natural gas
prices to be subject to significant fluctuations. Due to the practical
difficulties in transporting natural gas, local factors tend to influence
product prices more for natural gas than for crude oil.
In the U.S. market where we operate, crude oil and gas liquids are readily
transportable and marketable. Since March 2005, we have sold all of our crude
oil production to Plains Marketing LP, a crude oil purchaser, at competitive
field prices. A portion of our crude oil production is subject to fixed price
contracts (excluding basis risk) with Plains Marketing as described in the
"Commodity Contracts" section below. We believe that other crude oil purchasers
are readily available.
We have sold all of our natural gas liquids to Dufour Petroleum, L.P., a
subsidiary of Enbridge Energy Partners, at a market competitive price based on
an index price of liquid components, less a charge of $0.175 per gallon for
transportation and fractionation.
There is only one natural gas pipeline sales point readily available to our gas
treating facility serving our Delhi natural gas production, which reduces our
leverage in negotiating a more favorable transportation charge and sales price.
The current natural gas sales line is also a delivery line to customers,
downstream of the pipeline's processing and treating facilities, thus making the
pipeline very sensitive to the quality of natural gas sold into our point of
interconnection.
Since March 2005, we have sold all of our natural gas through Texla Energy
Management, Inc., a natural gas marketer/aggregator, although we believe that
other natural gas marketers are readily available. A portion of our natural gas
volumes has been sold under commodity contracts, as discussed in the section
below. The remaining natural gas volumes are priced on either a monthly average
index or a daily cash price as established at the Henry Hub market, less a
$0.215 per MMBTU deduction for the market differential between Henry Hub and our
sales point. All gas sold from the Delhi Field is charged $0.0854 per MMBTU by
Gulf South, the pipeline into which we deliver our gas, for transportation.
These costs, along with the costs for natural gas processing and transportation
prior to delivery to the sales point, are deducted from the natural gas sales
receipts before calculation and distribution of royalties. Title to the natural
gas passes to the purchaser at the metered interconnection to the transportation
pipeline, where the Index price is reduced by the Gulf South transportation
charge.
COMMODITY CONTRACTS
In compliance with the loan agreement we entered into with Prospect Energy in
February 2005, we executed three commodity contracts for approximately 50% of
the production volumes that our outside petroleum engineers estimated for our
proved developed producing reserves on a rolling two year basis. Although we
paid off the Prospect loan in May 2006, two of these contracts continue to
extend through February 2007, as described below.
The first commodity contract, with Plains Marketing L.P., covered the sale of 70
barrels of crude oil per day for a 12 month period from March 2005 through
February 2006. The fixed sale price was based upon the NYMEX WTI (West Texas
Intermediate) crude oil price and monthly settlements, wherein Plains Marketing
delivered a fixed price of $48.35 per barrel to us before adjustment for the
basis differential between the NYMEX price and the contract price. This contract
was extended for the months of March 2006 through May 2006 at a fixed price of
$52.55 per barrel of oil for 70 barrels of oil per day, extended for the three
months of June 2006 through August 2006 at a fixed price of $63.45 per barrel of
oil for 90 barrels of oil per day, and extended for the six months of September
2006 through February 2007 at a fixed price of $69.30 per barrel of oil for 90
barrels of oil per day. Plains Marketing L.P. is our crude oil purchaser and
picks up our production in the field using their trucks.
The second commodity contract is between us and Wells Fargo Bank, N.A. We
purchased a series of price floors, set at a NYMEX WTI price of $38.00 per
barrel of crude oil, based upon the arithmetic average of the daily settlement
price for the first nearby month of NYMEX WTI futures, for 2,000 barrels of
crude oil per month for March 2006 through February 2007. The cost of the hedge
was $3.00 per barrel of oil.
Our third commodity contract was with Texla Energy Management, Inc., whereby we
sold 100 MMBTU per day at a fixed price of $6.21 per MMBTU over a fifteen month
period beginning March 1, 2005 and ending May 31, 2006.The fixed price was
before deduction of a $0.0854 per MMBTU fixed gathering charge by Gulf South,
the owner of the natural gas pipeline into which we deliver our natural gas from
the Delhi Field. This fixed price included the basis differential from NYMEX to
our sales point on the Gulf South pipeline.
COMPETITION
Our competitors include major integrated crude oil and natural gas companies and
numerous independent crude oil and natural gas companies, individuals and
drilling and income programs. Many of our competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than us. Competitors are national, regional or local
in scope and compete on the basis of financial resources, technical prowess or
local knowledge. The principal competitive factors in our industry are the
ability to efficiently conduct operations, achieve technological advantages,
identify and acquire suitable properties and obtain affordable capital.
GOVERNMENT REGULATION
Crude oil and natural gas drilling and production operations are regulated by
various federal, state and local agencies. These agencies issue binding rules
and regulations that carry penalties, often substantial, for failure to comply.
These regulations and rules require monthly, semiannual and annual reports on
production amounts and water disposal amounts, and govern most aspects of
operations, drilling and abandonment, as well as crude oil spills. We anticipate
the aggregate burden of federal, state and local regulation will continue to
increase, including in the area of rapidly changing environmental laws and
regulations. We also believe that our present operations substantially comply
with applicable regulations. To date, such regulations have not had a material
effect on our operations, or the costs thereof. We do not believe that capital
expenditures related to environmental control facilities or other regulatory
matters will be material in the near term (Please see Item 3. Legal
Proceedings). We cannot predict what subsequent legislation or regulations may
be enacted or what effect it will have on our operations or business.
RISK FACTORS
Risks related to the Company
FORWARD LOOKING RESULTS WILL CHANGE
Due to the farmout we completed on June 12, 2006 with Denbury Onshore LLC (the
"Delhi Farmout"), our future development initiatives in the Delhi Field are
expected to be replaced with a CO2 enhanced oil recovery ("CO2-EOR") project
offering much greater potential, which Denbury has undertaken to fund and
operate. The Delhi Farmout will result in the immediate reduction in net
production and net revenues accruing to us from Delhi, until such time, if at
all, as the EOR project is completed and brought online. Without further
acquisitions of new properties, or production increases at our Tullos Field
Area, our production and revenues from oil and gas production will decline in
the foreseeable future, as compared to our fiscal 2006 results. Nevertheless, we
believe that the $50 million pre-tax cash payment we received from the Delhi
Farmout, the interest income earned on these proceeds and the oil production
from our Tullos Field Area operations will provide sufficient liquid resources
to fund our operations and capital program for the foreseeable future.
THE TYPES OF RESOURCES WE FOCUS ON HAVE CERTAIN RISKS.
Our business plan focuses on the acquisition and development of relatively
shallow, more complex and/or lower permeability reservoirs. Shallower reservoirs
usually have lower pressure, which translates into fewer natural gas volumes in
place; complex reservoirs are more difficult to analyze and exploit; and low
permeability reservoirs require more wells and stimulation for development and
such wells may have low profit margins and higher capital costs per produced BBL
of oil or MCF of gas.
The Delhi Farmout EOR project requires significant amounts of CO2 resources, the
source of which may be become unavailable or be curtailed. In order to produce
and deliver sufficient quantities of CO2 from Denbury's reserves from its
Jackson Dome, Mississippi field, the construction of an ~100 mile pipeline
necessary to connect to the Delhi Field will require large amounts of capital
resources and the acquisition of new permits, right-of-ways, engineering
designs, construction personnel and materials. Denbury's failure to mange these
and other technical, strategic and logistical risks, may render ultimate
enhanced recoveries from the planned CO2-EOR project, if any, to fall short of
our expectations.
In addition, the mature fields we currently own and operate have well bores that
were drilled as early as the 1920s. As such, they contain older down-hole
equipment and casing that is more subject to failure than new equipment. The
failure of such equipment or other subsurface failure can result in the complete
loss of a well.
Our new projects require that we acquire new leases in and around established
fields and drill and complete wells, some which may be horizontal, as well as
negotiate the purchase of existing well bores and production equipment and
install our proprietary artificial lift technology that has yet to be proven in
the field. Leases may not be available, required oil field services may not be
obtainable on the desired schedule or at the expected costs. While the projected
drilling results are considered to be low to moderate in risk, there is no
assurance as to what productive results may be obtained, if any.
OUR LIMITED OPERATING HISTORY MAKES IT DIFFICULT TO PREDICT FUTURE RESULTS AND
INCREASES THE RISK OF AN INVESTMENT IN OUR COMPANY.
We commenced our crude oil and natural gas operations in late 2003 and have a
limited operating history. Therefore, we face all the risks common to companies
in their early stages of development, including uncertainty of funding sources,
high initial expenditure levels and uncertain revenue streams, an unproven
business model, and difficulties in managing growth. Our prospects must be
considered in light of the risks, expenses, delays and difficulties frequently
encountered in establishing a new business. Any forward-looking statements in
this report do not reflect any possible effect on us from the outcome of these
types of uncertainty. Prior to our recent farmout transaction with Denbury, we
have incurred significant losses since the inception of our oil and gas
operations. We cannot assure you that we will be successful. While members of
our management have previously carried out or been involved with acquisition and
production activities in the crude oil and natural gas industry while employed
by us and other companies, we cannot assure you that our intended acquisition
targets and development plans will lead to the successful development of crude
oil and natural gas production or additional revenue.
WE MAY BE UNABLE TO CONTINUE LICENSING FROM THIRD PARTIES THE TECHNOLOGIES THAT
WE USE IN OUR BUSINESS OPERATIONS.
As is customary in the crude oil and natural gas industry, we utilize a variety
of widely available technologies in the crude oil and natural gas development
and drilling process. We do not have any patents or copyrights for the
technology we currently utilize. Instead, we license or purchase services from
the holders of such technology, or outsource the technology integral to our
business from third parties. Our commercial success will depend in part on these
sources of technology and assumes that such sources will not infringe on the
propriety rights of others. We cannot be certain whether any third-party patents
will require us to utilize or develop alternative technology or to alter our
business plan, obtain additional licenses, or cease activities that infringe on
third-parties' intellectual property rights. Our inability to acquire any
third-party licenses, or to integrate the related third-party products into our
business plan, could result in delays in development unless and until equivalent
products can be identified, licensed, and integrated. Existing or future
licenses may not continue to be available to us on commercially reasonable terms
or at all. Litigation, which could result in substantial cost to us, may be
necessary to enforce any patents licensed to us or to determine the scope and
validity of third-party obligations.
REGULATORY AND ACCOUNTING REQUIREMENTS MAY REQUIRE SUBSTANTIAL REDUCTIONS IN
PROVEN RESERVES (SEE GLOSSARY) AND LIMITATIONS OF HEDGING.
We review on a periodic basis the carrying value of our crude oil and natural
gas properties under the applicable rules of the various regulatory agencies,
including the SEC. Under these rules, the carrying value of proved reserves of
crude oil and natural gas properties may not exceed the present value of
estimated future net after-tax cash flows from proved reserves, discounted at
10%. Application of this "ceiling" test generally requires pricing future
revenues at the un-escalated prices in effect as of the end of our fiscal year
and requires a write down for accounting purposes if the ceiling is exceeded,
even if prices declined for only a short period of time. We may in the future be
required to write down the carrying value of our crude oil and natural gas
properties when crude oil and natural gas prices are depressed or unusually
volatile. Whether we will be required to take such a charge will depend on the
prices for crude oil and natural gas at the end of any fiscal period and the
effect of reserve additions or revisions and capital expenditures during such
period. If a write down is required, it would result in a charge to our earnings
but would not impact our cash flow from operating activities.
In order to reduce our exposure to short-term fluctuations in the price of crude
oil and natural gas and comply with the terms of our credit facility, we entered
into three commodity contracts. Although we terminated our credit facility in
May 2006, two of these contracts extend through February 2007. After June 2006,
these arrangements apply to virtually all of our crude oil production and
provide price protection against declines in crude oil prices. Our commodity
contracts may expose us to risk of financial loss in certain circumstances,
including instances where production is less than expected, our customers fail
to purchase contracted quantities of crude oil or natural gas or a sudden,
unexpected event materially impacts crude oil prices. In addition, our commodity
contracts may limit the benefit to us of increases in the price of crude oil.
WE MAY BE UNABLE TO ACQUIRE AND DEVELOP THE ADDITIONAL OIL AND GAS RESERVES THAT
ARE REQUIRED IN ORDER TO SUSTAIN OUR BUSINESS OPERATIONS.
In general, the volumes of production from crude oil and natural gas properties
decline as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent we acquire properties containing
proved reserves or conduct successful development activities, or both, our
proved reserves will decline. Our future crude oil and natural gas production
is, therefore, highly dependent upon our level of success in finding or
acquiring additional reserves.
WE ARE SUBJECT TO SUBSTANTIAL OPERATING RISKS THAT MAY ADVERSELY AFFECT OUR
RESULTS OF OPERATIONS.
The crude oil and natural gas business involves numerous operating hazards such
as well blowouts, mechanical failures, explosions, uncontrollable flows of crude
oil, natural gas or well fluids, fires, formations with abnormal pressures,
hurricanes, flooding, pollution, releases of toxic gas and other environmental
hazards and risks. We could suffer substantial losses as a result of any of
these events. While we carry general liability, control of well, and operator's
extra expense coverage typical in our industry, we are not fully insured against
all risks incident to our business.
We may not always be the operator of some of our wells. As a result, our
operating risks for those wells and our ability to influence the operations for
these wells will be less subject to our control. Operators of these wells may
act in ways that are not in our best interests. If this occurs, the development
of, and production of crude oil and natural gas from, some wells may not occur
which would have an adverse effect on our results of operations.
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US.
We depend to a large extent on the services of certain key management personnel,
including our executive officers, the loss of any of whom could have a material
adverse effect on our operations. In particular, our future success is dependent
upon Robert S. Herlin, our President, for capital raising, sourcing and
evaluating and closing deals, and oversight of development and operations.
THE LOSS OF ANY OF OUR SKILLED TECHNICAL PERSONNEL COULD ADVERSELY AFFECT OUR
BUSINESS.
We depend to a large extent on the services of skilled technical personnel to
operate and maintain our crude oil and natural gas fields. We do not have the
resources to perform all of these services and therefore we outsource our
requirements. Additionally, as our production increases, so does our need for
such services. Generally, we do not have long-term agreements with our drilling
and maintenance service providers. Accordingly, there is a risk that any of our
service providers could discontinue servicing our crude oil and natural gas
fields for any reason. Although we believe that we could establish alternative
sources for most of our operational and maintenance needs, any delay in
locating, establishing relationships, and training our sources could result in
production shortages and maintenance problems, with a resulting loss of revenue
to us. We also rely on third-party carriers for the transportation and
distribution of our production, the loss of any of which could have a material
adverse effect on our operations.
WE MAY HAVE DIFFICULTY MANAGING FUTURE GROWTH AND THE RELATED DEMANDS ON OUR
RESOURCES AND MAY HAVE DIFFICULTY IN ACHIEVING FUTURE GROWTH.
We hope to experience rapid growth through acquisitions and development
activity. Any future growth may place a significant strain on our financial,
technical, operational and administrative resources. Our ability to grow will
depend upon a number of factors, including:
o our ability to identify and acquire new development or acquisition
prospects;
o our ability to develop existing properties;
o our ability to continue to retain and attract skilled personnel;
o the results of our development program and acquisition efforts;
o the success of our technologies;
o hydrocarbon prices;
o our ability to successfully integrate new properties; and
o our access to capital.
We can not assure you that we will be able to successfully grow or manage any
such growth.
WE FACE STRONG COMPETITION FROM LARGER CRUDE OIL AND NATURAL GAS COMPANIES.
Our competitors include major integrated crude oil and natural gas companies and
numerous independent crude oil and natural gas companies, individuals and
drilling and income programs. Many of our competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than we have. We may not be able to successfully
conduct our operations, evaluate and select suitable properties and consummate
transactions in this highly competitive environment. Specifically, these larger
competitors may be able to pay more for development projects and productive
crude oil and natural gas properties and may be able to define, evaluate, bid
for and purchase a greater number of properties and prospects than our financial
or human resources permit. In addition, such companies may be able to expend
greater resources on the existing and changing technologies that we believe are
and will be increasingly important to attaining success in our industry.
THE CRUDE OIL AND NATURAL GAS RESERVES INCLUDED IN THIS REPORT ARE ONLY
ESTIMATES AND MAY PROVE TO BE INACCURATE.
There are numerous uncertainties inherent in estimating crude oil and natural
gas reserves and their estimated values. The reserves discussed in this report
are only estimates that may prove to be inaccurate because of these
uncertainties. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of crude oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable crude oil and
natural gas reserves depend upon a number of variable factors, such as
historical production from the area compared with production from other
producing areas and assumptions concerning effects of regulations by
governmental agencies, future crude oil and natural gas prices, future operating
costs, severance and excise taxes, development costs and work-over and remedial
costs. Some or all of these assumptions may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of crude 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 therefrom prepared by different
engineers or by the same engineers but at different times may vary
substantially. Accordingly, reserve estimates may be subject to downward or
upward adjustment. Actual production, revenue and expenditures with respect to
our reserves will likely vary from estimates, and such variances may be
material. The information regarding discounted future net cash flows included in
this report should not be considered as the current market value of the
estimated crude oil and natural gas reserves attributable to our properties. As
required by the SEC, the estimated discounted future net cash flows from proved
reserves are based on prices and costs as of the date of the estimate, while
actual future prices and costs may be materially higher or lower. Actual future
net cash flows also will be affected by factors such as the amount and timing of
actual production, supply and demand for crude oil and natural gas, increases or
decreases in consumption, and changes in governmental regulations or taxation.
In addition, the 10% discount factor, which is required by the SEC to be used in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with us or the crude oil and
natural gas industry in general.
WE CANNOT MARKET THE CRUDE OIL AND NATURAL GAS THAT WE PRODUCE WITHOUT THE
ASSISTANCE OF THIRD PARTIES.
The marketability of the crude oil and natural gas that we produce depends upon
the proximity of our reserves to, and the capacity of, facilities and
third-party services, including crude oil and natural gas gathering systems,
pipelines, trucking or terminal facilities, and processing facilities. The
unavailability or lack of capacity of such services and facilities could result
in the shut-in of producing wells or the delay or discontinuance of development
plans for properties. A shut-in or delay or discontinuance could adversely
affect our financial condition. In addition, federal and state regulation of
crude oil and natural gas production and transportation could affect our ability
to produce and market our crude oil and natural gas on a profitable basis.
Risks Relating to the Oil and Gas Industry
CRUDE OIL AND NATURAL GAS DEVELOPMENT, RE-COMPLETION OF WELLS FROM ONE RESERVOIR
TO ANOTHER RESERVOIR, RESTORING WELLS TO PRODUCTION AND DRILLING AND COMPLETING
NEW WELLS ARE SPECULATIVE ACTIVITIES AND INVOLVE NUMEROUS RISKS AND SUBSTANTIAL
AND UNCERTAIN COSTS.
Our growth will be materially dependent upon the success of our future
development program. Drilling for crude oil and natural gas and re-working
existing wells involve numerous risks, including the risk that no commercially
productive crude oil or natural gas reservoirs will be encountered. The cost of
drilling, completing and operating wells is substantial and uncertain, and
drilling operations may be curtailed, delayed or cancelled as a result of a
variety of factors beyond our control, including:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o inability to obtain leases on economic terms, where applicable;
o adverse weather conditions;
o compliance with governmental requirements; and
o shortages or delays in the availability of drilling rigs or crews
and the delivery of equipment.
Drilling or re-working is a highly speculative activity. Even when fully and
correctly utilized, modern well completion techniques such as hydraulic
fracturing and horizontal drilling do not guarantee that we will find crude oil
and/or natural gas in our wells. Hydraulic fracturing involves pumping a fluid
with or without particulates into a formation at high pressure, thereby creating
fractures in the rock and leaving the particulates in the fractures to ensure
that the fractures remain open, thereby potentially increasing the ability of
the reservoir to produce oil or gas. Horizontal drilling involves drilling
horizontally out from an existing vertical well bore, thereby potentially
increasing the area and reach of the well bore that is in contact with the
reservoir. Our future drilling activities may not be successful and, if
unsuccessful, such failure would have an adverse effect on our future results of
operations and financial condition. We cannot assure you that our overall
drilling success rate or our drilling success rate for activities within a
particular geographic area will not decline. We may identify and develop
prospects through a number of methods, some of which do not include lateral
drilling or hydraulic fracturing, and some of which may be unproven. The
drilling and results for these prospects may be particularly uncertain. Our
drilling schedule may vary from our capital budget. The final determination with
respect to the drilling of any scheduled or budgeted prospects will be dependent
on a number of factors, including, but not limited to:
o the results of previous development efforts and the acquisition,
review and analysis of data;
o the availability of sufficient capital resources to us and the other
participants, if any, for the drilling of the prospects;
o the approval of the prospects by other participants, if any, after
additional data has been compiled;
o economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for crude oil and natural gas and
the availability of drilling rigs and crews;
o our financial resources and results;
o the availability of leases and permits on reasonable terms for the
prospects; and
o the success of our drilling technology.
We cannot assure you that these projects can be successfully developed or that
the wells discussed will, if drilled, encounter reservoirs of commercially
productive crude oil or natural gas. There are numerous uncertainties in
estimating quantities of proved reserves, including many factors beyond our
control.
CRUDE OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES
WILL NEGATIVELY AFFECT OUR FINANCIAL RESULTS.
Our revenues, operating results, profitability, cash flow, future rate of growth
and ability to borrow funds or obtain additional capital, as well as the
carrying value of our properties, are substantially dependent upon prevailing
prices of crude oil and natural gas. Lower crude oil and natural gas prices also
may reduce the amount of crude oil and natural gas that we can produce
economically. Historically, the markets for crude oil and natural gas have been
very volatile, and such markets are likely to continue to be volatile in the
future. Prices for crude oil and natural gas are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for crude oil
and natural gas, market uncertainty and a variety of additional factors that are
beyond our control, including:
o worldwide and domestic supplies of crude oil and natural gas;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political instability or armed conflict in oil-producing regions;
o the price and level of foreign imports; and
o overall domestic and global economic conditions.
It is extremely difficult to predict future crude oil and natural gas price
movements with any certainty. Declines in crude oil and natural gas prices may
materially adversely affect our financial condition, liquidity, ability to
finance planned capital expenditures and results of operations. Further, oil and
gas prices do not move in tandem. Because approximately 99% of our reserves at
July 1, 2006 are crude oil reserves, we are more affected by movements in crude
oil prices. While our new projects are evaluated based on the assumption of oil
and gas prices considerably less than in the current market or projected in the
futures market, we do assume commodity prices will be higher than historic
levels prior to 2004.
OILFIELD SERVICE PRICES HAVE BEEN ESCALATING, AND THE AVAILABILITY OF SUCH
SERVICES MAY BE INADEQUATE TO MEET OUR NEEDS.
Our business plan to redevelop mature oil and gas resources requires third party
oilfield service vendors, which we do not control. Long lead times and spot
shortages of any of a myriad of services we may require to redevelop our
properties may prevent us from, or delay us in, maintaining or increasing the
production volumes we expect. In addition, the recent escalating costs for such
services may render certain or all of our projects uneconomic, as compared to
the earlier prices we may have assumed when deciding to redevelop newly
purchased or existing properties. Further adverse economic outcomes may result
from the long lead times often necessary to execute and complete our redevelop
plans.
GOVERNMENT REGULATION AND LIABILITY FOR ENVIRONMENTAL MATTERS MAY ADVERSELY
AFFECT OUR BUSINESS AND RESULTS OF OPERATIONS.
Crude oil and natural gas operations are subject to extensive federal, state and
local government regulations, which may be changed from time to time. Matters
subject to regulation include discharge permits for drilling operations,
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 crude oil and natural gas wells below actual production capacity
in order to conserve supplies of crude oil and natural gas. There are federal,
state and local laws and regulations primarily relating to protection of human
health and the environment applicable to the development, production, handling,
storage, transportation and disposal of crude oil and natural gas, by-products
thereof and other substances and materials produced or used in connection with
crude oil and natural gas operations. In addition, we may inherit liability for
environmental damages caused by previous owners of property we purchase or
lease. As a result, we may incur substantial liabilities to third parties or
governmental entities. We are also subject to changing and extensive tax laws,
the effects of which cannot be predicted. The implementation of new, or the
modification of existing, laws or regulations could have a material adverse
effect on us.
Risks Associated with Our Stock
OUR STOCK PRICE HAS BEEN AND MAY CONTINUE TO BE VERY VOLATILE.
Our common stock is thinly traded and the market price has been, and is likely
to continue to be, highly volatile. For example, during the twelve months prior
to June 30, 2006, our stock price as traded on the OTC Bulletin Board ranged
from $1.00 to $3.70. The variance in our stock price makes it extremely
difficult to forecast with any certainty the stock price at which an investor
may be able to buy or sell shares of our common stock. The market price for our
common stock could be subject to wide fluctuations as a result of factors that
are out of our control, such as:
o actual or anticipated variations in our results of operations;
o naked short selling of our common stock and stock price
manipulation;
o changes or fluctuations in the commodity prices of crude oil and
natural gas;
o general conditions and trends in the crude oil and natural gas
industry; and
o general economic, political and market conditions.
OUR EXECUTIVE OFFICERS, DIRECTORS AND AFFILIATES MAY BE ABLE TO CONTROL THE
ELECTION OF OUR DIRECTORS AND ALL OTHER MATTERS SUBMITTED TO OUR STOCKHOLDERS
FOR APPROVAL.
Our executive officers and directors, in the aggregate, beneficially own
approximately 36% of our outstanding common stock. Further, our Chairman of the
Board, Mr. Laird Q. Cagan, Managing Director of Cagan McAfee Capital Partners,
LLC ("CMCP") currently owns or controls, directly or indirectly, approximately
7.7 million shares (including shares issuable upon the exercise of warrants), or
approximately 29% of our outstanding common stock. Mr. Eric McAfee, a Managing
Director of CMCP, currently owns or controls, directly or indirectly,
approximately 5.9 million shares (including shares issuable upon the exercise of
warrants), or approximately 22% of our outstanding common stock, but is neither
an officer nor a member of our board of directors. Collectively, these two
managing directors of CMCP currently own or control, directly or indirectly,
approximately 13.6 million shares (including shares issuable upon the exercise
of warrants), or approximately 50% of our outstanding common stock. As a result,
these holders, if they were to act together, could exercise control over all
matters submitted to our stockholders for approval (including the election and
removal of directors and any merger, consolidation or sale of all or
substantially all of our assets). This concentration of ownership may have the
effect of delaying, deferring or preventing a change in control of our company,
impede a merger, consolidation, takeover or other business combination involving
our company or discourage a potential acquirer from making a tender offer or
otherwise attempting to obtain control of our company, which in turn could have
an adverse effect on the market price of our common stock.
THE MARKET FOR OUR COMMON STOCK IS LIMITED AND MAY NOT PROVIDE ADEQUATE
LIQUIDITY.
Our common stock is currently thinly traded on the American Stock Exchange. In
the twelve months prior to June 30, 2006, the actual trading volume in our
common stock ranged from a low of no shares of common stock traded to a high of
over 356,000 shares of common stock traded, with only 75 days exceeding a
trading volume of 50,000 shares. On most days, this trading volume means there
is limited liquidity in our shares of common stock. Selling our shares is more
difficult because smaller quantities of shares are bought and sold and news
media coverage about us is limited. These factors result in a limited trading
market for our common stock and therefore holders of our stock may be unable to
sell shares purchased should they desire to do so.
IF SECURITIES OR INDUSTRY ANALYSTS DO NOT PUBLISH RESEARCH REPORTS ABOUT OUR
BUSINESS OR IF THEY DOWNGRADE OUR STOCK, THE PRICE OF OUR COMMON STOCK COULD
DECLINE.
Small, relatively unknown companies can achieve visibility in the trading market
through research and reports that industry or securities analysts publish.
However, to our knowledge, no non-company paid analysts cover our company. The
lack of published reports by independent securities analysts could limit the
interest in our common stock and negatively affect our stock price. We do not
have any control over the research and reports these analysts publish or whether
they will be published at all. If any analyst who does cover us downgrades our
stock, our stock price would likely decline. If any analyst ceases coverage of
our company or fails to regularly publish reports on us, we could lose
visibility in the financial markets, which in turn could cause our stock price
to decline.
THE ISSUANCE OF ADDITIONAL COMMON AND PREFERRED STOCK WOULD DILUTE EXISTING
STOCKHOLDERS.
We are authorized to issue up to 100,000,000 shares of common stock. To the
extent of such authorization, our board of directors has the ability, without
seeking stockholder approval, to issue additional shares of common stock in the
future for such consideration as our board may consider sufficient. The issuance
of additional common stock in the future will reduce the proportionate ownership
and voting power of the common stock now outstanding. We are also authorized to
issue up to 5,000,000 shares of preferred stock, the rights and preferences of
which may be designated in series by our board of directors. Such designation of
new series of preferred stock may be made without stockholder approval, and
could create additional securities which would have dividend and liquidation
preferences over the common stock now outstanding. Preferred stockholders could
adversely affect the rights of holders of common stock by:
o exercising voting, redemption and conversion rights to the detriment
of the holders of common stock;
o receiving preferences over the holders of common stock regarding our
surplus funds in the event of our dissolution or liquidation;
o delaying, deferring or preventing a change in control of our
company; and
o discouraging bids for our common stock.
WE DO NOT PLAN TO PAY ANY CASH DIVIDENDS ON OUR COMMON STOCK.
We have not paid any dividends on our common stock to date and do not anticipate
that we will be paying dividends in the foreseeable future. Any payment of cash
dividends on our common stock in the future will be dependent upon the amount of
funds legally available, our earnings, if any, our financial condition, our
anticipated capital requirements and other factors that our board of directors
may think are relevant. However, we currently intend for the foreseeable future
to follow a policy of retaining all of our earnings, if any, to finance the
development and expansion of our business and, therefore, do not expect to pay
any dividends on our common stock in the foreseeable future.
Item 2. Description of Properties.
Delhi Field
The Delhi Holt Bryant Unit in the Delhi Field, currently our most strategic
asset, is in the early stages of being redeveloped through an enhanced oil
recovery (EOR) project utilizing CO2 technology. We, and various other companies
that submitted offers to participate with us, believe that the Delhi Holt Bryant
Unit is an excellent candidate for a CO2-EOR project, due to its favorable rock
characteristics, large unproven reserves remaining in place, miscibility
potential and relatively close location to naturally occurring CO2 reserves
approximately 100 miles east of the Delhi Field. In June 2006, we conveyed a
farmout to Denbury Resources for all of our working interests in the Delhi Holt
Bryant Unit and 75% of our working interests in certain other depths of the
Delhi Field. For this, we received approximately $50 million in cash, a 25%
back-in working interest in the Delhi Holt Bryant Unit and a commitment by
Denbury Resources to install a CO2-EOR project in the Delhi Holt Bryant Unit
(the "Delhi Farmout"), as described in more detail below.
The Delhi Field was discovered in the mid-1940's and was extensively developed
by various operators including the Sun Oil and Murphy Oil companies through the
drilling and completion of approximately 450 wells, most within the first few
years after discovery. According to W. D. Von Gonten & Co., the third party
reservoir engineering firm that prepares our independent estimate of proved
reserves, the Delhi Field has produced more than 200 million barrels of crude
oil and substantial amounts of natural gas to date. Much of the natural gas
production was processed to remove natural gas liquids and re-injected for
pressure maintenance. Beginning in the late 1950's, the field was unitized to
conduct a pressure maintenance project through the injection of water into the
producing reservoir in down dip injection wells (unitization is the process of
combining multiple leases into a single ownership entity in order to simplify
operations and equitably distribute royalties when common operations are
conducted over multiple leases). Drilling operations resulted in primarily
40-acre spacing across the unit's 13,636 acres. A few wells were drilled below
the targeted Tuscaloosa and Paluxy formations. The water injection pressure
maintenance waterflood did not utilize a more traditional and effective five
spot flood pattern that generally results in a more complete reservoir sweep and
oil recovery.
At the time we began our oil and gas operations in late September 2003, we
purchased 100% of the working interests and an 80% net revenue interest in the
Delhi Field (from the surface to the top of the Massive Anhydride, but excepting
the Mengel Unit), for approximately $2.8 million, including the assumption of a
plugging and abandonment reclamation bond. All but 43 wells in Richland,
Franklin and Madison Parishes, Louisiana had been plugged and abandoned and
production averaged approximately 18 BOPD with no natural gas being sold due to
a lack of natural gas processing and transportation facilities. The best
producing well was immediately lost during a periodic sand wash work-over when
water from a lower reservoir broke through along the casing exterior and into
the producing reservoir.
In October of 2003, we applied an unproven lateral re-entry technology that
resulted in no increase in production. In December 2003, we initiated a
development program based on re-completion of wells to other reservoirs and
restoring non-producing wells to producing status. During 2004, we refurbished a
gas injection line necessary to serve as our gas gathering line and placed a gas
processing plant in the field, thus re-starting shut-in natural gas production
in July of 2004. During 2005, we began a five well development drilling program
aimed at reaching mostly proved undeveloped reserves left in primary "attic"
positions. The culmination of these activities caused production to increase
from 18 BOPD to a monthly average rate of 145 BOEPD during our peak production
month in late 2005.
Concurrent with these activities, we completed internal studies indicating that
the reservoirs in the Delhi Holt Bryant Unit, the dominant oil producing
reservoirs, were believed to be less than 50% depleted. Based on successful CO2
pilots conducted by Sun Oil in 1985, and favorable rock characteristics shown in
multiple cores taken throughout the Delhi Field, we began discussions in late
2004 with industry partners skilled in tertiary/EOR recovery methods, especially
with respect to CO2 injection.
With positive industry reception, and following extended negotiations with three
candidate partners, we accelerated our redevelopment plan in June 2006 by
selling a major portion of our Delhi Field interests in the form of a farmout
(the "Delhi Farmout") to a subsidiary of Denbury Resources, Inc. (NYSE: DNR).
Important aspects of this transaction include:
o We received approximately $50 million in cash (pre-tax) to redeploy
to other projects and to repay of all of our debt.
o DNR committed to install a CO2-EOR project in the Holt Bryant Unit
and is obligated to expend a minimum of $100 million on the project
over the next 6-1/2 years, subject to penalty payments to us for
shortfalls in such expenditures. All capital expenditures necessary
to install the project are required to be borne by DNR.
o DNR, the dominant CO2-EOR operator on the Gulf Coast, currently
operates several CO2-EOR projects, and owns naturally occurring CO2
reserves we believe to be sufficient to meet the needs of the Delhi
project.
o We retained significant participating interests through separately
acquired royalty and overriding royalty interests aggregating 7.4%,
and a 25% back-in working interest (20% revenue interest).
o Our 25% back-in working interest in the CO2-EOR project is based on
a defined $200 million threshold, and our back-in occurs when
cumulative project net revenues less direct operating costs in the
field reach the threshold.
o We further retained a 25% working interest (20% net revenue
interest) in certain other depths outside of the Holt Bryant Unit
within the Delhi Field, and believe that additional development
potential may exist in the shallower depths.
o We expect to be able to claim proven reserves following the first
injection of CO2 and demonstration of production response.
Tullos Field Area
On September 3, 2004, through a wholly-owned subsidiary, we completed the
acquisition of a 100% working interest and approximately 78% average net revenue
interest in producing and shut-in crude oil wells, water disposal wells,
equipment and improvements located in the Tullos Urania, Colgrade and Crossroads
Fields in LaSalle and Winn Parish, Louisiana, collectively referred to as the
Tullos Field Area. The purchased assets included 124 completed wells, 9 water
disposal wells, and all associated infrastructure, including water disposal
facilities, crude oil and water tanks, flow lines and pumping units. In addition
we acquired 15 crude oil wells that required new leases. Of the purchased wells,
81 were producing and 43 were shut-in due to repair and maintenance
requirements. The purchase price for the acquisition was $725,000 before
adjustment for post-effective date production and expenses.
In early February 2005, we closed the purchase of a 100% working interest and
approximately 79% average net revenue interest in additional properties in the
same Tullos Urania and Colgrade Fields. The purchased assets included 65
producing crude oil wells, 56 shut-in crude oil wells, 8 salt water disposal
wells and associated infrastructure and equipment. The purchase price for the
acquisition was $798,907, after post-closing adjustments.
The original development plan for the properties included restoring wells to
production and increases in produced water disposal capacity. Oil production
from wells is generally in the form of fluid that is generally 99.5% brine water
on average, and oil production rate is constrained by the capacity to properly
dispose of the produced water. The high level of industry activity, however, has
reduced the availability of oil field services, particularly workover rigs, and
our wells require substantial ongoing maintenance and repairs that had been
neglected in the year prior to the sale. Thus, the initial focus of operations
was on restoring the stated production level of the then producing wells. We
first applied to state regulatory agencies for required permits to convert wells
to disposal use in 2005, and received the first permit in the spring of 2006.
Following conversion, the state agencies must then authorize use of the
converted well. The conversion process is ongoing and the first well has been
approved by state agencies for use and we believe that the balance of the seven
conversions will be completed in calendar year 2006.
For the month of June 2006, we produced approximately 118 BOPD from our Tullos
Field Area. As only one service rig is available, its use in converting wells to
water disposal utility creates a growing backlog of producing wells being shut
in for repairs and maintenance.
We are reviewing the results of our development program and the ongoing high
level of required maintenance and repairs to determine other options to produce
the substantial remaining oil potential while reducing operating costs.
Other Operations
We maintain insurance on our properties and operations for risks and in amounts
customary in the industry. Such insurance includes general liability, excess
liability, control of well, operators extra expense and casualty coverage. Not
all losses are insured, and we retain certain risks of loss through deductibles,
limits and self-retentions. We do not carry lost profits coverage, and our
aviation liability insurance coverage is limited to $1million.
We occupy a leased headquarters containing 2,259 square feet in a modern
high-rise office building located in the West Memorial area of Houston, Texas.
In April 2004, we extended our lease for three years, and the right to use
furniture and fixtures without cost.
For more complete information regarding current year activities, including crude
oil and natural gas production, refer to "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net
Revenues
We engaged W. D. Von Gonten & Co. ("Von Gonten") to prepare an independent
report of our proved reserves located in the Delhi Field and Tullos Field Area
as of July 1, 2006. Von Gonten also previously prepared an independent report of
our proved reserves at July 1, 2005, July 1, 2004 and January 1, 2004.
Estimates of reserve quantities and values must be viewed as being subject to
significant change as more data about the properties becomes available. Many, if
not most, of our existing wells are generally mature wells, originally drilled
as early as the 1920's. As such, they contain older down-hole equipment and
casing that is more subject to failure than new equipment. The failure of such
equipment or other subsurface failure can result in the complete loss of a well.
At July 1, 2006, natural gas represented 1% and crude oil represented 99% of
total proved reserves, denominated in equivalent barrels using a six MCF of gas
to one barrel of oil conversion ratio, as compared to 14% and 86%, respectively,
at July 1, 2005. The reduction in proved reserves was due to the Delhi Farmout.
The following table sets forth, as of July 1, 2006 and July 1, 2005, information
regarding our proved reserves based on the assumptions set forth in Note 10 to
the Consolidated Financial Statements, where additional reserve information is
provided. The average NYMEX prices used to calculate estimated future net
revenues were $73.93 and $56.50 per barrel of oil and $6.10 and $6.98 per MMBTU
of gas as of June 30, 2006 and June 30, 2005, respectively. The average NYMEX
prices used were adjusted for transportation, market differentials and BTU
content of gas produced. Amounts do not include estimates of future Federal and
State income taxes.
Estimated Future
Oil Gas Estimated Future Net Revenues
(bbls) (mcf) Net Revenues Discounted at 10%
------- ------- ---------------- -----------------
Jul 1, 2006 460,525 25,800 $14,141,560 $ 8,038,791
Jul 1, 2005 771,817 732,300* $24,892,850 $17,479,486
* NGL reserves of 7,300 as of July 1, 2005 are included in the above gas
volumes, at a 6:1 ratio.
At July 1, 2006, Proved Developed reserves totaled 82% of Total Proved reserves,
the balance consisting of Proved Undeveloped reserves.
At July 1, 2005, Proved Developed reserves (including Proved Behind Pipe)
totaled 68% of Total Proved reserves, the balance consisting of Proved
Undeveloped reserves.
Production, Average Sales Prices and Average Production Costs
The following table set forth certain information regarding production volumes,
oil and gas sales, average sales prices received and expenses for the periods
indicated:
12 months 12 months
ended June 30, 2006 ended June 30, 2005
------------------- -------------------
Product Volume Price Volume Price
---------- ------ ------ ------ ------
Gas (mcf) 45,368 $ 9.35 54,137 $ 6.62
Oil (bbls) 45,091 $54.05 27,230 $46.89
Average production costs, including production taxes, per unit of production
(using a six to one conversion ratio of mcf's to barrels) were $34.49 and $26.02
per barrel of oil equivalent for the twelve months ended June 30, 2006 and 2005,
respectively.
Productive Wells and Developed Acreage
Developed acreage at June 30, 2006 totaled 519 net and gross acres, all of which
is in the Tullos Field Area in La Salle and Winn Parish Louisiana. This is a
reduction from last year by 13,636 acres, due to the Delhi Farmout, which became
effective as of June 1, 2006.
At June 30, 2006, we owned working interests in 262 net and gross wells
consisting of 165 crude oil wells, 22 salt water disposal wells and 75 shut-in
wells with uncertain future utility located in the Tullos Field Area.
Approximately 65 of the shut-in crude oil wells in the Tullos Field Area are
believed, in most part, to be capable of production following varying degrees of
repair and maintenance or incremental water disposal capacity. The number of
wells has declined by 44 wells from June 30, 2005 due to the farm-out of our
Delhi Holt Bryant Unit effective June 1, 2006.
Undeveloped Acreage
As of June 30, 2006, all of our working interest acreage is held by production
through a unitization agreement or lease agreements on developed properties.
Drilling
During the twelve months ended June 30, 2006, we drilled and completed 5 new
wells in the Delhi Field. For the twelve months ended June 30, 2005, no new
wells were drilled.
Subsequent Events
Natural Gas Systems, Inc changed its name to "Evolution Petroleum Corporation"
effective July 11, 2006, to avoid confusion with similar names on the AMEX and
to better reflect our business model. The name change was effectuated without
shareholder approval pursuant to a statutory short-form merger with a wholly
owned subsidiary, followed by the name change, in accordance with the provisions
of Nevada law.
On July 17, 2006, Evolution Petroleum Corporation started trading its common
stock on the American Stock Exchange ("AMEX") under the EPM ticker symbol.
On July 21, 2006, we funded and closed the acquisition of royalty and overriding
royalty interests aggregating 0.39% in the Delhi Holt Bryant Unit from an
unrelated third party owner.
Item 3. Legal Proceedings.
On November 17, 2005, a multi-plaintiff lawsuit was filed in the Fifth Judicial
District Court, Richland Parish, Louisiana, against 26 defendants, including two
of our subsidiaries, Arkla Petroleum L.L.C. ("Arkla") and NGS Sub Corp (together
with Arkla, the "Subsidiaries"). We were not served with, notified or aware of,
the lawsuit until February 2006.
The plaintiffs claim to be landowners whose property (including the soil,
surface water, and groundwater) has been contaminated by oil and gas
exploration, production and development activities conducted by the defendants
on the plaintiffs' property and adjoining land since the 1930's (including
activities by Arkla as operator of the Delhi Field subsequent to Arkla's
formation in 2002 and our acquisition of Arkla in 2003, and activities since NGS
Sub Corp's acquisition of a 100% working interest in the Delhi Field in 2003).
The plaintiffs claim that the defendants knew of the alleged dangerous nature of
the contamination and actively concealed it rather than remedy the problem.
The plaintiffs are seeking unspecified compensatory damages and punitive
damages, as well as an order that the defendants restore the property and
prevent further contamination. Our ultimate exposure related to this lawsuit is
not currently determinable, but could, if adversely determined, have a material
adverse effect on our financial condition. Our costs to defend this action,
which we currently believe is not covered by our insurance policies, could also
have a material adverse effect on our financial condition.
During the quarter ended March 2006, we filed our response and Motion to Stay
Proceedings and Dilatory and Declinatory Exceptions with respect to this
proceeding.
During the quarter ended June 2006, the Governor of the State of Louisiana
signed into law new legislation addressing complaints similar to and including
those filed against us. Although the intention of the legislation was designed
to limit plaintiff complaints and remedies by possibly deferring first to
administrative experts within the Louisiana State Departments of Environmental
Quality and Natural Resources, it is unclear at this time the impact of such
legislation.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders through the solicitation of
proxies or otherwise.
PART II
Item 5. Market for Common Equity, Related Stockholder Matters and Small Business
Issuer Purchases of Equity Securities.
Our common stock trades on the American Stock Exchange ("AMEX") under the ticker
symbol EPM, effective July 17, 2006. Prior to this time, our stock traded on the
OTC Bulletin Board National Association of Securities Dealers Automated
Quotation System under the symbol "NGSY" and its predecessor symbol "RLYI". The
following table sets forth the high and low bid prices per share of our Common
Stock for each of the calendar quarters identified below as reported by the OTC
Bulletin Board. These quotations represent inter-dealer prices, without retail
mark-up, markdown or commission, and may not represent actual transactions.
Furthermore, the prices have been adjusted for a 40:1 stock split that occurred
on February 5, 2004.
2006: High Low
----- ----- -----
Quarter ended June 30, 2006 $3.70 $2.01
Quarter ended March 31, 2006 $2.65 $1.31
2005: High Low
----- ----- -----
Quarter ended December 31, 2005 $2.05 $1.15
Quarter ended September 30, 2005 $2.05 $1.00
Quarter ended June 30, 2005 $3.47 $1.32
Quarter ended March 31, 2005 $2.30 $1.55
2004: High Low
----- ----- -----
Quarter ended December 31, 2004 $2.30 $1.45
Quarter ended September 30, 2004 $3.75 $2.05
At September 22, 2006, we had 1,782 shareholders of record.
We have never paid a cash dividend and we do not expect to pay any cash
dividends in the foreseeable future. Earnings, if any, are expected to be
reinvested in business activities. No stock has been repurchased by us since the
merger of Old NGS into us in May, 2004.
Securities authorized for issuance under equity compensation plans
As of June 30, 2006, options to purchase 2,361,000 shares had been granted under
the 2004 Stock Plan and 145,000 shares were issued directly under the same plan.
The purpose of the 2004 Stock Plan is to grant equity compensation in the form
of stock grants, options or warrants to purchase our common stock to our
employees and key consultants.
Number of Number of securities
securities to Weighted-average remaining
be issued exercise available for future
upon exercise price of issuance under
of outstanding outstanding equity compensation
options, options, warrants plans (excluding
warrants and and securities reflected
rights rights in column (a))
Plan category (a) (b) (c)
------------- -------------- ----------------- --------------------
Equity compensation plans approved by
security holders 3,016,000(1) $1.42 1,494,000
Equity compensation plans not approved by
security holders 1,478,021(2) $1.50 --
Total 4,494,021 $1.44 1,494,000
(1) On May 26, 2004, we, as Reality Interactive, Inc., executed an Agreement and
Plan of Merger with Natural Gas Systems, Inc., a Delaware corporation (the
"Merger"). In connection with the Merger, we assumed the obligations of 600,000
stock options under our newly acquired subsidiary's 2003 Stock Option Plan. As
of June 30, 2006, 510,000 shares remain issuable upon exercise under the 2003
Stock Option Plan and no further options shall be issued thereunder. As of June
30, 2006, there were 2,361,000 shares of common stock issued or issuable upon
exercise of outstanding options and 145,000 shares issued directly under the
2004 Stock Plan leaving 1,494,000 shares of common stock available for issuance.
(2) In addition to assuming certain obligations listed in footnote 1 above, in
connection with the Merger, we also assumed outstanding warrants to purchase
312,931 shares of common stock at an exercise price of $1.00, with a seven year
term (warrants). We issued 240,000 of these warrants to CMCP and their assigns
in connection with arranging the merger and 72,931 were issued to Laird Q.
Cagan, Chadbourn Securities and their assigns in connection with capital raising
services. Subsequently, we issued a warrant to purchase 122,590 shares of common
stock to Laird Q. Cagan, Chadbourn Securities and their assigns in connection
with capital raising services, a warrant to purchase 5,000 shares for capital
raising services in connection with the loan agreement with Prospect Energy
Corporation, a warrant to purchase 287,500 shares of common stock in connection
with Mr. Herlin's employment agreement with the Company, a warrant to purchase
200,000 shares in connection with Mr. Mazzanti's employment agreement with the
Company, a warrant to purchase 400,000 shares of common stock in connection with
Mr. Herlin's annual performance incentive and a warrant to purchase 150,000
shares of common stock in connection with Sterling McDonald's annual performance
incentives.
Recent Sales of Unregistered Securities
This information was previously reported on our 10-QSB and Current Form 8-K
filed during the fiscal year ended June 30, 2006.
Item 6. Management's Discussion and Analysis or Plan of Operation.
Liquidity and Capital Resources
As of June 30, 2006, we had approximately $9.9 million of unrestricted cash and
$34.7 million of cash held in a qualified intermediary ("QI") account for
possible Internal Revenue Code 1031 "like-kind exchanges", all of which is
available to us at any time. The QI account provides us the opportunity to defer
the recognition of taxable gain on amounts used from the QI account to acquire
like-kind property within 180 days from the date of the outgoing property sale
from our Delhi Farmout (being December 9, 2006) for assets identified within 45
days of such sale. Concurrent with the closing of the Delhi Farmout, we
established the QI account with $35 million of the $50 million of proceeds we
received from Denbury at closing, $420,000 of which has been used to acquire
like-kind property on or prior to June 30, 2006 (partially offset by
approximately $82,000 of interest income earned on the QI account). In the event
that we choose to withdraw any funds from the qualified intermediary account to
fund non like-kind exchanges, or fail to use all of the funds prior to December
9, 2006, all of the funds remaining or disbursed from the QI account will become
subject to immediate taxable gain on the sale of the Delhi property.
At June 30, 2006 we had $6.5 million of positive working capital, as compared to
$2.6 million of positive working capital at June 30, 2005. Our working capital
at June 30, 2006 does not include the $34.7 million of cash deposited in the QI
account for possible like-kind exchanges, or the $13.1 million of deferred tax
liability associated with such cash receipt deferral, as they are recorded as
non-current assets and liabilities, respectively.
Cash flow used by our operating activities was $0.7 million for the twelve
months ended June 30, 2006, as compared to $1 million used during the fiscal
year ended June 30, 2005.
Cash flow provided by investing activities was approximately $11.8 million for
the twelve months ended June 30, 2006. Approximately $50 million of cash was
provided by the Delhi Farmout. Of the major investing activities, approximately
$34.7 million was invested in the QI account for possible 1031 "like-kind"
exchanges, approximately $1.4 million was used to acquire additional royalty and
overriding royalty interests in the Delhi Holt Bryant Unit, $2.6 million was
used to develop our oil and gas properties (primarily in the Delhi Field prior
to our divestiture). In the prior fiscal year, we used $1.6 million to acquire
working interests in our Tullos Field Area, approximately $0.5 million was used
in developing our properties, and $0.6 million was used to fund the Prospect
Debt Service Reserve account.
During the twelve months ended June 30, 2006, we borrowed $1.04million and
received $1.0 million in proceeds (net of transaction costs) from the sale of
351,553 shares of common stock and the issuance of warrants to Prospect with
respect their additional loan, prior to the repayment of all of our debt in the
amount of $5.6 million.
These transactions, especially the Delhi Farmout, have allowed us to:
o Further strengthen our balance sheet to fund new development
projects in accordance with our business plan to exploit known
petroleum resources.;
o Participate in a major enhanced oil recovery project without our
incurring further capital expenditures or scaled up operations; and
o Repay all of our debt.
Although our future development initiatives in the Delhi Field are expected to
be replaced with a CO2-EOR project offering much greater potential, the Delhi
Farmout will result in the immediate reduction in net production and net
revenues accruing to us from Delhi until such time, if at all, as the CO2-EOR
project is completed and brought online. Without further acquisitions of new
properties, or production increases at our Tullos Field Area, our production and
revenues from oil and gas production will decline in the foreseeable future, as
compared to our fiscal 2006 results. Nevertheless, we believe that the $50MM of
pre-tax proceeds that we received from the Delhi Farmout, the interest income
earned on these proceeds and the oil production from our Tullos Field Area
operations will provide sufficient liquid resources to fund our operations and
capital program for the foreseeable future.
Product Prices and Production
Refer to Item 1, "Markets and Customers", for discussion of oil and gas prices
and marketing.
Although product prices are key factors in our ability to operate profitably and
to budget capital expenditures, they are beyond our control and are difficult to
predict.
Refer to Item 2, "Properties", for disclosures regarding reserve values and for
a summary on production, average sales prices and average production costs.
Oil and Gas Activities
General
Our oil and gas activities for the fiscal year 2006 included ongoing development
of our fields in Louisiana, completion of our development drilling program in
the Delhi Field, purchase of additional royalty and overriding royalty interests
in the Delhi Holt Bryant Unit, and, most importantly, completion of the Delhi
Farmout. Important aspects of the Delhi Farmout include:
o We received approximately $50 million in cash (pre-tax) to redeploy
to other projects and to repay of all of our debt.
o DNR committed to install a CO2-EOR project in the Holt Bryant Unit
and is obligated to expend a minimum of $100 million on the project
over the next 6-1/2 years, subject to penalty payments to us for
shortfalls in such expenditures. All capital expenditures necessary
to install the project are required to be borne by DNR.
o DNR, the dominant CO2-EOR operator on the Gulf Coast, currently
operates several CO2-EOR projects, and owns naturally occurring CO2
reserves we believe to be sufficient to meet the needs of the Delhi
project.
o We retained significant participating interests through separately
acquired royalty and overriding royalty interests aggregating 7.4%,
and a 25% back-in working interest (20% revenue interest).
o Our 25% back-in working interest in the CO2-EOR project is based on
a defined $200 million threshold, and our back-in occurs when
cumulative project net revenues less direct operating costs in the
field reach the threshold.
o We further retained a 25% working interest (20% net revenue
interest) in certain other depths outside of the Holt Bryant Unit
within the Delhi Field, and believe that additional development
potential may exist in the shallower depths.
o We expect to be able to claim proven reserves following the first
injection of CO2 and demonstration of production response.
Reserves
Refer to Item 2, "Properties, General, Estimated Proved Oil and Gas Reserves and
Future Net Reserves", for information regarding oil and gas reserves.
Results of Operations
Fiscal year ended June 30, 2006 compared to fiscal year ended June 30, 2005
Revenues. Our revenues were $2.9 million in fiscal year 2006, compared to
revenue of $1.6 million in fiscal year 2005. This 75% increase in revenues was
primarily due to increased oil sales of approximately 65%, offset by a 16%
decrease in gas sales. In addition, overall commodity prices were higher by 11%
and 41%, respectively, for oil and gas. Increased oil sales were due to
development activity at our Delhi Field, a full year of production from our
Tullos Field Area and improved commodity prices. Gas sales decreased due to
depletion of gas reservoirs.
Lease Operating Expenses. The 97% increase in our lease operating expenses is
primarily due to an increase in the number of wells operated in 2006 versus 2005
and well work-over costs. Fiscal 2006 includes a full year of operating expenses
for the Tullos Field Area, which assets were purchased during early and mid
fiscal year 2005. In addition, lease operating expenses increased due to
substantial overall industry cost increases and due to an increase in drilling
and production activity.
Production taxes. The 27% increase in production (severance) taxes is directly
related to the increase in net production and sales.
General and Administrative expenses (G&A). Our G&A expenses increased 27% in
fiscal 2006 as compared to fiscal 2005, primarily due to the addition of two
full time employees in late fiscal 2005 and accrual of cash bonuses for fiscal
year 2006, offset slightly by reduced non-cash stock compensation expense of
$546,567 during fiscal 2006, as compared to $707,117 during fiscal 2005. Our G&A
expenses continue to be high due to costs of being a public company, compounded
by high recruitment costs, salaries and benefits necessary to attract and retain
personnel in a tight market for skilled energy staff.
Depletion, Depreciation and Amortization (DD&A). DD&A expenses are recorded on
the full cost method of accounting. Depletion and depreciation of oil and gas
properties is on a unit of production basis. In the fiscal year ended 2006, the
average DDA rate per BOE was up 13% percent to $7.48 per barrel of oil
equivalent, compared to prior year of $6.63 per barrel of oil equivalent. This
increase is attributable to higher capital spending than estimated for the Delhi
Development drilling program. Depreciation of office equipment and computer
equipment is computed on a straight line basis.
Interest Income. Our interest income increased significantly, from $11,709 to
$165,313 due to higher cash balances and higher interest rates.
Interest Expense. Interest expense increased significantly from $387,301 to
$2,600,180 primarily due to the Prospect note payable. Specifically, cash
interest paid was approximately $600,000, imputed interest expense was
approximately $1,302,000 and amortization of deferred financing fees and other
loan costs was approximately $698,000 were all related to the Prospect note and
the early pre-payment of such note during fiscal year 2006.
Gain on sale of asset. As the result of the approximately $50 million in pre-tax
cash proceeds we received from the Delhi Farmout, we recorded a pre-tax gain on
the sale of assets for approximately $45 million after adjustments for customary
closing costs and buyer and seller credits.
Net income. We reported a net income of $24.6 million for the fiscal year 2006,
compared to a net loss of $2.2 million for the previous year. The primarily
reason for the net income in current the year is the $45 million pre-tax gain we
recorded from the Delhi Farmout.
Earnings / (loss) per share (EPS). For fiscal year 2006, basic and diluted EPS
was $0.98 and $0.96, respectively. For prior fiscal year, basic and diluted EPS
was $(0.09).
Our results of operations were positively impacted by the following events
during the fiscal year 2006:
o Receipt of approximately $50 million (pre-tax) for our Delhi
Farmout;
o Completion of our first full year of operations in the Tullos Field
Area;
o Successful drilling and completion of our Delhi Ut. #92-2 and Delhi
Ut. #70-4; and
o High crude oil and natural gas prices.
Our operating results for the year ended June 30, 2006 were adversely impacted
by the following events:
o With respect to our Delhi Development Drilling Program:
The Delhi Ut. 92-2 depleted far more rapidly than projected.
Drilling results in the Delhi Ut. 87-3, 139-2 and 225-2
yielded reservoirs that require additional stimulation to
reach the expected production rates, and required substantial
completion activities in excess of budgeted expenditures.
The program was substantially delayed due to unavailability of
a drilling rig, and the poor quality of the drilling rig and
operating crew received contributed to results less than
projected and far higher costs than budgeted.
o With respect to our Tullos Field Area:
The high industry demand for workover service rigs hampered
our ability to carry out our maintenance, repair and
development programs in a timely manner.
Delays in permit approvals necessary to convert wells to water
disposal utility substantially delayed our development program
at Tullos.
The following remedial actions have been or are planned to be taken:
o We have replaced our Delhi Development Drilling Program with a much
larger CO2-EOR project.
o We have begun a search for a General Manager for Tight Gas
Development and Drilling;
o We are focusing our new development projects in areas with greater
access to field services; and
o With respect to our Tullos Field Area, we:
Received the seven water disposal well permits we requested.
Conversion operations, to be followed by final regulatory
approvals, are in process.
Contracted to purchase a field yard in the Tullos Field Area
in order to consolidate operations and inventory.
Are considering alternative options to recover oil in the
Tullos Field Area and reduce operating expenses.
Plan on replacing certain high maintenance beam pumps with
submersible pumps, potentially reducing maintenance expense
and production downtime.
Following is a summary of the progress we have made in both sales volumes and
revenues, net to our interest:
Net to EPM for the quarters ended: Units 9/30/2004 12/31/2004 3/31/2005 6/30/2005 9/30/2005 12/31/2005 3/31/2006 6/30/2006*
---------------------------------- ----- --------- ---------- --------- --------- --------- ---------- --------- ----------
Oil & Gas Revenue $ $231,167 $365,768 $402,305 $635,948 $542,884 $830,936 $878,602 $608,993
Oil volumes sold BO 3,955 5,234 6,545 12,644 10,639 11,860 13,890 10,553
Gas volumes sold MCF 11,252 15,679 16,378 10,828 9,811 24,110 10,147 1,300
Barrels of oil equivalent sold BOE 5,830 7,847 9,275 14,449 12,274 15,878 15,581 10,770
Oil price (incl hedging gain or
losses) $BBL $ 42.66 $ 47.94 $ 47.61 $ 50.78 $ 45.72 $ 47.00 $ 57.67 $ 57.41
Gas price (incl hedging gain or
losses) $/MCF $ 5.55 $ 7.32 $ 6.71 $ 6.35 $ 5.90 $ 11.57 $ 8.25 $ 2.75
* only two months of Delhi field results are included as a result of the
Delhi Farmout becoming effective as of June 1, 2006.
Highlights of our performance from July 1, 2004 to June 30, 2006:
o We have generally increased revenues for each quarter, primarily due
to both production and commodity price increases; and
o We have generally increased sales volumes for each quarter due to
increases in production for both fields.
Critical Accounting Policies and Estimates
Accounting for Oil and Gas Property Costs. As more fully discussed in Note 3 to
the consolidated financial statements, the Company (i) follows the full cost
method of accounting for the costs of its oil and gas properties, (ii) amortizes
such costs using the units of production method, and (iii) applies a quarterly
full cost ceiling test. Adverse changes in conditions (primarily oil or gas
price declines) could result in permanent write-downs in the carrying value of
oil and gas properties as well as non-cash charges to operations, but would not
affect cash flows.
Estimates of Proved Oil and Gas Reserves. An independent petroleum engineer
annually estimates 100% of our proved reserves. Reserve engineering is a
subjective process that is dependent upon the quality of available data and the
interpretation thereof. In addition, subsequent physical and economic factors
such as the results of drilling, testing, production and product prices may
justify revision of such estimates. Therefore, actual quantities, production
timing, and the value of reserves may differ substantially from estimates. A
reduction in proved reserves would result in an increase in depreciation,
depletion and amortization ("DD&A") expense.
Estimates of Asset Retirement Obligations. In accordance with SFAS No 143, we
make estimates of future costs and the timing thereof in connection with
recording our future obligations to plug and abandon wells. Estimated
abandonment dates will be revised in the future based on changes to related
economic lives, which vary with product prices and production costs. Estimated
plugging costs may also be adjusted to reflect changing industry experience.
Increases in operating costs and decreases in product prices would increase the
estimated amount of the obligation and increase DD&A expense. Cash flows would
not be affected until costs to plug and abandon were actually incurred.
Fair value of debt and equity transactions. Many of our various debt and equity
transactions require us to determine the fair value of a debt or equity
instrument in order to properly record the transaction in our financial
statements. We have not utilized independent third parties to assist us in
determining the fair value of many of our transactions. Fair value is generally
determined by applying widely acceptable valuation models, (e.g., the
Black-Scholes options valuation model) using the trading price of the underlying
instrument or by comparison to instruments with comparable maturities and terms.
New Accounting Pronouncements. In December 2004, the FASB issued Statement of
Financial Accounting Standards No. 123R "Shared Based Payment" ("SFAS 123R").
This statement is a revision of SFAS Statement No. 123 "Accounting for
Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and its related implementation guidance. SFAS 123R
addresses all forms of shared based compensation ("SBP") awards, including
shares issued under employee stock purchase plans, stock options, restricted
stock and stock appreciation rights. Under SFAS 123R, SBP awards result in a
cost that will be measured at fair value on the awards' grant date, based on the
estimated number of awards that are expected to vest and will be reflected as
compensation cost in the historical financial statements. This statement is
effective for public entities that file as small business issuers as of the
beginning of the first interim or annual reporting period that begins after
December 15, 2005. The Company plans to adopt SFAS No. 123R on July 1, 2006 and
we estimate that our stock compensation cost will increase by a material amount.
However, due to the non-cash nature of this charge, adoption of SFAS No. 123R
will have no impact on our cash position.
On March 29, 2005, the SEC released Staff Accounting Bulletin 107 ("SAB 107"),
providing additional guidance in applying the provisions of SFAS 123(R). SAB 107
should be applied when adopting SFAS 123(R) and addresses a wide range of
issues, focusing on valuation methodologies and the selection of assumptions. In
addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC
guidance.
On September 13, 2006, the SEC released Staff Accounting Bulletin 108 ("SAB
108") providing interpretive guidance on how the effects of the carryover or
reversal of prior year misstatements should be considered in quantifying a
current year misstatement. There have been two common approaches used to
quantify such errors. Under one approach, the error is quantified as the amount
by which the current year income statement is misstated. The other common
approach quantifies the error as the cumulative amount by which the current year
balance sheet is misstated. Exclusive reliance on an income statement approach
can result in a registrant accumulating errors on the balance sheet that may not
have been material to any individual income statement, but which nonetheless,
may misstate one or more balance sheet accounts. Similarly, exclusive reliance
on a balance sheet approach can result in a registrant disregarding the effects
of errors in the current year income statement that result from the correction
of an error existing in previously issued financial statements. The SEC staff
believes that registrants should quantify errors using both a balance sheet and
an income statement approach and evaluate whether either approach results in
quantifying a misstatement that, when all relevant quantitative and qualitative
factors are considered, is material.
This Form 10-KSB includes certain statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended. All statements included in this Form 10-KSB, other than statements
of historical facts, address matters that the Company reasonably expects,
believes or anticipates will or may occur in the future. Such statements are
subject to various assumptions, risks and uncertainties, many of which are
beyond the control of the Company. Investors are cautioned that any such
statements are not guarantees of future performance and actual results or
developments may differ materially from those described in the forward-looking
statements. The Company bases its forward-looking statements on information
currently available and it undertakes no obligation to update them.
Item 7. Financial Statements.
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of June 30, 2006 and 2005.
Consolidated Statements of Operations for the Twelve Months ended June 30, 2006
and 2005.
Consolidated Statements of Stockholders' Equity for the Twelve Months ended June
30, 2006 and 2005.
Consolidated Statements of Cash Flows for the Twelve Months ended June 30, 2006
and 2005.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
June 30,
--------------------------
2006 2005
----------- -----------
Assets
Current Assets:
Cash $ 9,893,547 $ 2,548,688
Accounts receivable, trade 132,371 300,761
Inventories 76,917 222,470
Prepaid expenses 157,629 84,304
Retainers and deposits 60,895 56,335
----------- -----------
Total current assets 10,321,359 3,212,558
Cash in qualified intermediary account for "like-kind" exchanges 34,662,368 0
Oil & Gas properties - full cost 3,878,551 5,276,303
Oil & Gas properties - not amortized 52,098 61,887
Less: accumulated depletion (371,624) (313,391)
----------- -----------
Net oil & gas properties 3,559,025 5,024,799
Furniture, fixtures and equipment, at cost 16,561 12,113
Less: accumulated depreciation (7,998) (3,401)
----------- -----------
Net furniture, fixtures, and equipment 8,563 8,712
Restricted deposits 326,835 863,089
Other assets 79,808 356,066
----------- -----------
Total assets $48,957,958 $ 9,465,224
=========== ===========
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 310,272 $ 240,389
Accrued liabilities 473,782 276,470
Notes payable, current 0 6,754
Income taxes payable 2,978,650 0
Royalties payable 47,054 89,713
----------- -----------
Total current liabilities 3,809,758 613,326
Long term liabilities:
Notes Payable, net of discount 0 2,906,548
Deferred income taxes payable 13,101,350 0
Asset retirement obligations 123,679 433,250
----------- -----------
Total liabilities 17,034,787 3,953,124
Common Stock, totaling 351,333 shares subject to demand registration rights 790,500 0
Stockholders' equity:
Common Stock, par value $0.001 per share; 100,000,000 shares authorized,
26,300,664 and 24,774,606, issued and outstanding as of June 30, 2006 and
June 30, 2005, respectively, net of 351,333 shares of common stock subject
to demand registration rights 26,300 24,774
Additional paid-in capital 10,274,555 9,611,767
Deferred stock based compensation (265,167) (595,283)
Accumulated income / (deficit) 21,096,983 (3,529,158)
----------- -----------
Total stockholders' equity 31,132,671 5,512,100
Total liabilities and stockholders' equity $48,957,958 $ 9,465,224
=========== ===========
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
Years Ended June 30,
-------------------------
2006 2005
----------- -----------
Revenues:
Oil sales $ 2,450,676 $ 1,335,288
Gas sales 424,190 358,433
Price risk management activities (13,452) (58,534)
----------- -----------
Total revenues 2,861,414 1,635,187
Operating Costs:
Production expenses 1,725,760 874,876
Production taxes 86,562 68,386
Depreciation, depletion and amortization 407,467 260,124
General and administrative (includes non-cash stock based
compensation expense of $546,567 and $707,117 for the years ended
June 30, 2006 and 2005) 2,826,085 2,220,780
----------- -----------
Total operating costs 5,045,874 3,424,166
Loss from operations (2,184,460) (1,788,979)
Other income and (expense):
Interest income 165,313 11,709
Interest expense (2,600,180) (387,301)
Gain on sale of assets 45,325,468 0
----------- -----------
Total other income and (expense) 42,890,601 (375,592)
----------- -----------
Income / (loss) before income taxes 40,706,141 (2,164,571)
Income tax expense:
Current 2,978,650 0
Deferred 13,101,350 0
----------- -----------
Total income tax expense 16,080,000 0
----------- -----------
Net income (loss) $24,626,141 $(2,164,571)
=========== ===========
Earnings/ (Loss) per common share
Basic $ 0.98 $ (0.09)
=========== ===========
Diluted $ 0.96 $ (0.09)
=========== ===========
Weighted average number of common share
Basic 25,031,125 23,533,922
=========== ===========
Diluted 25,555,992 23,533,922
=========== ===========
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flow
Twelve Months Ended Twelve Months Ended
June 30, 2006 June 30, 2005
------------------- -------------------
Cash flows from operating activities:
Net Income / (loss) $ 24,626,141 $(2,164,571)
Adjustments to reconcile net income / (loss) to net cash
used by operating activities:
Gain on asset sale (45,208,532) 0
Depletion 402,870 257,882
Depreciation 4,597 2,242
Non-cash stock based compensation expense 546,567 707,117
Amortization of deferred financing costs 293,797 0
Accretion of asset retirement obligations 27,716 21,824
Accretion of debt discount and non-cash loan costs 1,739,046 78,882
Non-cash penalty expense 240,000 0
Changes in assets and liabilities:
Accounts receivable 168,390 (276,374)
Retainer and deposits (4,560) 0
Inventories 145,553 (106,611)
Accounts payable 69,883 101,201
Royalties payable (42,659) 89,713
Accrued liabilities 247,312 226,397
Income taxes payable 16,080,000 0
Prepaid expenses (73,325) (15,237)
------------ -----------
Net cash used by operating activities (737,204) (1,077,535)
Cash flows from investing activities:
Development of oil and gas properties (2,611,369) (503,394)
Acquisitions of oil and gas properties (1,448,239) (1,554,149)
Proceeds from asset sale 49,993,134 0
Cash in qualified intermediary account for "like-kind" exchanges (34,662,368) 0
Capital expenditures for furniture, fixtures and equipment (4,448) (9,022)
Restricted deposits 536,254 (612,589)
Other assets 19,661 (99,469)
------------ -----------
Net cash provided (used) in investing activities 11,822,625 (2,778,623)
Cash flow from financing activities:
Payments on notes payable (5,634,654) (1,725,167)
Proceeds from notes payable 1,040,764 3,806,678
Deferred financing costs (37,201) (279,924)
Proceeds from issuance of common stock and fair value of
warrants issued with debt 999,385 4,729,091
Transaction & registration costs (108,856) (493,663)
------------ -----------
Net cash provided (used) by financing activities (3,740,562) 6,037,015
------------ -----------
Net increase in cash and cash equivalents 7,344,859 2,180,857
Cash and cash equivalents, beginning of period 2,548,688 367,831
------------ -----------
Cash and cash equivalents, end of period $ 9,893,547 $ 2,548,688
============ ===========
Supplemental disclosure of cash flow information:
Interest paid $ 567,273 $ 308,419
Income taxes paid $ 0 $ 0
Non-cash transactions:
Non-cash equity adjustment $ 50,000 $ 0
Assumption of asset retirement obligations $ 0 $ 99,984
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the twelve months ended June 30, 2006 and June 30, 2005
Additional Deferred Stock Accumulated Total
Paid-in Based Income / Stockholders'
Shares Dollars Capital Compensation (Deficit) Equity
---------- -------- ---------- -------------- ----------- -------------
Balances, June 30, 2004 22,945,406 22,945 4,453,905 (378,136) (1,364,587) 2,734,127
Sales of common stock 1,829,200 1,829 4,502,517 -- -- 4,504,346
Fair value of warrants issued
with debt -- -- 1,149,008 -- -- 1,149,008
Transaction and registration
costs -- -- (493,663) -- -- (493,663)
Deferred compensation -- -- -- (217,147) -- (217,147)
Net loss -- -- -- -- (2,164,571) (2,164,571)
Balances, June 30, 2005 24,774,606 24,774 9,611,767 (595,283) (3,529,158) $ 5,512,100
Sales and issuances of common
stock 599,327 599 1,005,073 -- -- 1,005,672
Reduction of capital related to
common stock, subject to demand
registration rights (351,333) (351) (790,149) (790,500)
Exercise of warrants 1,278,064 1,278 -- -- -- 1,278
Fair value of warrants issued
with debt -- -- 209,236 -- -- 209,236
Transaction and registration
costs -- -- 238,628 -- -- 238,628
Deferred compensation -- -- -- 330,116 -- 330,116
Net Income -- -- -- -- 24,626,141 24,626,141
Balances, June 30, 2006 26,300,664 $26,300 10,274,555 ($265,167) 21,096,983 $31,132,671
See accompanying notes to consolidated financial statements.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Company's Business
Reality Interactive, Inc. (" Reality "), a Nevada corporation that traded on the
OTC Bulletin Board under the symbol RLYI.OB, and the predecessor of Natural Gas
Systems, Inc., now Evolution Petroleum Corporation, was incorporated on May 24,
1994 for the purpose of developing technology-based knowledge solutions for the
industrial marketplace. On April 30, 1999, Reality ceased business operations,
sold substantially all of its assets and terminated all of its employees.
Subsequent to ceasing operations, Reality explored other potential business
opportunities to acquire or merge with another entity, while continuing to file
reports with the SEC. During the two years prior to May 26, 2004, Reality
represented that it had not conducted any operations and had minimal assets and
liabilities.
On May 26, 2004, Natural Gas Systems, Inc., a privately owned Delaware
corporation formed in September of 2003 (" Old NGS "), was merged into a wholly
owned subsidiary of Reality and Reality changed its name to Natural Gas Systems,
Inc. On the effective date of the merger, Laird Q. Cagan was elected as Chairman
of the Board of Directors of Reality and Robert S. Herlin and Sterling H.
McDonald, the CEO and CFO of Old NGS, were elected CEO and CFO of Reality,
respectively. The corporation was renamed Natural Gas Systems, Inc. ("we", "us",
"our", "our company", "Company" or "NGS") and adopted a June 30 fiscal year end.
Natural Gas Systems, Inc changed its name to "Evolution Petroleum Corporation"
(AMEX: EPM) effective July 11, 2006, to avoid potential confusion with similar
names traded on the AMEX and to better reflect our business model. The change
was effected pursuant to an Agreement and Plan of Merger dated as of July 11,
2006 by which Evolution Petroleum Corporation, a Nevada corporation and
wholly-owned subsidiary of the Company, merged with and into the Company, with
the Company as the surviving entity and renamed as "Evolution Petroleum
Corporation." This statutory short-form merger and name change was effectuated
without shareholder approval in accordance with the provisions of Section
92A.180 of the Nevada Revised Statutes. The Company's Board of Directors
authorized this transaction on June 26, 2006.
Headquartered in Houston, Texas, Evolution Petroleum Corporation is a petroleum
company engaged primarily in the acquisition, exploitation and development of
properties for the production of crude oil and natural gas. We acquire
established oil and gas properties and exploit them through the application of
conventional and specialized technology to increase production, ultimate
recoveries, or both. At June 30, 2006, we conducted our operations through our
100% working interest in the Tullos Urania field, Crossroads field and Colgrade
fields (collectively, the "Tullos Field Area"), and our non-operated royalty,
overriding royalty and back-in working interests in the Delhi Field, all located
in Louisiana.
All regulatory filings and other historical information prior to May 26, 2004
apply to Reality, the predecessor of the Company. EPM trades on the American
Stock Exchange under the symbol "EPM".
2. Significant Risks and Uncertainties
Preparation of our financial statements requires management to make estimates
and assumptions that affect the reported amounts of assets, liabilities and
contingencies as of the balance sheet date, and the reported amount of revenues
and expenses during the reporting period. On an ongoing basis, management
reviews its estimates, including those related to litigation, environmental
liabilities, income taxes, abandonment costs and the determination of proved
reserves. Changes in circumstances may result in revised estimates and actual
results may differ from those estimates.
Our business makes us vulnerable to changes in crude oil and natural gas prices.
Such prices have been volatile in the past and can be expected to be volatile in
the future. This volatility can dramatically affect cash flows and proved
reserves, since price declines reduce the estimated quantity of proved reserves
and increase annual amortization expense (which is based on proved reserves), or
could potentially result in an impairment charge. Other risks related to proved
reserves, revenues, and cash flows include our current reliance on the
concentration of a few wells.
3. Summary of Significant Accounting Policies
Principles of Consolidation -- Our consolidated financial statements include the
Company and its subsidiaries. All material inter-company accounts and
transactions have been eliminated.
Oil and Gas Properties and Furniture, Fixtures and Equipment -- We follow the
full cost method of accounting for its investments in oil and natural gas
properties. All costs incurred in the acquisition, exploration and development
of oil and natural gas properties, including unproductive wells, are
capitalized. Proceeds from the sale of oil and natural gas properties are
credited to the full cost pool, unless the sale involves a significant quantity
of reserves, in which case a gain or loss is recognized. Under the rules of the
Securities and Exchange Commission ("SEC") for the full cost method of
accounting, the net carrying value of oil and natural gas properties is limited
to the sum of the present value (10% discount rate) of the estimated future net
cash flows from proved reserves based on current prices as of the balance sheet
date, and excluding future cash outflows associated with settling asset
retirement obligations, plus the lower of cost or estimated fair market value of
unproved properties adjusted for related income tax effects.
Capitalized costs of proved oil and natural gas properties are depleted on a
unit of production method using proved oil and natural gas reserves. Costs
depleted include net capitalized costs subject to depletion and estimated future
dismantlement, restoration and abandonment costs.
The costs of certain unevaluated leasehold acreage and wells being drilled are
not being amortized. Costs not being amortized are periodically assessed for
possible impairments or reductions in value. If a reduction of value has
occurred, the amount of the impairment is transferred to costs being amortized.
Equipment, which includes computer equipment, hardware and software and
furniture and fixtures, is recorded at cost and is generally depreciated on a
straight-line basis over the estimated useful lives of the assets, which range
from two to five years.
Repairs and maintenance are charged to expense as incurred.
Statement of Cash Flows -- For purposes of the statements of cash flows, cash
equivalents include highly liquid financial instruments with maturities of three
months or less as of the date of purchase.
Concentrations of Credit Risk -- Financial instruments which potentially expose
us to concentrations of credit risk consist primarily of trade accounts
receivable. Our customer base is highly concentrated, even though our oil and
gas products are highly marketable. Although we are directly affected by the
well-being of the oil and gas industry, management does not believe a
significant credit risk exists at June 30, 2006.
Revenue Recognition --We recognize oil and natural gas revenues from our
interests in producing wells at the time oil and natural gas is sold. As a
result, we accrue revenues related to production sold for which we have not
received payment.
Accounts Receivable, trade - Accounts receivable, trade consists of
uncollateralized accrued oil and gas revenues due under normal trade terms,
generally requiring payment within 30 days of production. Management reviews
receivables periodically and reduces the carrying amount by a valuation
allowance that reflects management's best estimate of the amount that may not be
collectible. As of June 30, 2006 and 2005, the valuation allowance was $0.
Inventory - Inventory, which is included in current assets, includes tubular
goods and other lease and well equipment which we plan to utilize in our ongoing
development activities and is generally carried at the lower of cost or market
using the specific identification method.
Stock Options --SFAS 123, "Accounting for Stock-Based Compensation," as amended
by SFAS 148, "Accounting for Stock-Based Compensation--Transition and
Disclosure," established accounting and disclosure requirements using a fair
value-based method of accounting for stock-based employee compensation plans. We
account for stock-based compensation using the intrinsic value method prescribed
in Accounting Principles Board Opinion 25, "Accounting for Stock Issued to
Employees" ("APB 25").
Fair Value of Financial Instruments --Our financial instruments consist of cash
and cash equivalents, accounts receivable, accounts payable, derivatives, notes
payable and seller notes. The carrying amounts of cash and cash equivalents,
derivative, accounts receivable and accounts payable approximate fair value due
to the highly liquid nature of these short-term instruments. The fair value of
the notes payable to Prospect Energy approximates the carrying value of the
notes as the effective interest rates applicable to the notes approximates
current rates available to us for comparable financing arrangements.
Accounting for Price Risk Management activities - We enter into certain
financial derivative contracts utilized for non-trading purposes to minimize the
impact of market price fluctuations on contractual commitments and forecasted
transactions related to our oil and gas production. We follow the provisions of
the Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities, for the accounting of our hedge
transactions. SFAS No. 133 establishes accounting and reporting standards
requiring that all derivatives instruments be recorded in the consolidated
balance sheet as either as an asset or liability measured at fair value and
requires that the changes in the fair value be recognized currently in our
earnings unless specific hedge accounting criteria is met.
Upon adoption, we did not have any financial derivative contracts utilized for
non-trading purposes. Thus, the adoption of SFAS No. 133 had no impact on us. We
have entered into certain over-the-counter contracts to hedge the cash flow of
part of our forecasted sale of oil and gas production. We did not elect to
document and designate these as hedges. Thus, the changes in the fair value of
these over-the-counter contracts are reflected in the earnings in the period in
which they occur.
Income taxes - Income taxes are provided for the tax effects of transactions
reported in the financial statements and consist of taxes currently due, if any,
plus net deferred taxes related primarily to differences between basis of assets
and liabilities for financial and income tax reporting. Deferred tax assets and
liabilities represent the future tax return consequences of those differences,
which will either be taxable or deductible when the assets and liabilities are
recovered or settled. Deferred tax assets include recognition of operating
losses that are available to offset future taxable income and tax credits that
are available to offset future income taxes. Valuation allowances are recognized
to limit recognition of deferred tax assets where appropriate. Such allowances
may be reversed when circumstances provide evidence that the deferred tax assets
will more likely than not be realized.
Earning (loss) per share - Basic and diluted earning per share calculations are
presented in accordance with FASB 128, and are calculated on the basis of the
weighted average number of common shares outstanding during the year. They
include the dilutive effect of common stock equivalents in years with net income
New Accounting Pronouncements - In December 2004, the FASB issued Statement of
Financial Accounting Standards No. 123R "Shared Based Payment" ("SFAS 123R").
This statement is a revision of SFAS Statement No. 123 "Accounting for
Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and its related implementation guidance. SFAS 123R
addresses all forms of shared based compensation ("SBP") awards, including
shares issued under employee stock purchase plans, stock options, restricted
stock and stock appreciation rights. Under SFAS 123R, SBP awards result in a
cost that will be measured at fair value on the awards' grant date, based on the
estimated number of awards that are expected to vest and will be reflected as
compensation cost in the historical financial statements. This statement is
effective for public entities that file as small business issuers as of the
beginning of the first annual reporting period that begins after December 15,
2005. The Company plans to adopt SFAS No. 123R on July 1, 2006 and we estimate
that our stock compensation cost will increase by a material amount; however due
to the non-cash nature of this charge, adoption of SFAS No. 123R will have no
impact on our cash position.
On March 29, 2005, the SEC released Staff Accounting Bulletin 107 ("SAB 107")
providing additional guidance in applying the provisions of SFAS 123(R). SAB 107
should be applied when adopting SFAS 123(R) and addresses a wide range of
issues, focusing on valuation methodologies and the selection of assumptions. In
addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC
guidance.
4. Acquisitions and Divestitures
On January 31, 2006, we acquired from an unrelated third party an overriding
royalty interest of 4.811195% in the Delhi Holt Bryant Unit ("Delhi Unit")
within the Delhi Field. Funding of the $1.0 million purchase price was provided
by an additional $1.0 million advance under our Prospect Facility, thereby
increasing the maturity value of our note due at maturity to $6.0 million, and
the issuance of an additional 150,000 of irrevocable warrants and 100,000 of
revocable warrants, exercisable over five years at the 20 trading day average
price immediately prior to January 31 2006. The Prospect facility was repaid in
full on May 31, 2006. See Note 7 for more about the repayment of the Facility.
In June 2006, we acquired from various unrelated third parties, additional
royalty and overriding royalty interests totaling 2.2048% in the Delhi Holt
Bryant Unit. Funding of the approximate $464,000 purchase price was provided by
the approximate $50 million in proceeds received from the sale of our working
interest in the Delhi Field to a subsidiary of Denbury Resources Inc. See below
for more about the divestiture.
Also in June 2006, another unrelated party agreed to sell us their royalty and
overriding royalty interests aggregating 0.38919% in the Delhi Holt Bryant Unit
for approximately $85,000. The closing of this acquisition occurred on July 21,
2006. Funding was provided by the proceeds from the asset sale mentioned above.
Acquisitions were recorded using the purchase method of accounting and,
accordingly, results of operations of these acquired activities and oil and gas
properties have been included in our results of operations from the respective
closing dates of the acquisitions.
As previously reported in a Current Report on Form 8-K filed by the Company with
the SEC on May 11 and June 16, 2006, we conveyed a farmout to Denbury Onshore,
LLC., a subsidiary of Denbury Resources, Inc. (NYSE: DNR, hereinafter referred
to as "Denbury" or "DNR") to conduct a CO2 enhanced oil recovery project in the
Delhi Holt Bryant Unit within the Delhi Field in northeast Louisiana (the "Delhi
Farmout"). On June 12, 2006, we received $50 million and delivered to Denbury
all of our working interests and an 80% net revenue interest in the Delhi Holt
Bryant Unit, and a 75% working interest and a 60% net revenue interest in
certain other depths in the Delhi Field. We retained 7.4% in separately acquired
royalty and overriding royalty interests in the Delhi Holt Bryant Unit as
discussed above and a 25% working interest (20% net revenue interest) in certain
other depths of the Delhi Field outside of the Delhi Holt Bryant Unit. Under the
terms of the Delhi Farmout, Denbury has agreed to contribute all development
capital, technical expertise and required amounts of proven reserves of carbon
dioxide that will be injected into the Delhi Holt Bryant Unit oil reservoirs.
After the project generates $200 million of net cash flows before capital
expenditures for Denbury, we will regain a 25% working interest (20% net revenue
interest) in the Delhi Holt Bryant Unit.
5. Asset Retirement Obligations
Asset retirement obligations are included in long term liabilities on our
balance sheet. The following table describes the change in our asset retirement
obligations for the periods from June 30, 2005 to June 30, 2006:
Asset retirement obligation at June 30, 2005 $ 433,250
Liabilities incurred 0
Accretion expense for 2006 27,716
Revisions to estimates during 2006 (property divestiture) (337,287)
---------
Asset retirement obligation at June 30, 2006 $ 123,679
On June 12, 2006, we closed the Delhi Farmout. Consequently, once the change of
operator has been filed by the new operator with the State of Louisiana and they
establish their own Site Specific Trust Account, we will seek release of our
collateralized certificate of deposit from the State and receive a refund of
approximately $326,000.
6. Oil and Gas Properties
Depletion expense for the twelve months ended June 30, 2006 and June 30, 2005
totaled $402,870 and $257,882, respectively. Also, as of June 30, 2006 and 2005,
unamortized capital expenditures totaled $52,098 and $61,887, respectively.
These costs are reviewed quarterly to determine when they should be transferred
to the full cost pool and amortized.
7. Notes Payable
The following table sets forth the Company's notes payable balances as of the
dates indicated:
Borrowing June 30, 2006 June 30, 2005
-------------------------------- ------------- -------------
Cananwill Insurance Premium Loan -- 6,754
Prospect Energy Note -- 2,906,548
--- ----------
Total Outstanding $-- $2,913,302
CANANWILL LOAN: At June 30, 2005, $6,754 was owed under the Cananwill Insurance
Premium Loan. The balance of $6,754 was paid in October 2006.
LOAN: In March 2006, Laird Q. Cagan, our Chairman and a major stockholder,
loaned us $250,000 pursuant to an unsecured note bearing interest at 10% per
annum. The funds were used for corporate and working capital purposes. On June
12, 2006, we repaid the Loan, totaling $257,058 with accrued interest, in full.
PROSPECT ENERGY NOTE: On February 3, 2005, we closed the "Prospect Facility" (or
"Facility") and drew down $3,000,000, and on March 16, 2005 we drew down an
additional $1,000,000 against a $4,800,000 total commitment. The draws were used
to fund the February 2005 acquisition of properties in Louisiana, costs of the
financing, funding of a debt service reserve fund, repayment of a bridge loan,
immediate re-development of our existing properties and for working capital
purposes.
At June 30, 2005, we owed $2,906,548 on the Prospect Facility, including the
accreted discount through such date. At maturity or, exclusive of any prepayment
penalty, on early prepayment, the total amount owed under the Facility was
$4,000,000 due to accretion of the original issue discount.
During fiscal year 2006, we borrowed another $1,000,000 in maturity value of
loans from Prospect to fund the acquisition of an overriding royalty interest in
the Delhi Holt Bryant Unit, recording approximately $0.8 million of the proceeds
to loans payable and $0.2 million of the proceeds to equity from the warrants we
attached. On May 31, 2006, we voluntarily repaid the Prospect loan in full,
including a prepayment penalty, offset by release of $0.56MM held in a
restricted Debt Service Reserve account.
8. Common Stock, Stock Options and Warrants
Common Stock
During the twelve months ended June 30, 2006, we raised gross proceeds of
$790,500 from the sale of our common stock in a private equity offering and
$209,235 from the issuance of warrants to Prospect with respect to their
additional loan. A total of 351,335 shares were sold at a price of $2.25 per
share. We paid Chadbourn Securities and Laird Q. Cagan, a placement agent fee
consisting of (i) cash equal to 8% of the gross proceeds, or $63,240 and (ii)
warrants exercisable for up to 14,054 shares of our common stock at an exercise
price of $2.25 per share.
As part of the repayment of the Prospect loan, Prospect demanded payment of an
additional 100,000 warrants exercisable at a price of $2.71 per share. While we
disagreed with the justification for the demand, we elected to issue the
warrants. Since Prospect elected to immediately exercise the warrants, the
impact of the issuance of the disputed warrants was negligible.
During the fiscal year 2006, we issued an aggregate 88,000 shares of common
stock to individual consultants for services rendered; issued 160,000 shares of
common stock to Rubicon as compensation for not securing an effective
registration on previously issued shares per the agreement; and lastly, various
holders exercised their warrants into 1,278,064 shares of common stock.
During the twelve months ended June 30, 2005, we raised gross proceeds of
$4,729,091 from the sale of our common stock, warrants to purchase our common
stock and direct stock grants, less placement fees of $257,840 paid to Chadbourn
Securities and Laird Q. Cagan and warrants to purchase 108,536 shares. In
addition, we also paid $32,659 to unrelated third parties as finder's fees. Of
the total, $3,580,083 was received from the sale of 1,594,200 shares of our
common stock and the issuance of 235,000 shares of our common stock upon the
exercise of options and direct stock awards granted under our 2004 Stock Plan.
The remaining $1,149,008 was raised through the sale of warrants to Prospect
Energy.
Options and Warrants issued to Employees
2003 Stock Option Plan
Old NGS adopted a stock option plan in 2003 (the "2003 Plan"). The purpose of
the 2003 Plan was to offer selected individuals an opportunity to acquire a
proprietary interest in the success of Old NGS, or to increase such interest, by
purchasing shares of the Old NGS common stock.
The 2003 Plan provided both for the direct award or sale of shares and for the
grant of options to purchase shares in an aggregate amount not to exceed
4,000,000 shares. Options granted under the Plan included non-statutory options
as well as incentive stock options intended to qualify under Section 422 of the
Internal Revenue Code. Of the options to purchase 600,000 shares granted under
the 2003 Plan by Old NGS, all were assumed by Reality Interactive, Inc.,
predecessor to the Company. Of these, options to purchase 250,000 shares were
granted to each of Messrs. Herlin and McDonald. These options were accounted for
under APB 25, giving rise to $437,250 of expense, spread over a four year
vesting schedule.
2004 Stock Plan
On August 3, 2004, we adopted our 2004 Stock Plan (the "2004 Plan"). The purpose
of the 2004 Plan is to offer selected individuals an opportunity to acquire a
proprietary interest in our success, or to increase such interest, by purchasing
our shares of common stock. The 2004 Plan provides both for the direct award or
sale of shares and for the grant of options or warrants to purchase shares in an
aggregate amount not to exceed 4,000,000 shares. Options granted under the 2004
Plan may include non-statutory options as well as incentive stock options
intended to qualify under Section 422 of the Internal Revenue Code.
During the twelve months ended June 30, 2006, the company awarded stock options
to purchase 761,000 shares of common stock upon exercise of outstanding options
under the 2004 Stock Plan to employees and directors, all subject to various
vesting requirements, leaving 1,494,000 shares of common stock available for
issuance under the 2004 Stock Plan, after taking into account awards to
non-employees totaling 50,000 shares.
Non-Plan Warrants to Employees
During the twelve months ended June 30, 2006, as part of their annual incentive
compensation and in lieu of cash bonuses, Mr. Herlin was awarded warrants to
purchase 400,000 shares of common stock and Mr. McDonald was awarded warrants to
purchase 150,000 shares. These warrants were granted at "at the money" on the
grant date and have a four year vesting term and a contractual life of 10 years.
A reconciliation of reported income (loss) as if the Company used the fair value
method of accounting for stock-based compensation computed under FASB 123 as
compared to the compensation expense we recorded under APB 25 follows:
Twelve Months ended Twelve Months ended
June 30, 2006 June 30, 2005
------------------- -------------------
Net income / (loss) attributable to common stockholders, as reported $ 24,626,141 ($2,164,571)
Plus: share based compensation expense determined under APB 25 171,537 131,313
Less: compensation expense determined under Fair Value Method (1,543,690) (359,457)
------------- ------------
Pro forma net income / (loss) attributable to common stockholders $ 23,253,988 ($2,392,715)
============= ============
Basic earnings / (loss) per common share:
As reported $0.98 ($0.09)
============= ============
Pro Forma $0.93 ($0.10)
============= ============
Diluted earnings / (loss) per common share:
As reported $0.96 ($0.09)
============= ============
Pro Forma $0.91 ($0.10)
============= ============
Weighted average Black-Scholes fair value assumptions:
Risk free interest rate 4.18% - 4.93% 4.18% - 4.93%
Expected life 2-4 years 3-4 years
Expected volatility 104% - 159% 104% - 130%
Expected dividend yield 0.0% 0.0%
Fair values were estimated at the date of grant using the Black-Scholes options
pricing model, based on the assumptions above. For purposes of the pro forma
disclosures, the estimated fair value is amortized to expense over the awards'
vesting period. The Black-Scholes option valuation model was developed for use
in estimating the fair value of traded options which have no vesting
restrictions and are fully transferable. In addition, option valuation models
require the input of highly subjective assumptions including the expected stock
price volatility. Because the Company's employee stock options have
characteristics significantly different from those of traded options, and
because changes in the subjective input assumptions can materially affect the
fair value estimate, in management's opinion, the existing models do not
necessarily provide a single measure of the fair value of its employee stock
options. At June 30, 2006, 1,494,000 shares were available for grant under the
plans.
A summary of option and warrant transactions issued to employees for the period
from July 1, 2004 to June 30, 2006 follows:
Weighted Weighted Weighted average
average average Grants Remaining
Number of Shares Exercise Price Date Fair Value Contractual Life
---------------- -------------- --------------- ----------------
Beginning balance 500,000 $0.13 9.3 years
Twelve months ended June 30, 2005
Granted 2,012,500 $1.71 $1.31
Exercised
Canceled
Outstanding at June 30, 2005 2,512,500 $1.39 9.4 years
Twelve months ended June 30, 2006
Granted 1,311,000 $1.70 $1.43
Exercised
Canceled
Outstanding at June 30, 2006 3,823,500 $1.50 9.6 years
These options and warrants vest during the following fiscal years ended as
follows: Vested at June 30, 2005: 303,125; 2006: 1,001,250; 2007: 935,375; 2008:
801,250; 2009: 641,875 and 2010: 140,625.
Options, Warrants and Grants to Non-Employees
At June 30, 2006, outstanding warrants and options, excluding employees, to
purchase the Company's common shares were as follows:
Warrants and Stock Options Outstanding
(excludes employees)
----------------------------------------------------
Range of Outstanding at Exercisable at
Holders Exercisable Prices June 30, 2006 June 30, 2006
---------------------------------- ------------------ -------------- --------------
Cagan McAfee Capital Partners, LLC $ 1.00 $1.00 165,000 165,000
Chadbourn Securities, Inc. $ 1.50 $2.50 9,463 9,463
Laird Q. Cagan $ 1.00 $2.50 171,308 171,308
Steven D. Lee $0.001 $1.80 110,000 79,444
Others $ 1.00 $2.00 94,750 94,750
------- -------
Total 550,521 519,965
During fiscal year ended June 30, 2006, we issued warrants to purchase 14,054
shares of common stock in connection with capital raising services to Laird Q.
Cagan and Chadbourn Securities, Inc., and a stock option to purchase 50,000
shares to Steve D. Lee under the 2004 Stock Plan. Mr. Lee's grant gives rise to
$39,275 of share based compensation expense under SFAS 123, to be spread over a
six month vesting term, beginning March 2006. Fair value was derived using the
Black-Scholes model using the following assumptions: Volatility - 150%, Risk
Free Rate - 4.50%, Estimated Term - 1 year, and Dividends - 0.
In addition, the Company also made direct stock grants for 78,000 shares to
Liviakis Communications for investor relations services and a direct stock grant
for 10,000 shares to a third party consultant for services rendered. (Both
grants are excluded from the table above) The Liviakis stock grant gave rise to
$204,282 of expense, spread over a six month vesting schedule, beginning monthly
in May 2006, and the consultant stock grant gives rise to $12,091 of immediate
expense. The fair value of both direct stock grants under SFAS 123 was
equivalent to the fair value of our stock on the date of grants.
During the fiscal year ended 2006, 1,864,500 warrants were (cashless) exercised
resulting in 1,278, 064 shares of common stock issued.
Registration Rights
Under the terms of our private placement of 1,200,000 shares of our common stock
with the Rubicon Fund on May 6, 2005, we contemporaneously entered into a
registration rights agreement (the "RRA"). The RRA required us, among other
things, to obtain and maintain an effective registration statement with the SEC
for Rubicon's shares, failing which, would have subjected us to the payment of
penalties not to exceed 1% of the share proceeds, or $30,000, for each month of
non-compliance. Penalties were to be incurred for each month for which a
registration statement had not become effective, beginning October 6, 2005.
Penalties were also to be incurred for any month for which effectiveness has not
been maintained prior to the shares becoming tradable under Rule 144, but in no
event would total penalties cumulatively exceed 8% or $240,000. In January 2006,
we entered into a mutual agreement with Rubicon that eliminated their demand
registration rights and any penalties, historic and future, in exchange for
160,000 shares of common stock.
We have also entered into registration rights agreements with others, the effect
of which gives the holders the right to "piggyback" their shares, from time to
time, as we register other shares. Alternatively, we may be required to register
shares on Form S-3 under certain conditions.
9. Related Party Transactions
Laird Q. Cagan, the Chairman of our Board of Directors, is a Managing Director
of Cagan McAfee Capital Partners, LLC ("CMCP"). CMCP performs financial advisory
services for us pursuant to a written agreement and is paid a monthly retainer,
which was $15,000 per month through October 2005 and $5,000 per month beginning
December 1, 2005, per the amended agreement. In addition, Mr. Cagan is a
registered representative of Chadbourn Securities, Inc. ("Chadbourn"), our
non-exclusive placement agent for private financings. Pursuant to the Agreement
between Mr. Cagan, Chadbourn and us, as amended, we pay a cash fee equal to 8%
of the first $1 million of gross equity proceeds and declining by 1% for each
subsequent $1MM of gross proceeds to a minimum rate of 4%, and warrants equal to
4% of the shares placed by CMCP.
During fiscal year ended June 30, 2006, we expensed and paid CMCP $95,000 for
monthly retainers, issued warrants to purchase 14,054 shares of common stock to
Laird Q. Cagan and Chadbourn Securities, Inc. and paid a $63,240 cash commission
to Chadbourn in connection with capital raising services (a substantial portion
of which we believe Mr. Cagan receives). Also, in March 2006 Mr. Cagan loaned us
$250,000, pursuant to a secured promissory note bearing interest at 10% per
annum, for general working capital purposes. On June 13, 2006, we repaid the
loan in full including accrued interest, or $257,058.
During the fiscal year ended June 30, 2005, we issued warrants to purchase
91,359 and 5,427 shares of common stock to Laird Q. Cagan and Chadbourn
Securities, Inc., respectively, in connection with capital raising services.
During the same period, we paid $257,890 cash commissions to Laird Q. Cagan and
Chadbourn Securities, Inc., in connection with capital raising activities.
Further, during fiscal year ended June 30, 2005, the Company expensed and paid
CMCP $180,000 for monthly retainers earned in fiscal 2005, and paid $60,000 for
monthly retainers earned, but unpaid, during fiscal 2004.
Also during fiscal 2005, from August through December, 2004, Mr. Cagan loaned
us, through a series of advances, $920,000, pursuant to a secured promissory
note bearing interest at 10% per annum and a 5% origination fee (the "Bridge
Loan") earmarked for our purchase of working interests in the Tullos Urania
Field in Louisiana, working capital and certain costs related to the pre-closing
of the Prospect Facility. On February 15, 2005, we repaid the Bridge Loan,
totaling $953,589 with accrued interest, in full.
10. Supplemental Disclosures about Oil and Gas Producing Properties
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to EPM's oil and gas
producing activities are summarized as follows:
Twelve Months Ended Twelve Months Ended
June 30, 2006 June 30, 2005
------------------- -------------------
Capitalized costs being amortized $3,878,551 $5,276,303
Capitalized costs not being amortized* 52,098 61,887
---------- ----------
Total 3,930,649 5,338,190
Less accumulated depletion (371,624) (313,391)
---------- ----------
Net capitalized costs $3,559,025 $5,024,799
========== ==========
* Costs not being amortized at the end of each period were excluded from the
depletion base. The costs as of June 30, 2006 are expected to be evaluated
within the next two years.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and development
activities which have been capitalized are summarized as follows:
Twelve Months Ended Twelve Months Ended
June 30, 2006 June 30, 2005
------------------- -------------------
Property acquisition costs:
Proved $1,448,239 $1,554,149
P&A liability assumed -- 99,984
Unproved (9,788) 61,887
Exploration costs -- --
Development costs 2,611,369 441,508
---------- ----------
Total $4,049,820 $2,157,528
========== ==========
Results of Operations from Oil and Gas Producing Activities (unaudited)
Our results of operations from oil and gas producing activities are presented
below for fiscal years 2006 and 2005. The following table includes revenues and
expenses associated directly with our oil and gas producing activities. It does
not include any interest costs or general and administrative costs and,
therefore, is not necessarily indicative of the contribution to consolidated net
operating results of our oil and gas operations.
Twelve Months Ended Twelve Months Ended
June 30, 2006 June 30, 2005
------------------- -------------------
Oil and gas sales $ 2,861,414 $1,635,187
Production expenses (1,725,760) (874,876)
Production taxes (86,562) (68,386)
Depletion (402,870) (257,882)
----------- ----------
Results of operations for oil and gas producing activities
(excluding corporate overhead and financing costs) $ 646,222 $ 434,043
=========== ==========
Oil and Gas Reserve Quantities (unaudited)
The following table sets forth the net proved reserves of the Company as of July
1, 2006, and the changes therein for the periods from July 1, 2004 to July 1,
2006. The reserve information was prepared by W. D. Von Gonten & Co.,
independent petroleum engineers. All of the Company's oil and gas producing
activities are located in the United States.
Oil (bbls) Gas (mcf)
---------- ---------
July 1, 2004 239,534 508,556
Purchases of minerals in place (1) 418,217 0
Extensions and discoveries 242,340 330,023
Revisions (100,978) (34,290)
Production (27,230) (72,166)
Sales of minerals in place 0 0
-------- ---------
July 1, 2005 (2) 771,883 732,123
Purchases of minerals in place 4,200 25,800
Extensions and discoveries 0 0
Revisions 138,762 0
Production (46,942) (45,368)
Sales of minerals in place (407,403) (686,755)
July 1, 2006 460,500 25,800
Proved developed reserves:
July 1, 2004(3) 239,534 508,556
July 1, 2005(4) 540,360 396,600
July 1, 2006(5) 460,500 25,800
(1) Proved developed reserves acquired in the Tullos Field Area during fiscal
2005.
(2) During fiscal 2005, the preponderance of our proved crude oil and natural
gas extensions and discoveries was due to the addition of eight proved
undeveloped reserve locations (PUDs), resulting from a six month
geological study performed by an outside geologist we engaged to review
approximately 20% of our Delhi Field. Proved crude oil additions more than
exceeded the downgrade of our acquired Tullos reserves, resulting from
poor performance related to bad weather, lack of service equipment and
lack of repairs and maintenance by the seller in the months immediately
preceding our acquisition. Elimination of our Delhi 210-2 well was
primarily offset by a decrease in the estimate of fuel use. Proved natural
gas reserve quantities include 7,300 Bbl of NGL's, converted at 6 Mcfs per
Bbl at July 1, 2005.
(3) At July 1, 2004, our proved developed natural gas reserves include 5,000
Bbls of NGL, converted at 6 Mcfs per Bbl.
(4) During fiscal 2005, our proved developed natural gas reserves were revised
downward due to the loss of our Delhi 210-2 well due to bad casing. At
July 1, 2005, our proved developed natural gas reserves included 3,500
Bbls of NGL, converted at 6 Mcf per Bbl.
(5) During fiscal 2006, our proved reserves were reduced by the Delhi Farmout,
offset by an increase in proved reserves in the Tullos Field Area due to
the increase in commodity prices and additional proved developed
non-producing reserves associated with shut-in wells.
Standardized Measure of Discounted Future Net Cash Flows at June 30, 2006 and
June 30, 2005
The information that follows has been developed pursuant to SFAS No. 69 and
utilizes reserve and production data prepared by independent petroleum
consultants. Reserve estimates are inherently imprecise and estimates of new
discoveries are less precise than those of producing oil and natural gas
properties. Accordingly, these estimates are expected to change as future
information becomes available.
The estimated discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless such prices
or costs are contractually determined at such date. Actual future prices and
costs may be materially higher or lower. Actual future net revenues also will be
affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by natural gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs. Future income tax expense has been reduced for the effect of available
net operating loss carryforwards.
June 30, 2006 June 30, 2005
------------- -------------
Future cash inflows $ 32,874,568 $ 46,841,246
Future production costs (18,167,012) (20,028,389)
Future development costs (566,000) (1,920,000)
Future income taxes (2,687,000) (6,036,000)
------------ ------------
Future net cash flows $ 11,454,556 $ 18,856,857
10% annual discount (4,943,196) (5,615,779)
------------ ------------
Standardized Measure $ 6,511,360 $ 13,241,078
============ ============
Changes in Standardized Measure
The following table sets forth the changes in standardized measure of discounted
future net cash flows for the period from the twelve months ended June 30, 2006
and 2005:
Twelve Months Ended Twelve Months Ended
June 30, 2006 June 30, 2005
------------------- -------------------
Standardized Measure, beginning $ 13,241,078 $ 5,180,611
Net changes in income taxes 1,445,256 (3,209,706)
Oil and gas sales, net of costs (1,049,092) (691,925)
Discoveries, extensions and transfers 239,382 7,131,907
Purchase of minerals in place 354,679 4,780,920
Sale of minerals in place (12,916,340) 0
Changes in prices and costs 1,403,539 3,285,724
Change in development costs 1,116,590 (1,045,275)
Accretion discount 1,324,108 518,061
Revisions of estimates 1,352,160 (2,670,979)
Other 0 (38,260)
------------ ------------
Standardized Measure, ending $ 6,511,360 $ 13,241,078
============ ============
11. Restricted Deposits
At June 30, 2006, restricted deposits totaled $326,835, representing an increase
of $25,000 and a decrease of approximately $560,000 from prior fiscal year end.
The increase was for a certificate of deposit pledged to the State of Louisiana
for future plugging and abandonment requirements for five new wells drilled as
part of the Development Drilling program in Delhi field. The decrease was the
result of early loan repayment of the Prospect Facility in May 2006. Pursuant to
the terms of our Delhi Farmout arrangement, as soon as the State of Louisiana
processes the change of operator to Denbury Onshore, LLC and Denbury funds the
Site Specific Trust Account accordingly, we will be refunded the full balance of
$326,835. Approximately $227,000 exceeds FDIC insurance limits in depository
accounts at Wells Fargo bank.
Also, at June 30, 2006, we had approximately $34.7 million (which is available
to us at any time) held in the qualified intermediary account as discussed in
note 12 below. These funds were invested in a U.S. Treasury and Agency Money
Market Fund with short-term durations.
At June 30, 2005, Restricted Deposits include $301,835 to secure a letter of
credit posted with the State of Louisiana for future plugging and abandonment
liabilities related to the Delhi Field, and $560,000 to secure the debt service
reserve under the Prospect Facility. Approximately $202,000 exceeds FDIC
insurance limits in depository accounts at Wells Fargo bank.
12. Income Taxes
The tax effect of significant temporary differences representing deferred tax
assets and liabilities at June 30, 2006 and 2005 are as follows:
2006 2005
------------ -----------
Oil and gas properties ($964,000) ($178,000)
Basis in subsidiary stock 149,000 126,000
Other 95,650 (11,000)
Gain on sale of property (12,191,000) 0
Net operating loss carryforwards 6,390,000 6,325,000
Valuation allowance (6,581,000) (6,262,000)
------------ -----------
Net deferred tax asset / (liability) ($13,101,350) $ 0
============ ===========
At June 30, 2006, we have current income tax payable of $2.98 million (split
$2.3 million for federal income taxes and $0.6 million for state income taxes
due) and a deferred non-current tax liability of approximately $13.1 million,
primarily as a result of the Delhi Farmout in which we received approximately
$50 million of pre-tax proceeds. In determining the $16.1 million of current and
non-current deferred tax liability, we used all of our $2.8 million of NOL's
generated by our oil and gas operations, and $82,600 of pre-merger Reality
NOL's.
We have established a full valuation allowance against our net deferred tax
assets totaling $6.58 million for fiscal year ended 2006, and we will continue
to take a full valuation allowance until an appropriate level of profitability
is attained. Of this amount, $6.1 million of deferred tax assets are permanently
impaired absent a change in Internal Revenue Code Section 382 legal limitations
imposed on the Reality NOL's we inherited in the merger. If not used, our
unimpaired tax assets will expire between 2010 and 2023.
On June 12, 2006, we consummated the Delhi Farmout as a completed sale for tax
purposes under advice from our tax consultants and in concert with our analysis
of the Internal Revenue Code, including Rev. Proc. 77-176, IRC Section 614
property definitions pertaining to natural resources, the IRS training manual
regarding the designation of property classifications with respect to natural
resources, General Counsel Memorandums 33552, 24094, 22106, various court case
rulings and other applicable research.
The completed sale designation was important to our ability to consummate IRC
Section 1031 like kind exchanges, thus potentially deferring federal income tax
liability by rolling the basis of the our Delhi property into similar like kind
properties we might purchase within the short timeframes allowed under current
tax law. Of the $50 million of proceeds we received from Denbury Resources for
our Delhi Farmout, we placed $35 million in a qualified intermediary ("QI")
account for possible Internal Revenue Code 1031 "like-kind exchanges" (which is
available to us at any time) and placed the remaining $15 million in an
unrestricted account which triggered immediate taxable "boot" on the $15 million
portion we received. As of June 30, 2006, we had approximately $34.7 million of
cash held in the QI account, providing us the opportunity to defer the
recognition of taxable gain on up to $35 million we received from the Delhi
Farmout in the event that like-kind property is purchased within 180 days from
the date of the outgoing property sale (being December 9, 2006) for assets
identified within 45 days of such sale. On or prior to June 30, 2006, we had
utilized $420,000 from the QI account to acquire like-kind property (partially
offset by approximately $82,000 of interest income earned on the QI account). In
the event that we choose to withdraw any funds from the qualified intermediary
account to fund non like-kind exchanges, or if we fail to use all of the funds
for like-kind exchanges prior to December 9, 2006, all of the funds remaining or
disbursed from the QI account will become subject to immediate taxable gain on
the sale of the Delhi property.
The following is a reconciliation of the Company's expected income tax expense
(benefit) based on statutory rates to the actual expense (benefit):
2006 2005
------------ ---------
Income taxes (benefit) at U.S. and state statutory rates $ 16,400,000 ($735,954)
Non-deductible amortization and expenses 0 0
Non-deductible interest expense and deferred stock compensation 508,000 240,860
Deferred tax asset valuation allowance adjustment (1,160,000) 495,094
Other 332,000 0
------------ ---------
Total $ 16,080,000 $ 0
The U. S. statutory rate is 35%. The state of Louisiana tax rate, net of federal
tax benefit is 5.2%. The blended tax rate is 40.2%
The deferred tax asset valuation allowance adjustment is due to the release of
valuation allowances from prior year NOL's, including net operating losses from
that past two fiscal years and the maximum portion of tax credits allowed under
current tax laws for Reality's NOL's. The total amount of the NOL's used in the
current year is $2.9 million, with a tax effect of approximately $1,160,000.
13. Leases
At June 30, 2006, our only operating lease obligation is for our corporate
headquarters in Houston, Texas. Minimum lease payments (i.e. rent expense)
through April 14, 2007, the expiration date of agreement, totals $33,980.
Our lease expense was $121,502 for the twelve months ended June 30, 2006 and
$121,799 for the twelve months ended June 30, 2005. These figures include a
monthly lease rental for the gas processing plant servicing our Delhi Field,
which was terminated on June 1, 2006, the effective date of our Delhi Farmout.
14. Earnings / (Loss) per Share
The following table sets forth the computation of basic and diluted earnings /
(loss) per share:
Twelve Months ended Twelve Months ended
June 30, 2006 June 30, 2005
------------------- -------------------
Numerator:
Net income / (loss) applicable to common stockholders $24,626,141 ($2,164,571)
Plus income impact of assumed conversions:
Preferred Stock dividends N/A N/A
Interest on convertible subordinated notes N/A N/A
----------- -----------
Net income / (loss) applicable to common stockholders
plus assumed conversions $24,626,141 ($2,164,571)
=========== ===========
Denominator: 25,031,125 23,533,922
Affect of potentially dilutive common shares:
Warrants 176,072 N/A
Employee and director stock options 348,795 N/A
Convertible preferred stock N/A N/A
Convertible subordinated notes N/A N/A
Redeemable preferred stock N/A N/A
Denominator for dilutive earnings per share - weighted average
shares Outstanding and assumed conversions 25,555,992 23,533,922
Earnings / (loss) per common share:
Basic $ 0.98 ($0.09)
=========== ===========
Diluted $ 0.96 ($0.09)
=========== ===========
15. Commodity Contracts
In compliance with the loan agreement we entered into with Prospect Energy in
February 2005, we executed three commodity contracts for approximately 50% of
the production volumes that our outside petroleum engineers estimated for our
proved developed producing reserves on a rolling two year basis. Although we
paid off the Prospect loan in May 2006, two of these contracts continue to
extend through February 2007, as described below.
The first commodity contract, with Plains Marketing L.P., covered the sale of 70
barrels of crude oil per day for a 12 month period from March 2005 through
February 2006. The fixed sale price was based upon the NYMEX WTI (West Texas
Intermediate) crude oil price and monthly settlements, wherein Plains Marketing
delivered a fixed price of $48.35 per barrel to us before adjustment for the
basis differential between the NYMEX price and the contract price. This contract
was extended for the months of March 2006 through May 2006 at a fixed price of
$52.55 per barrel of oil for 70 barrels of oil per day, extended for the three
months of June 2006 through August 2006 at a fixed price of $63.45 per barrel of
oil for 90 barrels of oil per day, and extended for the six months of September
2006 through February 2007 at a fixed price of $69.30 per barrel of oil for 90
barrels of oil per day. Plains Marketing L.P. is our crude oil purchaser and
picks up our production in the field using their trucks.
The second commodity contract is between us and Wells Fargo Bank, N.A. We
purchased a series of price floors, set at a NYMEX WTI price of $38.00 per
barrel of crude oil, based upon the arithmetic average of the daily settlement
price for the first nearby month of NYMEX WTI futures, for 2,000 barrels of
crude oil per month for March 2006 through February 2007. The cost of the hedge
was $3.00 per barrel of oil.
Our third commodity contract was with Texla Energy Management, Inc., whereby we
sold 100 MMBTU per day at a fixed price of $6.21 per MMBTU over a fifteen month
period beginning March 1, 2005, and ending May 31, 2006.The fixed price was
before deduction of a $0.0854 per MMBTU fixed gathering charge by Gulf South,
the owner of the natural gas pipeline into which we deliver our natural gas from
the Delhi Field. This fixed price included the basis differential from NYMEX to
our sales point on the Gulf South pipeline.
16. Major Customers
All of our crude oil is currently sold to Plains Marketing L.P. and committed
through the life of our fixed price crude oil sales contract. Other crude oil
purchasers are available.
17. Subsequent Events
Natural Gas Systems, Inc changed its name to "Evolution Petroleum Corporation"
effective July 11, 2006. Our name was changed pursuant to an Agreement and Plan
of Merger dated as of July 11, 2006 by which Evolution Petroleum Corporation, a
Nevada corporation and wholly-owned subsidiary of the Company, merged with and
into the Company, with the Company as the surviving entity and renamed as
"Evolution Petroleum Corporation." This statutory short-form merger and name
change was effectuated without shareholder approval in accordance with the
provisions of Section 92A.180 of the Nevada Revised Statutes. Our Board of
Directors authorized this transaction on June 26 2006.
On July 17, 2006, our common stock began trading on the American Stock Exchange
("AMEX") under the ticker symbol "EPM." J. Streicher & Co. Ltd acts as our
trading specialist.
On July 21, 2006, we funded and closed the acquisition of 0.39% in royalty and
overriding royalty interests in the Delhi Holt Bryant Unit from an unrelated
third party owner.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Evolution Petroleum Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of Evolution
Petroleum Corporation as of June 30, 2006 and 2005 and the related consolidated
statements of operations, stockholders' equity, and cash flows for the years
ended June 30, 2006 and 2005. 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
financial statements are free of material misstatement. The Company has
determined that it is not required to have, nor were we engaged to perform, an
audit of its internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such
opinion. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Evolution Petroleum Corporation and subsidiaries as of June 30, 2006 and 2005,
and the consolidated results of their operations and their cash flows for each
of the years then ended in conformity with accounting principles generally
accepted in the United States of America.
HEIN & ASSOCIATES LLP
Houston, Texas
August 29, 2006
Item 8. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure.
None.
Item 8A. Controls and Procedures.
We maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed by us in reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the rules and forms of the SEC and that such
information is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure. As required by SEC Rule
13a-15(b), we carried out an evaluation, under the supervision and with the
participation of our management, including our Chief Executive Officer and e
Chief Financial Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures as of the end of the period covered by this
report.
Based on the foregoing, our Chief Executive Officer and Chief Financial Officer
concluded that, as of the end of the period covered by this report, our
disclosure controls and procedures were effective in ensuring that the
information required to be disclosed in reports we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms and that such information is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure.
There was no change in our internal control over financial reporting during our
last fiscal quarter that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
Item 8B. Other Information.
None.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance
with Section 16(a) of the Exchange Act.
Incorporated by reference to the Company's Proxy Statement to be filed with the
Commission pursuant to Regulation 14A within 120 days of the end of the
Company's 2006 fiscal year.
Item 10. Executive Compensation.
Incorporated by reference to the Company's Proxy Statement to be filed with the
Commission pursuant to Regulation 14A within 120 days of the end of the
Company's 2006 fiscal year.
Item 11. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholders Matters.
Incorporated by reference to the Company's Proxy Statement to be filed with the
Commission pursuant to Regulation 14A within 120 days of the end of the
Company's 2006 fiscal year.
Item 12. Certain Relationships and Related Transactions.
Incorporated by reference to the Company's Proxy Statement to be filed with the
Commission pursuant to Regulation 14A within 120 days of the end of the
Company's 2006 fiscal year.
Item 13. Exhibits.
Index of Exhibits
2.1 Asset Purchase Agreement for Tullos Field, dated September 3, 2004. Previously Filed
2.2 Definitive Asset Purchase Agreement, dated as of February 2, 2005, by and between Chadco, Inc., Previously Filed
Alan Chadwick McCartney, Sonya McCartney and NGS Sub. Corp.
3(i) Articles of Incorporation. Previously Filed
3(ii) Bylaws. Previously Filed
10.1 Registration Rights Agreement, dated as of February 2, 2005, between the Company and Prospect Previously Filed
10.2 Executive Employment Agreement, Robert S. Herlin, dated April 4, 2005 Previously Filed
10.3 Herlin Stock Option Agreement, dated April 4, 2005 Previously Filed
10.4 Herlin Warrant Agreement, dated April 4, 2005 Previously Filed
10.5 Executive Employment Agreement, Sterling H. McDonald, dated April 4, 2005 Previously Filed
10.6 McDonald Stock Option Agreement, dated April 4, 2005 Previously Filed
10.7 Securities Purchase Agreement dated as of May 6, 2005, by and between Natural Gas Systems, Inc. Previously Filed
and Rubicon Master Fund
10.8 Executive Employment Agreement, Daryl V. Mazzanti ("Mazzanti"), dated June 23, 2005 Previously Filed
10.9 Mazzanti Stock Option Agreement, dated June 23 2005 Previously Filed
10.10 Mazzanti Stock Grant Agreement dated June 23, 2005 Previously Filed
10.11 Mazzanti Revocable Warrant Agreement, dated June 23, 2005 Previously Filed
10.12 Securities Purchase Agreement dated as of January 13, 2006 by and between Natural Gas Systems, Previously Filed
Inc. and Rubicon Master Fund
10.13 Amended and Restated Registration Rights Agreement dated as of January 13, 2006 by and between Previously Filed
Natural Gas Systems, Inc. and Rubicon Master Fund.
10.14 Subordinated Promissory Note, dated March 3, 2006, between Natural Gas Systems, Inc. and Laird Q. Previously Filed
Cagan.
10.15 Master Services Agreement, dated September 29, 2005, by and between the NGS Technologies, Inc. and Previously Filed
MTEM, LTD
10.16 Agreement with Chadbourn Securities, Inc., dated February 13, 2006. Previously Filed
10.17 Agreement with Cagan McAfee Capital Partners, LLC, dated February 13, 2006. Previously Filed
10.18 Purchase and Sale Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 9, Previously Filed
2006.
10.19 Purchase and Sale Agreement I, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, Previously Filed
2006.
10.20 Purchase and Sale Agreement II, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May Previously Filed
8, 2006.
10.21 Unit Operating Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006. Previously Filed
10.22 Conveyance, Assignment and Bill of Sale Agreement, by and between NGS Sub Corp. and Denbury Previously Filed
Onshore, LLC, dated May 8, 2006.
10.23 Form of Indemnification Agreement for Officers and Directors, as adopted on September 20, 2006. Previously Filed
14.1 Code of Ethics for Natural Gas Systems, Inc. Previously Filed
21.1 List of all subsidiaries of the Company. Included
31.1 Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley Act of 2002. Included
31.2 Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley Act of 2002. Included
32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant Included
to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant Included
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1 Audit Committee Charter of the Board of Directors of Natural Gas Systems, Inc. Previously Filed
99.2 Compensation Committee Charter of the Board of Directors of Natural Gas Systems, Inc. Previously Filed
99.3 Nominating Committee Charter of the Board of Directors of Natural Gas Systems, Inc. Previously Filed
Item 14. Principal Accountants Fees and Services.
Incorporated by reference to the Company's Proxy Statement to be filed with the
Commission pursuant to Regulation 14A within 120 days of the end of the
Company's 2006 fiscal year.
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized. Evolution Petroleum Corporation
By: /s/ ROBERT S. HERLIN
------------------------------------
Robert S. Herlin
Chief Executive Officer
(Principal Executive Officer)
By: /s/ STERLING H. MCDONALD
------------------------------------
Sterling H. McDonald
Chief Financial Officer
(Principal Financial and
Accounting Officer)
Date: September 27, 2006
In accordance with the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
Date Signature Title
---- --------- -----
September 27, 2006 /s/ E. J. DIPAOLO Director
--------------------------------
E. J. DiPaolo
September 27, 2006 /s/ GENE STOEVER Director
--------------------------------
Gene Stoever
September 27, 2006 /s/ WILLIAM DOZIER Director
--------------------------------
William Dozier
September 27, 2006 /s/ LAIRD Q. CAGAN Chairman of the Board
--------------------------------
Laird Q. Cagan