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, 2005

|_|   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF SECURITIES EXCHANGE
      ACT OF 1934

                For the transition period _________ to _________

                             Commission File Number

                            NATURAL GAS SYSTEMS, INC.
               (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:

      Securities registered pursuant to Section 12(g) of the Exchange Act:

                          Common Stock, $.001 Par Value
                     (Title of class and shares outstanding)

      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: 1,635,187

      As of August 1, 2005, the aggregate market value of common stock held by
non-affiliates of the registrant was approximately $15,015,900, 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 August 01, 2005 was
24,774,606 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
2005 Annual Meeting.

      Transitional Small Business Format (Check One): Yes |_|  No |X|

                      Glossary of Selected Petroleum Terms

      The following abbreviations and definitions are terms commonly used in the
oil and natural gas industry and throughout this report on Form 10-KSB:

<PAGE>

      "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. 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.

      "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.

      "gross well" The total number of wells participated in, regardless of the
amount of working interest owned. (See "net wells").

      "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 wells" The aggregate fractional working interests owned, e.g., a 20%
working interest in each of 5 gross wells equals one net well. (See "gross
well").

      "NGL" Natural gas liquids, being the combination of ethane, propane,
butane and natural gasolines 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.

      "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 or proven 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.

      "psi" pounds per square inch, a measure of pressure. Pressure is typically
measured as "psig", or the pressure in excess of standard atmospheric pressure.

      "PV-10" The present value of 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.

      "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.

      "shut-in well" A well that is not on production, but has not 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.

<PAGE>

                                     PART I.

ITEM 1. BUSINESS

The terms "we," "us," "our," "our company" and "NGS" refer to Natural Gas
Systems, Inc., a Nevada corporation formerly known as Reality Interactive, 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

Old NGS was privately formed in late 2003 to 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 operate 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).

The NGS team is broadly experienced in oil and gas operations, development,
acquisitions and financing, and we follow a strategy of outsourcing most of our
property, corporate administrative and accounting functions. During the year, we
added key members to our team, as discussed under "Management Additions", below.

Our principal executive offices are located at 820 Gessner, Suite 1340, Houston,
Texas 77024. Our telephone number is 713-935-0122. We maintain a website at
www.natgas.us, but information contained on our website does not constitute part
of this document.

Our stock is quoted on the OTC Bulletin Board under the symbol NGSY.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., 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.

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

NGS seeks to acquire majority working interests of oil and gas resources in
established fields and redevelop those fields through the application of capital
and technology to convert the oil and gas resources into producing reserves. In
acquiring our crude oil and natural gas properties, we target established,
shallow oil and gas fields or resources, preferably with existing road, pipeline
and storage infrastructure, and reservoirs with low permeability (referred to as
"tight" reservoirs in which oil or gas flow is inhibited). Such reservoirs
typically have low decline rate production and limited drainage areas per well.
Our strategy is to develop incremental value by:

      o     Focusing on established fields with long-lived production from
            relatively shallow reservoirs and reservoirs with low permeability,
            providing us the following potential advantages:

            o     Reduced exposure to the risk of whether resources are present.

            o     Reduced capital expenditures for infrastructure, such as
                  roads, water handling facilities and pipelines.

            o     Long-lived properties generally reduce risks from short-term
                  oil and gas price volatility and spread the cost of
                  acquisitions over more reserves.

            o     Reduced technical and operational risks and costs associated
                  with lower pressures and lower temperatures typically found at
                  shallow depths.

<PAGE>

            o     The ability to obtain majority working interests, and thus
                  maintain full control of operations and development often
                  available when acquiring established fields.

      o     Accelerating existing production by:

            o     Bringing shut-in, non-producing wells, back to production.

            o     Performing workovers to clean sand, water and paraffin from
                  wells.

            o     Optimizing production facilities, including installation of
                  compression facilities.

      o     Bringing un-drained or partially drained areas of the reservoirs
            into production by:

            o     Re-completing into other reservoirs.

            o     Performing development and exploitation drilling.

            o     Applying lateral drilling, hydraulic fracturing and other
                  stimulation methods to older fields that matured prior to the
                  application of these technologies.

            o     Selective use of newer technologies, some of which may be
                  unproved, to locate bypassed resources in mature fields.

Old NGS purchased its first property in September 2003 through the acquisition
of a 100% working interest and an approximate 80% average net revenue interest,
in property and wells located in northeastern Louisiana which we refer to as the
"Delhi Field." Please see "Item 2. - Properties." This acquisition included the
purchase of six producing wells, one salt water disposal well and 37 shut-in
wells with aggregate average production of approximately 18 barrels of crude oil
per day ("BOPD") and no natural gas sales. The Delhi Field encompasses
approximately 13,636 acres. We own all working interest rights from the surface
to the top of the Massive Anhydride Formation, which lies below the Tuscaloosa
and Paluxy formations in which our currently producing wells are completed and
that are targeted in our development plan, less and except the Mengel Reservoir,
which is being produced by another operator in a small number of wells.

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 included 15 wells without leases. We subsequently acquired
new leases for most of these wells and are attempting to secure new leases for
the remainder.

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.

Management Additions

Daryl Mazzanti joined NGS as our Vice President of Operations in July, 2005, to
lead all of our oil and gas operations. From 1985 to 2005, Mr. Mazzanti was
employed by Union Pacific Resources (UPR) and Anadarko Petroleum (the successor
to UPR), where he managed operational, engineering and geotechnical teams
responsible for oil and gas fields in Texas, Oklahoma, Louisiana, the Rockies
and offshsore GOM. His accomplishments included overseeing up to 1,300
horizontal wells, optimizing artificial lift methods for a 750 well program and
supervising multi-rig drilling and service programs. Mr. Mazzanti began his
career in 1985 as a Development Engineer with Champlin Oil (the predecessor to
UPR), where he was responsible for drilling, completion, workover, recompletion,
reservoir analysis and surface facility optimization across Texas and offshore
GOM. Mr. Mazzanti holds a Bachelor of Science in Petroleum Engineering, with
distinction, from the University of Oklahoma at Norman.

David Joe joined NGS as our Accounting Manager in March 2005, to manage our
outsourced accounting services with Petroleum Financial, Inc. (PFI), perform
financial reporting activities, coordinate our audits and assist with special
projects. From 2004 to 2005, Mr. Joe was a Client Manager for the Prejean
Company, a competitor to PFI in providing outsourced accounting services to the
petroleum industry. In this capacity, he was responsible for managing and
executing the complete upstream accounting cycle for multiple clients. Prior to
joining Prejean, Mr. Joe spent 17 years in a wide array of supervisory,
accounting and financial analysis positions with the UNOCAL Corporation. Mr. Joe
received his BBA in Accounting from the University of Texas at Austin and is
certified as an Accredited Petroleum Accountant. He is also a member of the
Institute of Management Accountants (IMA) and serves on the Education Committee
of the Petroleum Accountants Society of Houston (PASH).

<PAGE>

Markets and Customers

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 $8.50, to in excess of $65 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 regulation and transportation issues unique to
certain producing regions.

Over the past 20 years, domestic natural gas prices have also been volatile,
ranging from $1 to $11 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, price influences tend to be more localized 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. We sell all of our crude oil production from our
Delhi and Tullos Fields to Plains Marketing LP, a crude oil purchaser, at
competitive spot field prices. A portion of our crude oil production is subject
to a fixed price contract (excluding basis risk) with Plains Marketing that
began March 1, 2005 for approximately 2,100 barrels per month through May 2006,
and 2,700 barrels per month thereafter through August 31, 2006 (Please see
"Commodity Contracts.") We believe that other crude oil purchasers are readily
available.

We currently sell our natural gas liquids to Dufour Petroleum, L.P., a
subsidiary of Enbridge Energy Partners, at a market competitive price. We
receive an index price based upon the components of the liquids less a charge of
$0.175 per gallon for transportation and fractionation.

All of our current crude oil and natural gas production is located in northern
Louisiana. There is only one natural gas pipeline sales point readily available
to our gas treating facility, 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.

We presently sell a portion of our natural gas under a short-term contract with
Texla Energy Management, Inc., a natural gas marketer/aggregator, at either the
daily cash price or at the monthly index, as elected by us prior to each month.
The balance, a fixed volume of 100 MMBTU per day, is sold at a fixed price of
$6.21 per MMBTU over a fifteen month period that began March 1, 2005 (see
"Commodity Contracts"). We believe that other natural gas marketers are readily
available. 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. Natural gas sold from the Delhi Field
that is not subject to the commodity contract referred to above is priced on
either a monthly average index price 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 also 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.

In late 2003, we entered into an agreement with Verdisys, Inc., whose name has
been changed to Blast Energy Services, Inc., to provide us with lateral drilling
services based on our projected needs, subject only to adequate advance notice,
at a fixed price not to exceed the lowest price offered to any other customer
for similar services. Although we may find the Blast technology useful, our
business plan does not rely on it. To date, we have used the Blast technology in
only two wells, the results of which were inconclusive.

Since purchase of the Delhi Field and the Tullos Field, we have expended an
estimated approximately $872,614 on development activities.

COMMODITY CONTRACTS

In February 2005, we entered into three commodity contracts. The first, with
Plains Marketing L.P., includes the purchase of 70 barrels of crude oil per day
for a 12 month period from March 2005 through February 2006. The fixed sale
price is based upon the NYMEX WTI (West Texas Intermediate) crude oil price and
requires monthly settlements, wherein Plains Marketing delivers a fixed price of
$48.35 per barrel to us before adjustment for the basis differential between
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, and for the 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. Plains
Marketing L.P. is our crude oil purchaser and picks up our production in the
field using their trucks.

The second 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 contract is with Texla Energy Management, Inc., a natural gas marketer
currently purchasing our natural gas production at the Delhi Field. This
contract provides for us to sell approximately 3 MMBTU of natural gas each month
at a fixed price of $6.21 per MMBTU, 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 includes
the basis differential from NYMEX to our sales point on the Gulf South pipeline.

<PAGE>

As required under our credit agreement with Prospect Energy, these contracts are
placed in amounts aggregating more than 50% of the production volumes that our
outside petroleum engineers have estimated to occur from our existing proved
developed producing reserves over the next two years. Our credit agreement also
requires us to extend such coverage on a rolling two-year basis through the five
year term of the loan as long as the facility is in place.

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. We cannot predict what subsequent
legislation or regulations may be enacted or what affect it will have on our
operations or business.

RISK FACTORS

Risks related to the Company

WE MAY BE UNABLE TO OBTAIN THE LARGE AMOUNT OF ADDITIONAL CAPITAL THAT WE NEED
TO GROW OUR BUSINESS.

Based on our current estimates of production and current oil and gas prices, and
absent a default causing acceleration of our debt, we currently have sufficient
capital reserves to satisfy our short-term obligations and to fund our
anticipated development activities through December 31, 2005. We will require
more capital or success in our development activities or both to execute
additional acquisitions, fund our development plan beyond 2005, replace our
existing depleting reserves or exploit any technology projects we may develop
from time to time. Additionally, we may encounter unforeseen costs or lower
commodity prices that could also require us to seek additional capital. While we
are exploring various capital raising avenues, we cannot assure you that we will
be able to obtain the capital needed to acquire additional crude oil and natural
gas fields. Further, we have been operating at a loss and intend to increase our
operating expenses and overhead significantly as we expand our acquisitions of
crude oil and natural gas production and expand our field operations staff. The
full and timely development and implementation of our business plan and growth
strategy beyond 2005 will require significant additional resources, and we may
not be able to obtain the funding necessary to implement our growth strategy on
acceptable terms or at all. An inability to obtain such resources would
significantly impair our ability to execute our growth plan or respond to
competitive pressures. Furthermore, our growth strategy may not produce material
revenues even if successfully funded.

We intend to explore a number of options to secure alternative sources of
capital, including the issuance of senior secured debt, volumetric production
payments, subordinated debt, or additional equity, including preferred equity
securities or other equity securities. We have not yet identified the sources
for the additional financing we require and we do not have commitments from any
third parties to provide this financing. We might not succeed, therefore, in
obtaining additional and acceptable financing when we need it or at all. Our
ability to obtain additional capital will also depend on market conditions,
national and global economics and other factors beyond our control. We cannot
assure you that we will be able to implement or capitalize on various financing
alternatives or otherwise obtain required working capital, the need for which is
substantial given our operating loss history. We refer you to "Management's
Discussion and Analysis of Financial Condition and Results of
Operations-Liquidity and Capital Resources."

OUR CURRENT CREDIT FACILITY INCLUDES STRICT FINANCIAL COVENANTS THAT WE MAY BE
UNABLE TO SATISFY.

We recently entered into a credit facility with Prospect Energy Corporation.
This facility is secured by essentially all of our existing and certain future
assets including the common stock of our subsidiaries. While no principal
payments are required prior to maturity, we are required to meet certain ongoing
financial covenants. The primary covenants include maintaining a minimum ratio
of borrowing base to debt and a minimum ratio of EBITDA (earnings before
interest, income tax and other non-cash charges such as depreciation, depletion
and amortization) to total interest. Our borrowing base is dependent upon our
proved reserves as determined by our outside engineers and the reasonable
satisfaction of Prospect Energy, future operating costs and capital expenditures
and commodity prices. We cannot assure you that, in the future, commodity prices
will not decline, projected reserve increases will be obtained or current proved
reserves will be realized, any one of which could reduce our borrowing base,
which could in turn require us to reduce our outstanding borrowings or prepay
our debt due to an acceleration by our lender. At June 30, 2005, we were in
compliance with our borrowing base covenant.

<PAGE>

Under the Prospect facility, we are required to maintain an EBITDA of two times
interest payable, beginning no later than the three month period ending January
31, 2006. Our ability to comply with this requirement is dependent on achieving
certain operating results, especially with respect to our planned drilling
program of proved undeveloped reserves at our Delhi Field that was scheduled to
begin in May 2005. At September 27, 2005, our Delhi drilling program had not yet
begun due to delays caused by casualty repairs sustained by the drilling
contractor for the account of another customer. Due to these delays, we can give
no assurance that the delayed results from this program will provide sufficient
EBITDA to meet the required interest coverage ratio. If such a covenant breach
occurs and is not waived by Prospect, the debt would become immediately due and
payable. Since we do not have sufficient liquid assets to prepay our debt in
full, we would be required to refinance all or a portion of our existing debt or
obtain additional financing. If we were unable to refinance our debt or obtain
additional financing, we would be required to curtail portions of our
development program, sell assets, and/or reduce capital expenditures. Had we
been subject to this requirement on June 30, 2005, we would not have been in
compliance.

Other covenants limit additional borrowings, sales of assets and the
distributions of cash or properties and prohibit the payment of dividends and
the incurrence of liens. The restrictions of the credit facility may have
adverse consequences on our operations and financial results, including our
ability to obtain financing for working capital, capital expenditures, our
development program, purchases of new technology or other purposes. We will be
required to use a substantial portion of our cash flow to make debt service
payments, which will reduce the funds that would otherwise be available for
operations and future business opportunities. A substantial decrease in our
operating cash flow or an increase in our expenses could make it difficult for
us to meet our debt service requirements, thus requiring us to modify operations
which could result in our becoming more vulnerable to downturns in our business
or the economy generally.

Our ability to obtain and service indebtedness will depend on our future
performance and performance of vendors, including our ability to manage cash
flow and working capital and availability of services from vendors, which are in
turn subject to a variety of factors beyond our control. We may not get timely
access to vendor services to allow us to carry out our business plan. Our
business may not generate cash flow at or above anticipated levels or we may not
be able to borrow funds in amounts sufficient to enable us to service
indebtedness, make anticipated capital expenditures or finance our development
program. If we are unable to generate sufficient cash flow from operations or to
borrow sufficient funds in the future to service our debt, we may be required to
curtail portions of our development program, sell assets, reduce capital
expenditures, refinance all or a portion of our existing debt or obtain
additional financing. We may not be able to refinance our debt or obtain
additional financing, restrictions on our ability to incur debt under our
existing debt or installment purchase arrangements, and the fact that some or
all of our assets are currently pledged to secure obligations under our existing
debt or installment purchase arrangements.

OUR LIMITED OPERATING HISTORY MAKES IT DIFFICULT TO PREDICT FUTURE RESULTS AND
INCREASES THE RISK OF YOUR INVESTMENT.

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 filing do not reflect any possible effect on us from the outcome of these
types of uncertainty. Since inception, we have incurred significant losses. 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 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 unescalated 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.

<PAGE>

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 have
entered into commodity contracts. These arrangements apply to only a portion of
our production and provide only partial price protection against declines in
crude oil and natural gas 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 or natural gas prices. In addition, our commodity contracts may limit the
benefit to us of increases in the price of crude oil and natural gas.

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.

BECAUSE OUR CURRENT GAS PRODUCING FIELD HAS ONLY ONE GAS PIPELINE OUTLET, OUR
BUSINESS WOULD BE ADVERSELY AFFECTED IF WE LOST ACCESS TO THAT OUTLET.

All of our natural gas sales are made via one gas pipeline connection. Our
ability to sell natural gas would be adversely affected if the operators of this
pipeline refused to or were unable to accept our gas. We have had infrequent
sales curtailment due to gas quality issues resulting from operational problems
with our gas treating facility that we believe have been rectified. Our only
alternative in such event would be to permit and construct a new pipeline
connection to a pipeline located several miles from the field and which could
require re-locating our gas treating facility.

<PAGE>

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 FILING 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 filing
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 filing 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.

<PAGE>

THE TYPES OF RESOURCES WE FOCUS ON HAVE CERTAIN RISKS.

Our business plan focuses on the acquisition and development of shallower, more
complex and/or lower permeability reservoirs. Shallow reservoirs usually have
lower pressure and, necessarily, fewer hydrocarbons 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.

In addition, the mature fields we currently own 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.

Risks Relating to the Oil and Gas Industry

CRUDE OIL AND NATURAL GAS DEVELOPMENT, RE-COMPLETION OF WELLS FROM ONE RESERVOIR
TO ANOTHER RESERVOIR, AND RESTORING WELLS TO PRODUCTION 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 lateral 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. Lateral 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.

<PAGE>

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, profitability, cash flow, future 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 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 conditions;

      o the foreign supply of crude oil and natural gas; and

      o the price of foreign imports and overall economic conditions.

It is impossible to predict future crude oil and natural gas price movements.
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.

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. During the twelve months prior to June 30,
2005, our stock price as traded on the OTC Bulletin Board has ranged from $1.32
to $3.75. The variance in our stock price makes it extremely difficult to
forecast with any certainty the stock price at which you 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.

<PAGE>

PRESENT MANAGEMENT AND DIRECTORS CURRENTLY 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 38% 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 31% of our outstanding common stock. Mr. Eric McAfee, also 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 24% of our outstanding common stock. 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 55% of our outstanding common stock.
As a result, these holders of our outstanding common stock are able to 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.

"PENNY STOCK" REGULATIONS MAY RESTRICT THE MARKETABILITY OF OUR COMMON STOCK.

The SEC's regulations generally define "penny stock" to be an OTC Bulletin Board
("OTCBB") stock that has a market price of less than $5.00 per share. Our common
stock may be subject to rules that impose additional sales practice requirements
on broker-dealers who sell these securities to persons other than established
customers and accredited investors (generally those with assets in excess of
$1,000,000, or annual incomes exceeding $200,000 or $300,000 together with their
spouse). For transactions covered by these rules, the broker-dealer must make a
special suitability determination for the purchase of these securities and have
received the purchaser's prior written consent to the transaction.

Additionally, for any transaction, other than exempt transactions, involving a
penny stock, the rules require the delivery, prior to the transaction, of a risk
disclosure document mandated by the SEC relating to the penny stock market. The
broker-dealer also must disclose the commissions payable to both the
broker-dealer and the registered representative, current quotations for the
securities and, if the broker-dealer is the sole market-maker, the broker-dealer
must disclose this fact and the broker-dealer's presumed control over the
market. Finally, monthly statements must be sent disclosing recent price
information for the penny stock held in the account and information on the
limited market in penny stocks. Consequently, the "penny stock" rules may
restrict the ability of broker-dealers to sell our common stock and may affect
the ability to sell our common stock in the secondary market.

THE MARKET FOR OUR COMMON STOCK IS LIMITED AND MAY NOT PROVIDE ADEQUATE
LIQUIDITY.

Our common stock is currently thinly traded on the OTC Bulletin Board, a
regulated quotation service that displays real-time quotes, last-sale prices,
and volume information in over-the-counter equity securities. As a result, an
investor may find it more difficult to dispose of, or obtain accurate quotations
as to the price of, our securities than if the securities were traded on the
NASDAQ Stock market, or another national exchange. There are a limited number of
active market makers of our common stock. In order to trade shares of our common
stock you must use one of these market makers unless you trade your shares in a
private transaction. In the twelve months prior to June 30, 2005, the actual
trading volume in our common stock ranged from a low of no shares of common
stock traded to a high of over 90,000 shares of common stock traded, with only
90 days exceeding a trading volume of 10,000 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 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:

<PAGE>

      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.

SUBSTANTIAL SALES OF OUR COMMON STOCK COULD CAUSE OUR STOCK PRICE TO FALL.

As of June 30, 2005, we had outstanding 24,774,606 shares of common stock, of
which approximately 23,713,345 shares were "restricted securities" (as that term
is defined in Rule 144 promulgated under the Securities Act of 1933). On June 6,
2005, we filed a registration statement on Form SB-2 ("registration statement")
to register 5,814,345 shares of our currently outstanding restricted common
stock, but this registration statement has not yet been declared effective.
Other than the shares being registered for resale by the registration statement,
only approximately 1,036,255 shares are currently freely tradable shares without
further registration under the Securities Act. However, as a result of the
registration of the shares included in the registration statement, an additional
5,814,345 shares of our currently outstanding common stock will be able to be
freely sold on the market, which number will increase to 6,864,345 shares if the
warrants are exercised by the selling stockholders and the underlying 1,050,000
shares that are included in the registration statement are purchased. Because
there currently are only approximately 1,036,255 freely tradable shares, the
release of 5,814,345 additional freely trading shares included in the
registration statement onto the market, or the perception that such shares will
or could come onto the market, could have an adverse affect on the trading price
of the stock.

In addition to the shares that are being registered for re-sale under this
prospectus, an additional 18,000,000 shares of restricted stock became eligible
for public resale under Rule 144 as of June 30, 2005. Although Rule 144
restricts the number of shares that any one holder can sell during any
three-month period under Rule 144, because more than one stockholder holds these
restricted shares, a significant number of shares can now be sold under Rule
144. We cannot predict the effect, if any, that sales of the shares included in
the registration statement or subject to Rule 144 sales, or the availability of
such shares for sale, will have on the market prices prevailing from time to
time. Nevertheless, the possibility that substantial amounts of our common stock
may be sold in the public market may adversely affect prevailing market prices
for our common stock and could impair our ability to raise capital through the
sale of our equity securities.

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. Additionally, we
are currently restricted from paying dividends pursuant to the terms of our
credit agreement.

ITEM 2. PROPERTIES

Delhi Field

In late September 2003, Old NGS purchased a 100% working interest and an 80% net
revenue interest in 43 wells in Richland, Franklin and Madison Parishes,
Louisiana, which we refer to as the Delhi Field, by paying $995,000 in cash,
issuing non-interest bearing notes for $1,500,000 and assuming a plugging and
abandonment reclamation liability in the amount of approximately $302,000, in
exchange for the conveyance of all the underlying, unitized leasehold interests.
The notes were collateralized by a first mortgage on the leasehold interests and
were fully repaid by the end of 2004.

The Delhi Field was discovered in the mid-1940's and was extensively developed
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 water flood 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 formation. 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 of acquisition in 2003, production in the Delhi Field 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, the
161-36, 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. Following the acquisition, we initiated a development
program for the Delhi Field based on re-completion of wells to other reservoirs
and restoring non-producing wells to producing status. We further refurbished a
gas injection line to serve as our gas gathering line.

<PAGE>

In March of 2004, we installed a leased natural gas treating and compression
facility under a one-year operating lease that automatically extends on a
month-to-month basis. The facility, located just north of the Delhi Field on
land provided to us by another oil and gas operator, was necessary to begin
sales of natural gas, which began in July of 2004, thus expanding our revenue
base as contemplated by our original plan for the Delhi Field.

In April 2005, we re-completed the Delhi Ut. #87-2 well to a new reservoir at a
test rate of approximately 90 BOPD and 35 MCFD and no water. The test rate was
constrained by the elective use of a choke to limit potential sand influx.
Subsequently, the well began to produce water while retaining its high pressure.
We commenced a series of workovers to repair a leaking packer and casing leak
that curtailed production from the well during the balance of the quarter, and
determined that the casing immediately below the producing reservoir had
developed mechanical problems. At this time, we have not confirmed that the
water production is coming from the damaged portion of the well bore and not the
producing reservoir, but believe that is the case. As further remedial work
would bear significant risk of further mechanical failure, we have elected to
delay such work until our development drilling program is completed and have
voluntarily curtailed production from the well to lower the risk of additional
mechanical problems.

We earlier reported that our development plan for the Delhi Field would include
five drilling locations and that drilling would begin in the second calendar
quarter of 2005. The contracted drilling rig suffered substantial damage while
on site of another client and was unavailable for use from mid-May 2005 through
late August, thus the anticipated production and revenues from the wells to be
drilled have been delayed correspondingly. The drilling contractor has agreed to
extend the program to a total of seven wells to be drilled consecutively, each
taking about one week to drill and about two weeks to complete using a separate
completion rig that is currently available.

At the end of June 2005, the gross productive rate of the Delhi field was
approximately 60 BOPD and 200 MCFD (net of 60 MCFD of shrinkage discussed
below) of natural gas and 3 barrels of natural gas liquids per day. Current
natural gas sales have been about 60 MCFD less than production, as a portion of
the produced natural gas is utilized as compressor, dehydrator and pump engine
fuel on site and a portion is converted into natural gas liquids during the gas
treating process that enables us to sell the gas. Several of our currently
shut-in wells are scheduled to be restored to production through workovers to
repair mechanical problems or through re-completions into new reservoirs and are
anticipated to further increase production in the near term. The seven well
drilling program also is expected to increase the production in the Delhi Field.

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.

As of June 30, 2005, the productive rate in the Tullos Field Area was
approximately 115 BOPD. Production in December 2004 through January 2005 was
adversely impacted by a dispute with one of the sellers who was retained as a
contract operator for the period of time following the initial closing and the
assumption of operatorship by our subsidiary, Four Star Development Corporation.
Production in January 2005 through March 2005 was adversely impacted by weather
conditions that limited road access to certain of the leases, including the
trucks of the oil purchaser and well service rigs. Production was further
hampered by lack of access to well service rigs and crews during April 2005 due
to the overall tightness in the oil field service industry, and the lack of
adequate field maps and well records that are normally provided by a selling
operator.

To date, our development work has been focused on reducing producing well
downtime due to mechanical problems, incrementally increasing water disposal
capacity through disposal well repairs and maintenance and reproducing the
necessary field records and maps. In April of 2005, we continued a program to
return wells to active production that had been shut-in for extended periods of
time and increasing overall water disposal capacity through workovers of
existing disposal wells and drilling of new disposal wells. Other near term
projects include gathering natural gas from the producing wells to power
electric generators that will power our electric pumps in the area. Our
development plans are modeled closely on the operations of an offset operator in
the same field that has increased per well production higher than the historic
rate of our properties.

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.

<PAGE>

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, 2005. Von Gonten also previously prepared an independent report of
our proved reserves at 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. All 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, 2005, natural gas and associated liquids represented 14% and crude
oil represented 86% of total proved reserves, denominated in equivalent barrels
using a six MCF of gas to one barrel of oil conversion ratio, as compared to 26%
and 74%, respectively, at July 1, 2004, and 35% and 65%, respectively at
December 31, 2003.

The following table sets forth, as of July 1, 2005, July 1, 2004 and January 1,
2004, 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 $56.50, $37.05 and $32.52 per barrel of oil
and $6.98, $6.16 and $6.19 per MMBTU of gas as of June 30, 2005, June 30, 2004
and December 31, 2003, 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.

<TABLE>
<CAPTION>
                  Oil        Gas           Estimated Future         Estimated Future
                (bbls)      (mcf)            Net Revenues             Net Revenues
                                                                   Discounted at 10%
<S>               <C>         <C>                  <C>                     <C>
Jul 1, 2005       771,817     732,300*             $24,892,850             $17,479,486
Jul 1, 2004       238,904     508,556*              $8,121,711              $6,320,754
Jan 1, 2004       240,362     778,700              $10,065,493              $8,119,670
</TABLE>

* NGL reserves of 7,300 and 5,000 bbls as of July 1, 2005 and July 1, 2004,
respectively, are included in the above gas volumes, at a 6:1 ratio.

At July 1, 2005, Proved Developed reserves (including Proved Behind Pipe)
totaled 68% of Total Proved reserves, the balance consisting of Proved
Undeveloped reserves. At July 1, 2004, Proved Developed reserves totaled 100% of
the Total Proved reserves (including Proved Behind Pipe).

Our Proved Reserves at July 1, 2005 represents a 176% increase in volumes and a
177% increase in PV10 to $17,479,486, as compared to $6,320,754 at July 1, 2004.
The increase in our PV10 of Proved Reserves is primarily due to discoveries and
extension ($7.1MM), the acquisition of the Tullos Field Area assets ($4.8MM) and
changes in prices and costs ($3.3MM), offset by revisions in estimates (-$2.7MM)
and production (-.7), plus other (.1). See Note 10. "Supplemental Oil and Gas
Disclosures", to the consolidated financial statements.

Production, Average Sales Prices and Average Production Costs

Our net production quantities and average price realizations per unit for the
fiscal periods are set forth below. Our hedging losses, totaling $102,632 for
oil and $4,280 for natural gas, are included in the prices in the table below:

<TABLE>
<CAPTION>
                        12 months ended                       6 months ended                           3 months ended
                         June 30, 2005                         June 30, 2004                          December 31, 2003
  Product     Volume              Price*         Volume                     Price*        Volume                       Price
<S>           <C>                     <C>         <C>                           <C>          <C>                         <C>
Gas (mcf)     54,137                  $6.62       110                           $5.90         --                             --
Oil (bbls)    27,230                 $46.89     3,180                          $36.95        857                         $28.27
</TABLE>

*On an "as-sold" basis, which excludes gas used in operations of 18,029 MCF's
and 13 MCF's, respectively for the twelve month period ended June 30, 2005 and
the six months ended June 30, 2004.

<PAGE>

Average production costs, including production taxes, per unit of production
(using a six to one conversion ratio of MCF's to barrels) were $26.02, $46.59
and $92.54 per barrel for the twelve months ended June 30, 2005, the six months
ended June 30, 2004 and the three month period ended December 31, 2003,
respectively. The high production costs per barrel are a result of substantial
expenses related to general field repairs immediately following the purchases.

Productive Wells and Developed Acreage

Developed acreage at June 30, 2005 totaled 14,155 net and gross acres, 13,636 of
which is in the Delhi Field subject to unitization, and 519 of which is in the
Tullos Field Area held by production under a number of leases. Developed acreage
at June 30, 2004 totaled 13,636 net and gross acres held by a unitization
agreement.

At June 30, 2005, we owned working interests in 306 net and gross wells
consisting of 253 crude oil wells, 3 natural gas wells, 18 water disposal wells
and 32 shut-in wells with uncertain future utility. Approximately 100 of the
crude oil wells in the Tullos Areas are shut-in and believed, in most part, to
be capable of production following varying degrees of repair and maintenance or
incremental water disposal capacity.

At June 30, 2004, we owned working interests in 44 net and gross wells
consisting of 6 oil wells, 1 gas well, 1 water disposal well and 36 shut-in
wells.

Undeveloped Acreage

As of June 30, 2005, all working interest acreage owned by the Company is held
by production through a unitization agreement or lease agreements on developed
properties.

Drilling

During the twelve months ended June 30, 2005 and the six months ended June 30,
2004, we drilled no new wells.

Subsequent Events

Since June 30, 2005:

      o     Effective September 22, 2005, we entered into an amendment to the
            Prospect Facility, thereby obtaining covenant relief with respect to
            our obligation to maintain an EBITDA to interest payable coverage
            ratio of 2:1. The amendment changes our compliance date to begin not
            later than the three months ended January 31, 2006, as compared to
            October 31, 2005 under the original terms of the agreement. This
            amendment was effected in order to allow us to proceed with the
            delayed drilling program of proved undeveloped reserve locations in
            our Delhi Field, the results of which we are relying on to achieve
            the required EBITDA coverage ratio. As explained earlier, the
            drilling program has been delayed due to a casualty sustained to the
            contracted rig, while demobilizing from a previous customer.

            In exchange for the amendment, we have issued to Prospect revocable
            warrants to purchase 200,000 shares of our common stock, exercisable
            at $1.36 per share over five years. The warrants will be
            automatically revoked in the event we achieve $200,000 in EBITDA, as
            defined, for any one month period through April 30, 2006. We also
            agreed to limit our acquisitions of additional oil and gas
            properties to a maximum of $100,000 plus any new funds raised, until
            we achieve a trailing three month EBITDA to interest coverage ratio
            of 2.0. The limitation does not include any evaluation costs, so
            that we may continue to review new projects. For additional details,
            the amendment to the Loan Agreement and the Revocable Warrant
            Agreement are attached as Exhibits 10.30 and 10.31, respectively.

      o     We have placed on production two additional wells that were
            previously shut-in in the Delhi Field, the Delhi Ut. #190-1 and
            #225-1.

      o     Cleaned out a water disposal well to increase capacity in the Tullos
            Area

      o     Extended our drilling contract for two additional wells, for a total
            of seven wells to be drilled in the Delhi Field in 2005. However,
            the rig has not yet mobilized and, accordingly, the drilling program
            has not yet begun.

      o     On August 29, 2005, the center of Hurricane Katrina, a Category 5
            storm, came onshore just east of New Orleans, Louisiana. None of our
            oil and gas properties suffered casualty loss from this storm, as
            the area was minimally affected by rains off of the west side of
            Katrina as she progressed inland veering to the east. It is
            possible, however, that in the aftermath of the storm we may become
            subject to supply chain disruptions affecting the availability of
            fuel, power, supplies and the like at any time, although we have not
            experienced any of these disruptions to date.

ITEM 3. LEGAL PROCEEDINGS

We are not a party to any material pending legal proceedings. No such
proceedings have been threatened and none are contemplated by NGS.

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 THE COMPANY'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Our common stock is traded on the OTC Bulletin Board National Association of
Securities Dealers Automated Quotation System under the symbol "NGSY" and its
predecessor symbol "RLYI". Market quotations shown below were reported by Media
General Financial Services and represent prices between dealers, excluding
retail mark-up or commissions, and adjusted for the 40:1 stock split that
occurred on February 5, 2004.

<PAGE>

<TABLE>
<CAPTION>
                    2005                    2004                     2003

Quarter Ended       High         Low        High         Low         High         Low
----------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------
<S>                  <C>         <C>        <C>          <C>         <C>         <C>
December 31          na          na         $ 2.30       $ 1.45      $ 1.60      $ 0.64

September 30         na          na         $ 3.75       $ 2.05      $ 2.60      $ 1.20

June 30              $ 3.47      $ 1.32     $ 4.75       $ 0.91      $ 1.80      $ 0.60

March 31             $ 2.30      $ 1.55     $ 3.25       $ 0.65      $ 1.80      $ 0.20

</TABLE>

At August 31, 2005, we had 1,044 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

On August 3, 2004, shareholders approved the adoption of our 2004 Stock Plan. As
of June 30, 2005, options to purchase 1,550,000 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.

<TABLE>
<CAPTION>
Plan category                                         Number of      Weighted-average   Number of securities
                                                    securities to        exercise            remaining
                                                      be issued          price of       available for future
                                                    upon exercise      outstanding         issuance under
                                                   of outstanding    options, warrants   equity compensation
                                                      options,             and            plans (excluding
                                                    warrants and          rights        securities reflected
                                                       rights              (b)             in column (a))
                                                        (a)                                       (c)
                                                   --------------    -----------------  --------------------
<S>                                                  <C>                      <C>                <C>
Equity compensation plans approved by security       2,205,000 (1)            $1.25              2,305,000
holders
Equity compensation plans not approved by
security holders                                     1,212,467 (2)            $1.24                     --

Total                                                 3,417,467               $1.24              2,305,000
</TABLE>


(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, 2005, 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, 2005, there were 1,550,000 shares of common stock issued or issuable upon
exercise of outstanding options and 145,000 shares issued directly under the
2004 Stock Plan (145,000 shares of which were subject to reverse vesting at June
30, 2005), leaving 2,305,000 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
319,931 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 79,921 were issued to Laird Q.
Cagan, Chadbourn Securities and their assigns in connection with capital raising
services. Subsequently, we issued a warrant to purchase 92,536 shares of common
stock to Laird Q. Cagan, Chadbourn Securities and their assigns in connection
with capital raising services , warrants to purchase 262,500 shares of common
stock to Tatum Partners in connection with Mr. Herlin's employment, and a
warrant to purchase 50,000 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, and a warrant to purchase 200,000 shares in
connection with Mr. Mazzanti's employment agreement with the Company.

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, 2005.

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

As used herein, the term "three months ended December 31, 2003" refers to our
inception date, September 23, 2003, through December 31, 2003.

Liquidity and Capital Resources

As of June 30, 2005, we had $2,548,688 of unrestricted cash and positive working
capital of $2,599,232, as compared to negative working capital of $383,352 at
June 30, 2004, and negative working capital of $360,749 at December 31, 2003.
Our working capital of $2,599,232 at June 30, 2005 was positively impacted by
the funded debt and equity we received under the Prospect Facility and the funds
we received from the sale of our common stock to the Rubicon Fund and a number
of accredited investors, the proceeds of which were used to pay off most of our
short-term debt and to replenish our working capital.

<PAGE>

Cash flow used by our operating activities was $1,077,535 for the twelve months
ended June 30, 2005, as compared to $854,350 used during the six months ended
June 30, 2005 and $247,003 used during the three months ended December 31, 2003.
On an annualized basis, cash flow used by operating activities improved 37% in
fiscal 2005, as compared to the six months ended June 30, 2004. The improvement
was mostly attributable to $735,573 of cash flow provided from field operations
in the twelve months ended June 30, 2005, as compared to $24,405 used in field
operations for the six months ended June 30, 2004.

Cash flow used by investing activities was $2,778,623 for the twelve months
ended June 30, 2005. Of the major investing activities, approximately $1,504,000
was used to acquire oil and gas properties in the Tullos Urania Field Area,
$553,543 was used to develop our oil and gas properties and $560,000 was used to
comply with the debt service reserve account under the Prospect Facility. This
compares to $4,194 used by investing activities during the six months ended June
30, 2004, and $1,805,485 for the three months ended December 31, 2003. Of the
major investing activities in the three months ended December 31, 2003,
$1,290,560 was invested in oil and gas properties, mostly to acquire our Delhi
Field, and $301,835 was used to fund a Site Specific Trust Fund with the state
of Louisiana for future plugging and abandonment related to the acquisition of
our Delhi Field.

During the twelve months ended June 30, 2005, we increased our debt, net of
repayments, by $2,081,511 and replaced short-term debt with long-term debt under
the Prospect Facility. We also raised gross proceeds from equity sales totaling
$4,729,091, of which $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 as described under "Common Stock, Options and Warrants" in Note
8 to our consolidated financial statements.

These debt and equity issuances have allowed us to:

      o Better match our long-term asset base with a longer term debt structure,
      while also relieving our liquidity issues. This is in sharp contrast to
      our previous debt structure that was comprised entirely of short-term
      debt.

      o Further strengthen our balance sheet through sales of additional equity
      securities.

      o Close the acquisition of additional oil and gas properties in the Tullos
      Urania, Colgrade and Crossroads field area where we already owned existing
      offset production acquired in September 2004 (together, the "Tullos Field
      Area"), thus potentially increasing our cash flow from operations through
      both increased production and synergies with our existing properties.

      o Initiate further development of our existing oil and gas properties in
      accordance with our business plan to exploit known petroleum resources.

      o Continue to seek additional acquisition candidates in accordance with
      our business plan.

Our most significant financing transactions included:

o     On May 6, 2005, we closed a private placement of 1,200,000 shares of our
      common stock with the Rubicon Fund, a European institutional investor, at
      a $2.50 price per share. The gross proceeds to us from this offering were
      $3,000,000 before payment of a $240,000 placement fee to Chadbourn
      Securities and Laird Q. Cagan, the Chairman of our board of directors. We
      also issued Chadbourn Securities and Mr. Cagan warrants to purchase up to
      a total of 96,000 shares of our common stock at a price of $2.50 per
      share.

o     On February 3, 2005, we closed the Prospect Facility and drew down
      $3,000,000, and on March 16, 2005 we drew down an additional $1,000,000 on
      the total $4,800,000 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 the Bridge Loan,
      immediate re-development of our existing properties and for working
      capital purposes. After taking into account the effect of the completion
      of the February 2005 acquisition of properties (see Note 2 to our
      consolidated financial statements), the closing of the Prospect Facility
      and our recent private placement of common stock described above, and
      before taking into account the effect of any new projects or acquisitions,
      we believed that our liquidity and anticipated operating cash flows were
      sufficient to allow the remaining $800,000 commitment under the Prospect
      Facility to expire on May 3, 2005.

      Under the terms of the Prospect Facility, we are required to maintain
      certain affirmative and negative covenants. At June 30, 2005, we were in
      compliance with the terms of the Facility.

<PAGE>

      Looking forward, we will be required to maintain an EBITDA of 2X interest
      payable, beginning no later than the three month period ending January 31,
      2006. Our ability to meet this requirement is dependent on achieving
      certain operating results, especially with respect to our planned drilling
      program of Proved Undeveloped Reserves at our Delhi Field, which was
      scheduled to begin in May 2005. As previously mentioned, our Delhi
      drilling program has been delayed by casualty repairs sustained by the
      drilling contractor for the account of another customer. Due to these
      delays, we can give no assurance that the delayed results from this
      program will provide sufficient EBITDA to meet our required interest
      coverage ratio. If such a covenant breach occurs and is not waived by
      Prospect, the debt would become immediately due and payable. Since we do
      not have sufficient liquid assets to prepay our debt in full, we would be
      required to refinance all or a portion of our existing debt or obtain
      additional financing. If we were unable to refinance our debt or obtain
      additional financing, we would be required to curtail portions of our
      development program, sell assets, and/or reduce capital expenditures. Had
      we been subject to this requirement on June 30, 2005, we would not been in
      compliance. In addition, the Prospect Facility, as amended, limits our
      acquisition of additional oil and gas properties to a maximum of $100,000
      plus any new funds raised, until we achieve a trailing three month EBITDA
      to interest coverage ratio of 2.0. The limitation does not include any
      evaluation costs, so that we may continue to review new projects.

      For a summary of the terms of the Prospect Facility, the Prospect Loans
      and the Prospect Warrants, see Note 7, Notes Payable, Note 8, Common
      Stock, Options and Warrants and Note 18, Subsequent Events, to our
      consolidated financial statements.

o     During Fiscal 2005, and prior to the closing of the Prospect Facility, the
      Chairman of our Board of Directors, Laird Q. Cagan, loaned us, through a
      series of advances, $920,000 pursuant to a secured promissory note bearing
      interest at 10% per annum (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 closing of the Prospect Facility.
      After the closing of the Prospect Facility, we paid off the Bridge Loan in
      full in the amount of $953,589, which included accrued interest thereon.

Based on our current estimates of production and current oil and gas prices, and
absent a default causing acceleration of our debt, we currently have sufficient
capital reserves to satisfy our short-term obligations and to fund our
anticipated development activities through December 31, 2005. We will require
more capital or success in our development activities, or both, to execute
additional acquisitions, fund our development plan beyond 2005, replace our
existing depleting reserves or exploit any technology projects we may develop
from time to time.

In accordance with our business objectives, we plan to continue expending
considerable time and effort to secure additional capital in order to acquire
additional oil and gas properties. We cannot assure you that we will be able to
secure such additional financing on terms satisfactory to us or at all, or that
we will be able to identify acquisitions that meet our strategic objectives.

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 to our ability to operate profitably and to
budget capital expenditures, they are beyond our control and are difficult to
predict. Gas sales are completed on a BTU basis and the gas pipeline measures
the BTU content at the delivery point. The gas produced at the Delhi Field is
high BTU, with over 1100 BTU per cubic foot of gas from the dry gas wells, and
over 1300 BTU in gas associated with the oil wells. Due to the low initial
production volumes, the Company utilizes a J-T gas processing unit that strips
out most of the heavier liquids, in accordance with the sales pipeline criteria.
However, the J-T unit is not as efficient as more costly methods such as
cryogenic separation, thus the sales gas heat content of 1117 BTU per cubic foot
(as of August, 2004) being delivered to the gas sales pipeline is higher than
the standard of 1000 BTU per cubic foot. When gas production volume increases to
a sufficient level, we may switch to a more efficient processing unit.

Increases in oil and natural gas volumes for the twelve months ended June 30,
2005, the six months period ended June 30, 2004 and the three months ended
December 31, 2003 were a result of more months in the period, the successful
workovers and restoration to production of several wells and the acquisitions of
additional producing properties.

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

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

We did not commence our crude oil and natural gas operations until October 2003.
Accordingly, our comparative results are limited.

During the twelve months ended June 30, 2005, we generated revenues of
$1,635,187, as compared to $118,158 for the six months ended June 30, 2004 and
$24,229 for the three months ended December 31, 2003, producing net losses of
$2,164,571, $1,027,682 and $336,905 for the same respective periods. Excluding
non-cash compensatory stock expense, our net losses were $1,457,454, $919,068
and $286,505 for the twelve month, six month and three month periods of 2005,
2004 and 2003, respectively. On an annualized basis, our net loss improved 21%,
excluding non-cash compensatory stock expense,

<PAGE>

Our results of operations were positively impacted by the following events
during the fiscal year 2005:

      o     Began our first natural gas sales from our Delhi Field in July 2004,

      o     Closed two acquisitions of producing properties in the Tullos Field
            Area in September 2004 and February 2005.

      o     Re-completed the Delhi Ut. #184-2 as a gas well with initial
            production rate of almost 400 MCFD.

      o     Re-completed the Delhi Ut. #87-2 as a flowing oil well at an initial
            rate of 90 BOPD and 35 MCFD and original reservoir pressure, which
            is being produced at a lower rate as described below.

      o     Completed the first phase of mapping of the Delhi Field and
            identified 15 locations to be drilled.

Our revenues have continued to increase substantially each quarter, albeit at a
slower rate of change than anticipated. Specifically, our operating results for
the year ended June 30, 2005 were adversely impacted by the following events:

      o     The re-completion of the Delhi Ut. #87-2 did not begin production
            until April 2005 and encountered mechanical problems in the (65 year
            old) well bore that severely reduced production in May and June
            2005. Following a series of workovers to repair the damage, we
            elected to defer further work and produce the well at a lower rate
            of 30-35 BOPD, compared to the initial rate of 90 BOPD, in order to
            lower the possibility of further damage. Correspondingly, we
            anticipate drilling a replacement well as part of our current
            development program that is expected to be higher in structure than
            the 87-2 and, therefore, should recover attic reserves that are
            otherwise not producible from the 87-2 well.

      o     Our second most significant oil well, the Delhi Ut. #197-2,
            continued to experience constrained production and numerous
            non-production days due to sand production. The current production
            level of about 10-15 BOPD appears to minimize sand influx and
            substantially reduce workover costs and downtime.

      o     Our most significant gas well, the Delhi Ut. #184-2, suffered
            plugging by ash material produced by the formation. Consequently,
            the well is producing at a curtailed rate until we initiate a
            cleanup and treatment.

      o     Heavy rains prevented regular lease maintenance and repairs from
            January through early April 2005, particularly in our Tullos Field
            Area. As the wells in the Tullos Field Area require a high level of
            maintenance and repairs, our production was significantly reduced in
            those months.

      o     Extensive rains also prevented most development work in all fields.
            Roads could not be built for new locations and existing roads could
            not be maintained to allow crude oil trucks to pick up product.

      o     The high industry demand for workover service rigs resulted in our
            losing access to vendor equipment during March and April 2005 due to
            the weather and the vendors' moving of inactive equipment to other
            parts of the region not so adversely impacted by the weather.

      o     The properties purchased in the Tullos Field Area were transferred
            without the normally available well plats, geological maps and well
            histories. Consequently, our development plan for Tullos Field has
            been delayed while we reproduce or locate much of this information
            necessary to more efficiently produce the wells, collect and dispose
            of water and identify precise disposal needs and workover
            opportunities.

      o     Our general and administrative costs have been affected by the
            increased costs of Rule 144 stock that required substantial legal
            work, recruitment costs, including sign on bonuses, in a tight
            market for skilled energy staff, and the relatively high cost of
            being a public company in our early stages of growth.

The following remedial actions have been or are planned to be taken:

      o     We are producing the 87-2 well at a reduced rate to limit the
            potential of further mechanical problems while scheduling a
            replacement well to be drilled up structure to recover additional
            reserves as well.

      o     We are evaluating alternative lift mechanisms for the Delhi Ut.
            #197-2 well that may be more resistant to sand production.

      o     We are planning to stimulate the 184-2 well following completion of
            the first few wells in our drilling program.

      o     We have nearly completed the reconstruction of the Tullos Field
            Area's records and maps.

      o     We are developing a program of improving the roads and lease
            batteries in key areas of the Tullos Field Area and are evaluating
            the movement of certain tank batteries to locations more resistant
            to rain.

      o     We are replacing certain high maintenance beam pumps with
            submersible pumps in the Tullos Field Area, potentially reducing
            maintenance expense and production downtime.

<PAGE>

      o     We have arranged for a local well service company to activate and
            dedicate a service rig to our priority use in the Tullos Field Area.

Following is a summary of the progress we have made in both sales volumes and
revenues, net to our interest:

<TABLE>
<CAPTION>
                                                                        Three months ended
                                 units     12/31/2003    3/31/2004   6/30/2004    9/30/2004    12/31/2004   3/31/2005    6/30/2005
                                           ---------------------------------------------------------------------------------------
<S>                              <C>          <C>          <C>         <C>         <C>           <C>         <C>          <C>
Oil & Gas revenues                 $          $24,229      $48,572     $69,586     $231,167      $365,768    $402,305     $635,948

Oil volumes sold                   BO             857        1,498       1,934        3,955         5,234       6,545       12,644

Gas volumes sold                  MCF              --           --         110       11,252        15,679      16,378       10,828

Barrels of oil equivalent sold    BOE              --        1,498       1,952        5,830         7,847       9,275       14,449

Oil price (excludes price
risk management activities)       $BBL         $28.29       $32.43      $35.64       $42.66        $47.94      $47.61       $50.78
Gas price  (excludes price
risk management activities)      $/MCF             --           --       $5.90        $5.55         $7.32       $6.71        $6.35

Operating cost                    BOE          $92.54       $43.20      $43.17       $26.38        $24.14      $25.97       $24.39

Depreciation, depletion &
amortization ("DD&A")             BOE          $16.29        $9.06      $14.33        $6.88         $6.88       $6.01        $7.12
</TABLE>

Highlights of our performance since beginning our oil and gas operations, as
shown in the table above:

      o  We have increased revenues for each quarter.

      o  We have increased sales volumes for each quarter, with average daily
         sales increasing from 9 BOEPD during the three months ended December
         31, 2003 to 103 BOEPD, net to our interest.

      o  We have reduced operating costs per BOE.

      o  We have consistently reduced DD&A, due to lower acquisition costs
         per BOE on recent field purchases.

General and administrative expenses increased for the year ended June 30, 2005
to $2,220,780, as compared to $912,761 for the six months ended June 30, 2004
and $239,093 for the three months ended December 31, 2003. Of the amount
incurred in fiscal 2005, $707,117 was due to non-cash charges for stock
compensation expense (largely attributable to the Tatum contract re-negotiation)
as compared to $108,614 of similar non-cash charges for the six months ended
June 30, 2004 and $50,400 for the three months ended December 31, 2003.

Also included in general and administrative expenses for the twelve month period
ended June 30, 2005 and the six months ended June 30, 2004, are significant
costs of being a public company. Such costs include additional audit, tax,
legal, printing, stock transfer, annual proxy statement preparation, merger
expenses and similar costs incurred by public companies. Merger fees and
expenses related to the merger of Old NGS into a subsidiary of Reality amounted
to $370,000 for the six month period ended June 30, 2004. Old NGS was not a
public company until its merger with us in May 2004.

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.

<PAGE>

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.

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 is in the
process of evaluating whether SFAS No. 123R will have a significant impact of
the Company's overall results of operations or financial position.

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, 2005, June 30, 2004 and December 31,
2003

Consolidated Statements of Operations for the Twelve Months ended June 30, 2005,
the Six Months ended June 30, 2004 and the period from September 23, 2003
(inception) to December 31, 2003

Consolidated Statements of Stockholders' Equity for the Twelve Months ended June
30, 2005, the Six Months ended June 30, 2004 and the period from September 23,
2003 (inception) to December 31, 2003

Consolidated Statements of Cash Flows for the Twelve Months ended June 30, 2005,
Six Months ended June 30, 2004 and the period from September 23, 2003
(inception) to December 31, 2003

Notes to Consolidated Financial Statements

<PAGE>

                   NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES
                           Consolidated Balance Sheets

<TABLE>
<CAPTION>
                                                                                                    December 31,
                                                                 June 30, 2005    June 30, 2004         2003
                                                                 -------------    -------------     -------------
Assets
Current Assets:
<S>                                                               <C>             <C>               <C>
     Cash                                                         $ 2,548,688     $   367,831       $   830,312
     Accounts receivable, trade                                       300,761          24,387            56,837
     Inventories                                                      222,470         115,859           109,216
     Prepaid expenses                                                  84,304          69,067            25,930
     Retainers and deposits                                            56,335           5,000           210,000
                                                                  -----------     -----------       -----------
            Total current assets                                    3,212,558         582,144         1,232,295

     Oil & Gas properties - full cost                               5,276,303       3,075,438         2,971,468
     Oil & Gas properties - not amortized                              61,887         105,225                --

     Less: accumulated depletion                                     (313,391)        (55,509)          (13,960)
                                                                  -----------     -----------       -----------
            Net oil & gas properties                                5,024,799       3,125,154         2,957,508

     Furniture, fixtures and equipment, at cost                        12,113           3,091             3,091

     Less: accumulated depreciation                                    (3,401)         (1,159)             (386)
                                                                  -----------     -----------       -----------

            Net furniture, fixtures, and equipment                      8,712           1,932             2,705

     Restricted deposits                                              863,089         301,835           301,835
     Other assets                                                     356,066              --                --
                                                                  -----------     -----------       -----------
     Total assets                                                 $ 9,465,224     $ 4,011,065       $ 4,494,343
                                                                  ===========     ===========       ===========

Liabilities and Stockholders' Equity
Current liabilities:

     Accounts payable                                             $   240,389     $   139,188       $   114,188
     Accrued liabilities                                              176,470          50,073            41,118
     Registration costs                                               100,000               0                 0
     Notes payable, current                                             6,754         776,235         1,500,000
     Discount on notes payable                                              0               0           (62,927)
     Royalties payable                                                 89,713               0               665
                                                                  -----------     -----------       -----------
            Total current liabilities                                 613,326         965,496         1,593,044

Long term liabilities:
     Notes payable                                                  4,000,000               0                  0
     Discount on notes payable                                     (1,093,452)              0                  0
     Asset retirement obligations                                     433,250         311,442           305,004
                                                                  -----------     -----------       -----------
            Total liabilities                                       3,953,124       1,276,938         1,898,048

Stockholders' equity:
     Common Stock, par value $0.001 per share; 100,000,000
     shares authorized, 24,774,606, 22,945,406 and 21,772,362
     issued and outstanding as of June 30, 2005, June 30, 2004,
     and December 31, 2003, respectively                               24,774          22,945            21,772
     Additional paid-in capital                                     9,611,767       4,453,905         3,398,178
     Deferred stock based compensation                               (595,283)       (378,136)         (486,750)
     Accumulated deficit                                           (3,529,158)     (1,364,587)         (336,905)
                                                                  -----------     -----------       -----------
            Total stockholders' equity                              5,512,100       2,734,127         2,596,295
                                                                  -----------     -----------       -----------
            Total liabilities and stockholders' equity            $ 9,465,224     $ 4,011,065       $ 4,494,343
                                                                  ===========     ===========       ===========
</TABLE>

          See accompanying notes to consolidated financial statements.

<PAGE>

                   NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES
                      Consolidated Statements of Operations

<TABLE>
<CAPTION>
                                                                                              For the Period from
                                                     Twelve Months                              September 23,2003
                                                     Ended June 30,     Six Months Ended    (inception) to December
                                                         2005            June 30, 2004             31, 2003
                                                     -------------      ---------------     -----------------------
<S>                                                  <C>                <C>                     <C>
Revenues:
      Oil sales                                      $  1,335,288       $    117,509            $     24,229
      Gas sales                                           358,433                649                      --
      Price risk management activities                    (58,534)                --                      --
                                                     ------------       ------------            ------------
               Total revenues                           1,635,187            118,158                  24,229

Expenses:
      Operating costs                                     874,876            134,420                  76,303
      Production taxes                                     68,386             14,581                   3,002
      Depreciation, depletion and amortization            260,124             41,549                  13,960
      Reverse merger fees and expenses                         --            370,000                      --
      General and administrative (includes
      non-cash stock-based compensation expense of
      $707,117, $108,614 and $50,400 the periods
      ending June 30, 2005, June 30, 2004 and
      December 31, 2003, respectively.)                 2,220,780            542,761                 239,093
                                                     ------------       ------------            ------------
               Total expenses                           3,424,166          1,103,311                 332,358
                                                     ------------       ------------            ------------
Loss from operations                                   (1,788,979)          (985,153)               (308,129)
Other revenues and expenses:
      Interest income                                      11,709              4,093                   1,148
      Interest expense                                   (387,301)           (46,622)                (29,924)
                                                     ------------       ------------            ------------
               Total other revenues and expenses         (375,592)           (42,529)                (28,776)
                                                     ------------       ------------            ------------
Net loss                                             $ (2,164,571)      $ (1,027,682)           $   (336,905)
                                                     ============       ============            ============
Loss per common share:
      basic and diluted                              $      (0.09)      $      (0.05)           $      (0.02)
                                                     ============       ============            ============
Weighted average number of common shares,
      basic and diluted                                23,533,922         22,057,614              20,091,720
                                                     ============       ============            ============
</TABLE>

          See accompanying notes to consolidated financial statements.

<PAGE>

<TABLE>
<CAPTION>
                                           NATURAL GAS SYSTEMS, INC. AND SUBIDIARIES
                                  Consolidated Statements of Changes in Stockholders' Equity
                        For the twelve months ended June 30, 2005, the six months ended June 30, 2004
                           and the Period from September 23, 2003 (Inception) to December 31, 2003

                            Shares          Dollars         Additional           Deferred        Accumulated         Total
                                                             Paid-in            Stock Based       Deficit         Stockholders'
                                                             Capital            Compensation                         Equity
<S>                         <C>                 <C>             <C>                <C>              <C>             <C>
Balances, September                 --     $        --     $           --     $          --     $         --    $          --
23, 2003
Sales of common             21,772,362          21,772          2,861,028                --               --        2,882,800
stock
Stock-based                         --              --            537,150          (486,750)              --          50,400
compensation
Net loss                            --              --                 --                --         (336,905)        (336,905)
Balances, December          21,772,362          21,772          3,398,178          (486,750)        (336,905)       2,596,295
31, 2003
Sales of common                923,377             923            825,977                --               --          826,900
stock before merger
Sales of common                249,667             250            229,750                --               --          230,000
stock
Deferred                            --              --                 --           108,614               --          108,614
compensation
Net loss                            --              --                 --                --       (1,027,682)      (1,027,682)
Balances, June 30,          22,945,406          22,945          4,453,905          (378,136)      (1,364,587)       2,734,127
2004
Sales of common              1,829,200           1,829          4,502,517                --               --        4,504,346
stock
Fair value of                       --              --          1,149,008                --               --        1,149,008
warrants issued
with debt
Transaction and                     --              --           (493,663)               --               --         (493,663)
registration costs
Deferred                            --              --                 --          (217,147)              --         (217,147)
compensation
Net loss                            --              --                 --                --       (2,164,571)      (2,164,571)
Balances, June 30,          24,774,606     $    24,774     $    9,611,767     $    (595,283)    $ (3,529,158)   $   5,512,100
2005
</TABLE>

          See accompanying notes to consolidated financial statements.

<PAGE>

                    NATURAL GAS SYSTEMS, INC. AND SUBIDIARIES
                      Consolidated Statements of Cash Flows

<TABLE>
<CAPTION>
                                                                                                                For the Period from
                                                                                                                 September 23, 2003
                                                                      Twelve Months Ended    Six Months Ended      (inception) to
                                                                         June 30, 2005         June 30, 2004      December 31, 2003
                                                                      -------------------    ----------------     -----------------
<S>                                                                       <C>                  <C>                  <C>
Cash flows from operating activities:
          Net loss                                                        $(2,164,571)         $(1,027,682)         $  (336,905)

          Adjustments to reconcile net loss to net cash
          provided (used) by operating activities:
                Depletion                                                     257,882               41,549               13,960
                Depreciation                                                    2,242                  773                  386
                Non-cash stock-based compensation expense                     707,117              108,614               50,400
                Accretion of asset retirement obligations                      21,824                6,438                3,169
                Accretion of debt discount and non-cash interest               78,882                   --               29,924
          Changes in assets and liabilities:
                Accounts receivable, trade                                   (276,374)              32,450              (28,762)
                Inventories                                                  (106,611)              (6,643)            (109,216)
                Accounts payable                                              101,201               24,999              114,188
                Royalties payable                                              89,713                   --                   --
                Accrued liabilities                                           226,397                8,289               41,783
                Prepaid expenses                                              (15,237)             (43,137)             (25,930)
                        Net cash used by operating activities              (1,077,535)            (854,350)            (247,003)
Cash flows from investing activities:
                Capital expenditures for oil and gas properties            (2,057,543)            (209,194)          (1,290,560)
                Capital expenditures for furniture, fixtures and
                equipment                                                      (9,022)                  --               (3,090)
                Restricted deposits and retainers                            (612,589)             205,000             (511,835)
                Other assets                                                  (99,469)                  --                   --
                                                                          -----------          -----------          -----------
                        Net cash used in investing activities              (2,778,623)              (4,194)          (1,805,485)
Cash flow from financing activities:
                Payments on notes payable                                  (1,725,167)            (710,327)                  --
                Proceeds from notes payable                                 3,806,678               49,490                   --
                Deferred financing costs                                     (279,924)                  --                   --
                Proceeds from issuance of common stock and fair
                value of warrants issued with debt                          4,729,091            1,056,900            2,882,800
                Transaction and registration costs                           (493,663)                  --                   --
                                                                          -----------          -----------          -----------
                        Net cash provided by financing activities           6,037,015              396,063            2,882,800
                                                                          -----------          -----------          -----------
          Increase (decrease) in cash and cash equivalents                  2,180,857             (462,481)             830,312
          Cash and cash equivalents, beginning of period                      367,831              830,312                   --
                                                                          -----------          -----------          -----------
          Cash and cash equivalents, end of period                        $ 2,548,688          $   367,831          $   830,312
                                                                          ===========          ===========          ===========

          Supplemental disclosure of cash flow information:

                Interest paid                                             $   308,419          $    46,622          $        --
                Income taxes paid                                         $        --          $        --          $        --
          Non-cash transactions:

                Seller note issued to acquire properties, net of
                discount                                                  $        --          $        --          $ 1,407,049

                Assumption of asset retirement obligations                $    99,984          $        --          $   301,835
</TABLE>

          See accompanying notes to consolidated financial statements.

<PAGE>

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  June 30, 2005

                   NATURAL GAS SYSTEMS, INC. AND SUBSIDIARIES

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., 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.

Headquartered in Houston, Texas, Natural Gas Systems, Inc. is a petroleum
company engaged primarily in the acquisition, exploitation and development of
properties for the production of crude oil and natural gas from underground
reservoirs. NGS acquires established oil and gas properties and exploits them
through the application of conventional and specialized technology to increase
production, ultimate recoveries, or both. At June 30, 2005, NGS conducted
operations through its 100% working interest in the Delhi, Tullos Urania,
Crossroads, and Colgrade fields in Louisiana. Tullos Urania, Crossroad and
Colgrade are referred to collectively herein as the "Tullos Field (Area)".

All regulatory filings and other historical information prior to May 26, 2004
apply to Reality, the predecessor of the Company. NGS trades on the OTC Bulletin
Board under the symbol NGSY.OB. All stock information is adjusted to reflect
Reality's 40:1 reverse stock split effected prior to the merger with NGS.

<PAGE>

2.    Significant Risks and Uncertainties

Preparation of the Company's 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.

The Company's business makes it 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 the Company's
current reliance on the concentration of a few wells. The reserve report dated
July 1, 2005, identified twelve wells that make up approximately 60% of the
Company's PV-10 proved reserves, as compared to six wells at July 1, 2004. For
the production month of June 2005, approximately 29% of the Company's production
was derived from three wells, as compared to 85% in June 2004.

3.    Summary of Significant Accounting Policies

Principles of Consolidation -- The 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 --The Company
follows 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
the Company to concentrations of credit risk consist primarily of trade accounts
receivable. The Company's customer base includes multiple purchasers of our oil
and gas products. Although the Company is directly affected by the well-being of
the oil and gas industry, management does not believe a significant credit risk
exists at June 30, 2005.

Revenue Recognition --The Company recognizes oil and natural gas revenues from
its interests in producing wells as oil and natural gas is sold. As a result,
the Company accrues revenues related to production sold for which the Company
has 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, 2005 and 2004, the valuation allowance was $0.

Accounting for Reverse Merger -- The Company accounted for its reverse-merger in
accordance with Staff Accounting Bulletin ("SAB") Topic 2A. Generally, the staff
of the Division of Corporate Finance considers reverse-mergers into public
shells to be capital transactions in substance, rather than business
combinations. That is, the transaction is equivalent to the issuance of stock by
the private company for the net monetary assets of the shell corporation,
accompanied by a recapitalization.

<PAGE>

Under this treatment, post reverse-acquisition comparative historical financial
statements are those of the "legal acquiree" (i.e., the "accounting acquirer"),
with appropriate disclosure concerning the change in the capital structure
effected at the acquisition date. In the Company's case, the historical
financial statements are those of the oil and gas operations of Old NGS, and the
Consolidated Statement Of Changes in Stockholder's Equity reflects the activity
of Old NGS prior to the merger. All share and per share amounts have been
adjusted to reflect the conversion ratio of shares exchanged between Reality and
Old NGS.

Also, in accordance with SAB Topic 2A, transaction costs incurred for the
reverse-merger, such as legal fees, investment banking fees and the like, may be
charged directly to equity only to the extent of the cash received, while all
costs in excess of cash received should be charged to expense. Accordingly,
since no cash was received, $370,000 in transaction fees was expensed in the
Company's financial statements.

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.
The Company accounts 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, notes payable and
seller notes. The carrying amounts of cash and cash equivalents, 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. The fair values of the seller notes
approximate their carrying amounts as of June 30, 2004, based upon interest
rates then available to us for borrowings with similar terms.

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.

Accounting for Price Risk Management activities - The Company enters 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 its oil and gas production. The Company
follows the provisions of the Statement of Financial Accounting Standards
("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities,
for the accounting of its 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 the earnings unless specific hedge accounting criteria
is met.

Upon adoption, the Company did not have any financial derivative contracts
utilized for non-trading purposes. Thus, the adoption of SFAS No. 133 had no
impact upon the Company. The Company has entered into certain over-the-counter
contracts to hedge the cash flow of part of the 2005 forecasted sale of oil and
gas production. The Company will not elect to document and designate these as
hedges. Thus, the changes in the fair value of these over-the-counter contracts
will be reflected in the earnings in the period in which they occur.

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 is in the process of evaluating whether SFAS No.
123R will have a significant impact of the Company's overall results of
operations or financial position.

4.    Acquisitions

In September 2003, Old NGS completed the acquisition of a 100% working interest
in the Delhi Field. The acquisition closed on September 25, 2003, whereby Old
NGS paid $995,000 in cash, issued a purchase money mortgage for $1,500,000 (See
Note 7, Notes Payable, for a description of the mortgage) and assumed a plugging
and abandonment reclamation liability in the amount of approximately $302,000
(see Note 5, Asset Retirement Obligations), in exchange for the conveyance of
all the underlying leasehold interests. In addition to the mortgage, the
property is burdened by an aggregate 20% royalty interest.

On May 26, 2004, Reality Interactive, Inc., a publicly traded Nevada corporation
("Reality"), executed an Agreement and Plan of Merger with Natural Gas Systems,
Inc., a private Delaware corporation ("Old NGS"), whereby the shareholders of
Old NGS received 21,749,478 shares of common stock of Reality, in exchange for
all of the 21,749,748 shares of Old NGS common stock then outstanding. The
operations and management of Old NGS became our own, and Reality's name was
changed to Natural Gas Systems, Inc., a Nevada corporation (the "Company" or
"NGS"). Immediately prior to the closing of the merger, Reality had virtually no
operations, assets or liabilities.

<PAGE>

On September 2, 2004, we purchased a 100% working interest in approximately 81
producing oil wells, 8 salt water disposal wells and 54 shut-in wells located in
La Salle and Winn Parishes, Louisiana. The purchase included leases covering
386.04 gross and net acres, and fee ownership of 2.33 acres around certain of
the wells. Fourteen of the 54 shut-in wells will require a new lease prior to
restoration of production. The purchase price was $725,000 less approximately
$20,000 in closing adjustments to reflect an effective date of July 1, 2004,
paid in cash, part of which was provided by the Bridge Loan described under Note
5. The acquisition was accounted for under the purchase method of accounting. No
goodwill arose from the purchase. Revenue and expense from the property was
recognized beginning September 1, 2004.

On February 3, 2005, we completed the purchase of a 100% working interest in
certain leases with approximately 65 producing oil wells, 9 salt water disposal
wells and 56 shut-in wells located in the Tullos Urania and Colgrade Fields in
La Salle and Winn Parishes, Louisiana. Four of the 56 shut-in wells required a
new lease prior to restoration of production. The purchase price was $812,733
less post-closing adjustments to reflect an effective date of December 1, 2004,
paid in cash. The acquisition was accounted for under the purchase method of
accounting. No goodwill arose from the purchase. Revenue and expense from the
property is recognized beginning February 1, 2005.

We believe that the foregoing property acquisitions are consistent with our
strategic business plan to acquire established oil and gas properties in order
to exploit them through the application of conventional and specialized
technology to increase production, ultimate recoveries, or both.

5.    Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 requires that an asset retirement obligation ("ARO")
associated with the retirement of a tangible long-lived asset be recognized as a
liability in the period in which a legal obligation is incurred and becomes
determinable, with an offsetting increase in the carrying amount of the
associated asset. The cost of the tangible asset, including the initially
recognized ARO, is depleted such that the cost of the ARO is recognized over the
useful life of the asset. The ARO is recorded at fair value, and accretion
expense will be recognized over time as the discounted liability is accreted to
its expected settlement value. The fair value of the ARO is measured using
expected future cash outflows discounted at the Company's credit-adjusted
risk-free interest rate. Fair value, to the extent possible, should include a
market risk premium for unforeseeable circumstances. Inherent in the fair value
calculation of ARO are numerous assumptions and judgments including the ultimate
settlement amounts, inflation factors, credit adjusted discount rates, timing of
settlement, and changes in the legal, regulatory, environmental, and political
environments. To the extent future revisions to these assumptions impact fair
value of the existing ARO liability, a corresponding adjustment is made to the
oil and gas property balance.

When an oil or gas property ceases economic production, we dismantle and remove
all surface equipment, plug the wells and restore the property's surface in
accordance with various regulations and agreements before abandoning the
property. The state of Louisiana requires operators of oil and gas properties to
secure plugging, abandonment and reclamation liabilities with financial
collateral in favor of the state. In the case of the Delhi Field, the previous
owner had established a Site Specific Trust Fund (SSTA Account) that is
considered a fully funded liability by the state of Louisiana. Pursuant to our
agreement to purchase the Delhi Field in September of 2003, we agreed to replace
the seller's collateral on the SSTA Account within 120 days of closing. During
the six months ended June 30, 2004, we replaced the seller's collateral by
posting a letter of credit in the face amount of $301,835, fully collateralized
by a certificate of deposit issued on Wells Fargo Bank. These restricted cash
equivalents are carried as "Other Assets" in our balance sheet.

In accordance with FAS 143, we recorded an estimated asset retirement obligation
("ARO") for our Delhi Field of approximately $302,000, of which $274,000 relates
to the Company's wells and $28,000 relates to wells operated by us for a third
party. Accordingly, we recorded an asset retirement obligation in the amount of
$302,000, with an offsetting $274,000 charge to the full cost pool and a $28,000
receivable due from the 3rd party at December 31, 2003. The receivable was
collected during the six months ended June 30, 2004.

With respect to our property acquisitions in the Tullos Field Area in late 2004
and early 2005, we recorded an estimated combined ARO liability totaling $99,984
based on the assessment we made during our fourth quarter of fiscal 2005.

The following table describes the change in our asset retirement obligations for
the periods from September 23, 2003 (inception) to June 30, 2005:

Asset retirement obligation at September 23, 2003                  $   301,835
Accretion expense for 2003                                               3,169
Asset retirement obligation at December 31, 2003                       305,004
Accretion expense for 2004                                               6,438
Asset retirement obligation at June 30, 2004                           311,442
Asset retirement costs in 2005                                          99,984
Accretion expense for 2005                                              21,824
Asset retirement obligation at June 30, 2005                       $   433,250

6.    Oil and Gas Properties

Depletion expense for the period from September 23, 2003 (inception) to December
31, 2003, the six months ended June 30, 2004 and the twelve months ended June
30, 2005 totaled $13,960, $41,549 and $257,882, respectively. During 2003, no
costs were excluded from amortization. As of June 30, 2004 and June 30, 2005,
$105,225 and $61,887 of costs, respectively, were not being amortized.

<PAGE>

7.    Notes Payable

The following table sets forth the Company's notes payable balances as of the
dates indicated:

<TABLE>
<CAPTION>
                  Borrowing                      June 30,        June 30,       December 31,
                  ---------                        2005           2004             2003
                                                 ----------     ----------       ----------
<S>                                              <C>            <C>              <C>
Delhi Mortgage Notes                             $       --     $  732,807       $1,436,973
AICCO Insurance Premium Loan                             --         43,428               --
Cananwill Insurance Premium Loan (current)            6,754             --               --
Prospect Energy 5-Year Note                       2,906,548             --               --
Bridge Loan by our Chairman of the Board                 --             --               --
Herlin Loan                                              --             --               --
Total outstanding                                $2,913,302     $  776,235       $1,436,973
</TABLE>

DELHI MORTGAGE NOTES: In September 2003, we issued $1,500,000 of notes payable
in connection with our acquisition of the Delhi Field. The notes were
collateralized by a first mortgage on our Delhi Field and were payable to the
sellers in twelve equal monthly installments beginning on January 30, 2004 and
ending December 2004. Although the notes did not bear any interest, we imputed
interest at 8% per annum, thus resulting in an initial recorded principal amount
of $1,407,049. The Delhi Mortgage Notes were paid from a combination of loan
proceeds from Bridge Loans and the Company's cash flow.

AICCO LOAN: In May 2004, we borrowed $49,490 to finance 70% of our Director and
Officer's liability insurance premiums. The loan required eight level
mortgage-amortizing payments in the amount of $6,350 per month, including 7%
interest per annum. At June 30, 2005, there were no outstanding amounts owed
under the AICCO Loan.

CANANWILL LOAN: In October 2004, we borrowed $33,186 to finance 80% of our
General Liability, Casualty and Well Control insurance premiums. The loan
required ten level payments in the amount of $3,399 per month, including 5.25%
interest per annum. At June 30, 2005, $6,754 was owed under the Cananwill
Insurance Premium Loan.

BRIDGE LOAN: From August through December, 2004, Laird Q. Cagan, our Chairman
and a major stockholder, loaned us, through a series of advances, $920,000,
pursuant to a secured 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 closing of the Prospect Facility described below. On
February 15, 2005, we repaid the Bridge Loan, totaling $953,589 with accrued
interest, in full.

HERLIN LOAN: In December, 2004, Mr. Herlin advanced us $3,000 for working
capital, with interest payable at 10% per annum. At June 30, 2005, there were no
amounts outstanding under the Herlin Loan.

PROSPECT FACILITY: 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 on the total $4,800,000 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 the Bridge Loan,
immediate re-development of our existing properties and for working capital
purposes. After taking into account the effect of the completion of the February
2005 acquisition of properties (see Note 2 to our consolidated financial
statements), the closing of the Prospect Facility and our recent private
placement of common stock described below, and before taking into account the
effect of any new projects or acquisitions, we believed that our current
liquidity and anticipated operating cash flows were sufficient to allow the
remaining $800,000 commitment under the Facility to expire on May 3, 2005.

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 will be
$4,000,000 due to accretion of the original issue discount, which is described
below.

Under the terms of the Prospect Facility, each advance required us to issue two
securities, a debt security and an equity security (in the form of irrevocable
and revocable warrants) as follows:

      (i)   The debt securities issued under the Facility (the "Prospect
            Loan(s)") are secured by all of our assets, bear an initial interest
            rate of 14% per annum payable in arrears on the "face" (the par or
            matured amount of the loan), mature on February 2, 2010 and do not
            require principal payments until the end of the term. The loans are
            subject to voluntary prepayment premiums equal to 9% of the face
            amount as of August 3, 2005, declining .5% for each three month
            period, thereafter. For each draw under the Facility, we recorded a
            loan with an imputed discount equivalent to the value of the
            Prospect Warrants described below. Through June 30, 2005, we had
            drawn $4,000,000 under the Facility, crediting $2,850,992 (net of
            the discount described below) to the Prospect Loan. The fair value
            of the Prospect Warrants of $1,149,008 was recorded as a discount on
            the Prospect Loans with a corresponding credit to additional paid-in
            capital for the Prospect Warrants. The discount is accreted as
            additional loan interest expense using the interest rate method over
            the five-year life of the loan, yielding an annual effective
            interest rate of 27.26% and 24.87% for the first and second Prospect
            Loans, respectively.

<PAGE>

      (ii)  The equity securities issued under the Facility consisted of
            irrevocable and revocable warrants (the "Prospect Warrants"). An
            irrevocable warrant to purchase one share of our common stock was
            issued to Prospect for each $6.666667 drawn under the Facility, and
            a revocable warrant to purchase one share of our common stock was
            issued for each $10 drawn under the Facility. Through June 30, 2005
            we had issued to Prospect Energy irrevocable warrants to acquire up
            to 600,000 shares of common stock exercisable over a five-year term
            at a price of $0.75 per common share, and revocable warrants to
            acquire up to 400,000 shares of common stock on the same terms,
            except that the revocable warrants will be automatically canceled if
            we attain certain financial targets by the end of February 2006, and
            such revocable warrants cannot be exercised prior to such date. As
            described under the Prospect Loan above, the Prospect Warrants have
            been credited to additional paid-in capital in the amount of
            $1,149,008, based on their estimated fair value. The holder of the
            shares of common stock underlying the Prospect Warrants is the
            beneficiary of a registration rights agreement. Terms of the
            registration rights agreement and assumptions underlying fair value
            of the warrants are described in Note 8, "Common Stock, Stock
            Options and Warrants".

Among other restrictions and subject to certain exceptions, the Prospect
Facility restricts us from creating liens, entering into certain types of
mergers or consolidations, incurring additional indebtedness, the payment of
dividends, changing the character of our business, or engaging in certain types
of transactions. The Prospect Loan agreement also requires us to maintain
specified financial ratios, including a 1.5:1 ratio of borrowing base to debt
and, commencing not later than the three months ended January 31, 2006, a 2.0:1
ratio of EBITDA (earnings before interest, income tax and other non-cash charges
such as depreciation, depletion and amortization) to interest.

At June 30, 2005, we were in compliance with the terms of the Facility. At May
31, 2005, we had however, not maintained a required performance milestone, thus
causing us to increase our restricted cash account under the terms of the
Facility from $300,000 to $560,000. The increased amount is reflected as
restricted deposits in our balance sheet at June 30, 2005, although transfer of
the additional $260,000 is pending our receipt of further instructions from
Prospect.

Looking forward, we are required to maintain an EBITDA to interest payable
coverage of 2:1, beginning no later than the three month period ending January
31, 2006, in order to maintain compliance. Our ability to comply with this
requirement is dependent on achieving certain operating results, especially with
respect to our planned drilling program of proved undeveloped reserves at our
Delhi Field beginning in May 2005. At September 27, 2005, our Delhi drilling
program had not yet begun due to delays caused by casualty repairs sustained by
the drilling contractor for the account of another customer. Due to these
delays, we can give no assurance that the delayed results from this program will
provide sufficient EBITDA to meet the required interest coverage ratio. If such
a covenant breach occurs and is not waived by Prospect, the debt would become
immediately due and payable. Since we do not have sufficient liquid assets to
prepay our debt in full, we would be required to refinance all or a portion of
our existing debt or obtain additional financing. If we were unable to refinance
our debt or obtain additional financing, we would be required to curtail
portions of our development program, sell assets, and/or reduce capital
expenditures. Had we been subject to this requirement on June 30, 2005, we would
not have been in compliance.

8.    Common Stock, Stock Options and Warrants

Common Stock

From September 23, 2003 (Inception) through December 31, 2003, Old NGS issued
18,000,000 common shares as founder's capital at $0.001 per share, and sold
2,864,600 of its $0.001 par value common shares at $1.00 per share through a
private equity offering to accredited investors. At December 31, 2003, Reality
had issued and outstanding 256,598 shares of its $0.001 par value common stock.

From January 1, 2004, up to, but not including, the merger closing on May 26,
2004, Reality issued 689,663 of its $0.001 par value common shares, net of
cancellations and redemptions. During the same period in 2004, Old NGS sold
884,878 of its $0.001 par value common shares to accredited investors for
$886,900 gross proceeds, less $60,000 in commissions equal to 8% of the gross
cash proceeds and the issuance of 7 year term warrants equal to 8% of the shares
issued, for the account of Chadbourn Securities, Inc. and Laird Q. Cagan, an
affiliate of the Company as described in Note 9, "Related Party Transactions".

At the closing of the merger on May 26, 2004, Reality issued 21,749,478 of its
$0.001 par value common shares in exchange for all of the 21,749,478 issued and
outstanding $0.001 par value common shares of Old NGS.

Subsequent to the merger closing through June 30, 2004, we sold 249,667 shares
of our $0.001 par value common shares for gross proceeds of $250,000, less
$30,000 in commissions and the same warrant structure described above for the
account of Chadbourn Securities, Inc. and Laird Q. Cagan.

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 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 as described in Note 7, "Notes Payable".

<PAGE>

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.

No options were issued during the six months ended June 30, 2004. However, an
aggregate 200,000 options had been authorized, but not issued, to two members of
our Board of Directors, Messrs. DiPaolo and Stoever.

During the twelve months ended June 30, 2005, there were 1,500,000 shares of
common stock issued or issuable upon exercise of outstanding options, and 25,000
shares issued directly under the 2004 Stock Plan to employees, all subject to
various vesting requirements, leaving 2,305,000 shares of common stock available
for issuance under the 2004 Stock Plan, after taking into account awards to
non-employees totaling 170,000 shares. Of these awards, options to purchase
100,000 shares were issued to each of our directors, E.J. DiPaolo and Gene
Stoever, in consideration for their services; options to purchase 500,000,
350,000, 350,000 and 100,000 shares were granted to Messrs. Herlin, McDonald,
Mazzanti and Joe; and a direct stock grant of 25,000 shares was made to Mr.
Mazzanti. All of these options and grants were accounted for under APB 25,
giving rise to $44,000 of expense spread over a two year vesting period for
Messrs. Stoever and DiPaolo, and $40,225 of expense spread over a one year
vesting period for Mr. Mazzanti.

Non-Plan Warrants to Employees
During the twelve months ended June 30, 2005, Mr. Herlin was granted revocable
warrants to purchase 287,500 of common stock, and Mr. Mazzanti was granted
revocable warrants to purchase 200,000 shares. These warrants were accounted for
under APB 25, and gave rise to no Company expense during fiscal 2005, because
the exercise price of Mr. Herlin's warrants exceeded fair value of the stock at
June 30, 2005, and vesting of Mr. Mazzanti's warrants is based on a future
specified event that has not yet occurred.

A reconciliation of reported 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:

<TABLE>
<CAPTION>
                                                                                                           For the Period
                                                                                                           from September
                                                                                                              23, 2003
                                                                          Twelve Months     Six Months     (Inception) to
                                                                          ended June 30,    ended June      December 31,
                                                                               2005          30, 2004           2003
                                                                         ----------------------------------------------------
<S>                                                                          <C>            <C>                 <C>
Pro forma impact of Fair Value Method (SFAS 148):
     Net loss attributable to common stockholders, as reported               ($2,164,571)   ($1,027,682)        ($336,905)
     Plus share based compensation expense determined under APB 25               131,313        108,614            50,400
     Less compensation expense determined under Fair Value Method               (359,457)      (110,978)          (51,858)
                                                                         ----------------------------------------------------
     Pro forma net loss attributable to common stockholders                  ($2,392,715)   ($1,030,046)        ($338,363)

Loss per share (basic & diluted):
     As reported                                                                  ($0.09)        ($0.05)           ($0.02)
     Pro Forma                                                                    ($0.10)        ($0.05)           ($0.02)
        Weighted average Black-Scholes fair value assumptions:
               Risk free interest rate                                     4.18%  - 4.93%          2.50%             2.50%
               Expected life                                                   3-4 years        3 years           3 years
               Expected volatility                                            104% - 130%         131.0%            131.0%
               Expected dividend yield                                               0.0%           0.0%              0.0%
</TABLE>

<PAGE>

Fair values were estimated at the date of grants 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, 2005, 2,305,000 shares were available for grant under the
plans.

A summary of option and warrant transactions issued to employees for the period
from September 23, 2003 (inception) to June 30, 2005 follows:

<TABLE>
<CAPTION>
                                                                                        Weighted
                                                         Weighted       Weighted        average
                                                          average        average       Remaining
                                            Number of    Exercise      Grants Date     Contractual
                                             Shares        Price       Fair Value         Life
                                            ---------    ---------     -----------    -----------
<S>                                         <C>            <C>                         <C>
For the Period from September 23,
2003 (Inception) to December 31, 2003

                              Granted       500,000        $0.13         $0.94
                            Exercised             0           --
                             Canceled             0           --

Outstanding at December 31, 2003            500,000        $0.13                       9.8 years

Six months ended June 30, 2004
                              Granted             0
                            Exercised             0
                             Canceled             0

Outstanding at June 30, 2004                500,000        $0.13                       9.3 years

Twelve months ended June 30, 2005

                              Granted    2,012,500*        $1.67         $1.31*
                            Exercised             0
                             Canceled             0
Outstanding at June 30, 2005              2,512,500        $1.37                       9.4 years
</TABLE>

* Mr. Mazzanti's revocable warrants to purchase 200,000 shares are included in
the number of shares granted, but have not been used to calculate the weighted
average grants date fair value since the award is contingent on a specified
future event.

These options and warrants vest during the following fiscal years ended June 30
as follows: Vested at June 30, 2005 - 303,125; 2006 - 696,875; 2007 - 571,875;
2008 - 493,750 and 2009 - 446,875.

Options, Warrants and Grants to Non-Employees

At June 30, 2005, outstanding warrants and options, excluding employees, to
purchase the Company's $0.001 par value common shares were as follows:

<TABLE>
<CAPTION>
                                               Warrants and Options Outstanding
                                                    (Excluding Employees)
Holder                                          Range of             Outstanding at    Exercisable
                                           Exercisable Prices        June 30, 2005    June 30, 2005
                                          ---------------------      ---------------  -------------
<S>                                       <C>             <C>              <C>           <C>
Cagan McAfee Capital Partners, LLC        $1.00           $1.00              165,000       165,000
Chadbourn Securities, Inc.                $1.50           $2.50                8,574         8,574
Laird Q. Cagan                            $1.00           $2.50              142,143       142,143
Tatum Partners                            $.001          $0.001              262,500       262,500
Prospect Energy                           $0.75           $0.75            1,000,000       600,000
Steve Lee (counsel to the Company)        $.001           $1.80               60,000        10,000
Other                                     $1.00           $2.00              146,750       146,750
---------------------------------------------------------------------------------------------------
Total                                                                      1,784,967     1,334,967
</TABLE>

<PAGE>

As of June 30, 2004, we issued warrants to purchase 240,000 shares of common
stock to Cagan McAfee Capital Partners and their assigns in connection with
arranging the merger, options to purchase 100,000 shares of common stock to
Steve Lee under the 2003 Stock Plan (90,000 of which have been exercised) and a
warrant to purchase 79,931 share of common stock in connection with Cagan
McAfee's capital raising services, of which warrants to purchase 66,784 and
3,147 shares of common stock were issued to Laird Q. Cagan and Chadbourn
Securities, Inc., respectively. Mr. Lee's award gave rise to $99,900 of fair
value expense under SFAS 123 over the one year vesting period, using the
Black-Scholes model with the following assumptions: Volatility - 131%, Risk Free
Rate - 5.0%, Estimated Term - 3 years, and Dividends - 0.

During fiscal year ended June 30, 2005, we issued warrants to purchase 142,536
shares of common stock in connection with capital raising services, of which we
issued warrants to purchase 75,359 and 5,427 shares of common stock to Laird Q.
Cagan and Chadbourn Securities, Inc., 61,750 to third parties and options to
purchase 50,000 shares to Steve Lee under the 2004 Stock Plan.

During the fiscal year ended June 30, 2005, we also made a direct stock grant
for 120,000 shares to Liviakis Communications (excluded from the table above)
for investor relations services and issued options to purchase 50,000 shares of
our stock to Mr. Lee under our 2004 Plan. Mr. Lee's grant gives rise to $67,519
of fair value expense under SFAS 123, to be spread over a four year vesting
schedule. Fair value was derived using the Black-Scholes model using the
following assumptions: Volatility - 110%, Risk Free Rate - 4.18%, Estimated Term
- 4 years, and Dividends - 0. The Liviakis stock grant gives rise to $263,880 of
expense, spread over a one year vesting schedule, beginning monthly in April
2005. The fair value of the Liviakis grant under SFAS 123 was equivalent to the
fair value of our stock on the date of grant.

Also during the fiscal year ended 2005, we issued warrants to purchase 1,000,000
shares under the Prospect Facility, recording fair value in the amount of
$1,149,008 using the Black-Scholes model, using the following assumptions:
Volatility - 102.8%, Risk Free Rate - 4.93%, Estimated Term - 3 years, Dividend
- 0. Certain of these warrants will not vest if the Company reaches certain
financial thresholds. As a result, those warrants were discounted in determining
fair value. Finally, we issued warrants to purchase 262,500 shares to Tatum
Partners, recognizing $432,976 of SFAS 123 fair value expense in the current
year, wherein fair value was equal to intrinsic value since there was no time
value associated with the grant.

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 requires us, among other
things, to obtain and maintain an effective registration statement with the SEC
for Rubicon's shares, failing which, subjects us to the payment of penalties not
to exceed 1% of the share proceeds, or $30,000, for each month of
non-compliance. Penalties are incurred for each month for which a registration
statement has not become effective, beginning October 6, 2005. Penalties may
also 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 can the
penalty cumulatively exceed 8% or $240,000. The SEC is currently reviewing the
registration statement we filed June 6, 2005 on Form SB-2, and we can give no
assurance that our registration statement will become or be maintained effective
after October 6, 2005. Accordingly, we have accrued, against our equity account
$100,000 for penalties and other transaction costs which may become due.

We have also entered into other registration rights agreements, the effect of
which gives the holders the right to "piggyback" their shares, from time to
time, as we register other shares.

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
of $15,000. 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, we
pay a cash fee equal to 8% of gross equity proceeds and warrants equal to 8% of
the shares placed by CMCP. During 2003, we expensed and paid CMCP $32,500 for
monthly retainers.

In connection with the founding of the Company, 18,000,000 shares of Old NGS
common stock were directly and indirectly purchased by various parties as
founder's shares, including, 1,000,000 shares by Robert S. Herlin as an
incentive to perform as the Company's President and CEO; 1,000,000 shares by
Liviakis Financial Communications, Inc., the Company's investor relations firm;
7,500,000 shares by Laird Q. Cagan, the Company's Chairman and Managing Director
of CMCP; and 5,700,000 by Eric M. McAfee, Managing Director of CMCP, and 450,000
by John Pimentel, a member of the Company's Board of Directors.

During the six months ended June 30, 2004 we expensed $90,000 in monthly
retainers, $60,000 of which remained unpaid at June 30, 2004, and charged
$80,000 to stockholder's equity as a reduction of the proceeds from common stock
sales in the amount of $1,000,000. The $80,000 paid to Chadbourn Securities and
Laird Q. Cagan was for commissions from the sale of our common stock. Also
during the six months ended June 30, 2004 we issued warrants to purchase 319,932
shares of Common Stock to CMCP, Chadbourn Securities and Laird Q. Cagan and
their assigns in connection with arranging the merger, (240,000 warrants) and
placement of 999,145 common shares (79,932 warrants). These warrants have a
$1.00 exercise price and a seven year term.

<PAGE>

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 closing of
the Prospect Facility. On February 15, 2005, we repaid the Bridge Loan, totaling
$953,589 with accrued interest, in full.

Eric McAfee, also a Managing Director of Cagan McAfee Capital Partners, has
served as Vice Chairman of the Board of Verdisys, Inc., the provider of certain
horizontal drilling services to the Company. Subsequently in 2004, Mr. McAfee
resigned from the Board of Directors of Verdisys, but continues to hold shares
in both companies. Mr. McAfee has represented to the Company that he is also a
50% owner of Berg McAfee Companies, LLC, which owns approximately 30% of
Verdisys, Inc. NGS paid $130,000 to Verdisys (Blast Energy) during 2003 and
$25,960 during 2004 for horizontal drilling services.

10.   Supplemental Oil and Gas Disclosures (unaudited)

               Costs Incurred in Oil and Gas Producing Activities

<TABLE>
<CAPTION>
                                                                                         For the Period From
                                                                                          September 23, 2003
                                       Twelve Months Ended       Six Months Ended           (Inception) to
                                          June 30, 2005            June 30, 2004          December 31, 2003
                                       ---------------------     ------------------     -----------------------
<S>                                              <C>                      <C>                       <C>
Property acquisition costs:
     Proved                                      $1,554,149                 $6,855                  $2,363,716
     P&A liability assumed                           99,984                      0                     273,760
     Unproved                                        61,887                105,225                           0
Exploration costs                                         0                      0                           0
Development costs                                   441,508                 97,114                     333,992
                                       ---------------------     ------------------     -----------------------
Total property acquisition costs                 $2,157,528               $209,194                  $2,971,468
                                       =====================     ==================     =======================


           Results of Operations for Oil and Gas Producing Activities

<CAPTION>
                                                                                                              For the Period From
                                                                  Twelve Months         Six Months Ended       September 23, 2003
                                                                  Ended June 30,         Ended June 30,          (Inception) to
                                                                       2005                   2004              December 31, 2003
                                                                 ------------------    -------------------    ---------------------
<S>                                                                    <C>                      <C>                       <C>
Oil and gas sales                                                      $1,635,187               $118,158                  $24,229
Production costs                                                         (874,876)              (134,420)                 (76,303)
Production taxes                                                          (68,386)               (14,581)                  (3,002)
Depletion                                                                (257,882)               (41,549)                 (13,960)
                                                                 ------------------    -------------------    ---------------------
Results of operations for oil and gas producing
activities (excluding corporate overhead and financing costs)            $434,043               ($72,392)                ($69,036)
                                                                 ==================    ===================    =====================
</TABLE>

                    Proved Developed and Undeveloped Reserves
              Prepared by W.D. Von Gonten & Co. Petroleum Engineers

The following table sets forth the net proved reserves of the Company as of July
1, 2005, and the changes therein for the periods from September 23, 2003
(inception) to July 1, 2005. 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.

<PAGE>

                                                    Oil (bbls)      Gas (mcf)
                                                    ----------      ---------
September 23, 2003                                  --              --
Purchases of minerals in place                      241,219         778,700
Extensions and discoveries                          --              --
Revisions                                           --              --
Production                                          (857)           --
Sales of minerals in place                          --              --

December 31, 2003                                   240,362         778,700
Purchases of minerals in place
Extensions and discoveries                          76,412          293,419
Revisions                                           (74,060)        (563,440)
Production                                          (3,180)         (123)
Sales of minerals in place                          --              --
July 1, 2004                                        239,534         508,556*
Purchases of minerals in place                      418,217         --
Extensions and discoveries                          242,340         330,023
Revisions                                           (100,978)       (34,290)
Production                                          (27,230)        (72,166)
Sales of minerals in place                          --              --
July 1, 2005                                        771,883         732,123
Proved developed reserves:
December 31, 2003                                   240,400         778,700
July 1, 2004                                        238,900         508,556*
July 1, 2005                                        771,800         732,300*
------------------

*     Includes 5,000 and 7,300 BBL of NGL's converted at 6 BBLs / MCF for July
      1, 2004 and July 1, 2005, respectively

            Standardized Measure of Discounted Future Net Cash Flows
              at December 31, 2003, June 30, 2004 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.

<TABLE>
<CAPTION>
                                                                           For the Period From
                                                                            September 23, 2003
                                  Twelve Months Ended   Six Months Ended      (Inception) to
                                     June 30, 2005        June 30, 2004     December 31, 2003
                                  -------------------   ----------------   -------------------
<S>                                <C>                   <C>                   <C>
Future cash inflows                $ 46,841,246          $ 11,549,850          $ 13,318,169
Future production costs             (20,028,389)           (2,978,139)           (2,895,677)
Future development costs             (1,920,000)             (450,000)             (357,000)
Future income taxes                  (6,036,000)           (1,465,000)           (2,412,000)
     Future net cash flows         $ 18,856,857             6,656,711             7,653,492
                                   ------------          ------------          ------------
10% annual discount                  (5,615,779)           (1,476,100)           (1,479,544)
                                   ------------          ------------          ------------
     Standardized Measure          $ 13,241,078          $  5,180,611          $  6,173,948
                                   ============          ============          ============
</TABLE>

<PAGE>

                         Changes in Standardized Measure

The following table sets forth the changes in standardized measure of discounted
future net cash flows for the period from September 23, 2003 (inception) to
December 31, 2003, the six months ended June 30, 2004 and the twelve months
ended June 30, 2005:

<TABLE>
<CAPTION>
                                        Twelve Months Ended                  Six Months                  For the Period From
                                           June 30, 2005                        Ended                    September 23, 2003
                                                                            June 30, 2004                  (Inception) to
                                                                                                          December 31, 2003
     -------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                                 <C>                          <C>
     Standardized Measure,           5,180,611                           6,173,948                    --
     beginning

     Net change in income taxes      (3,209,706)                         737,006                      (1,945,722)

     Oil and gas sales, net of       (691,925)                           30,843                       51,065
     costs

     Discoveries and extensions      7,131,907

     Purchase of minerals in place   4,780,920                           --                            8,068,605

     Changes in prices and costs     3,285,724                           82,230                       --

     Change in developments costs    (1,045,275)                         (84,042)                     --

     Accretion of discount           518,061                             308,697                      --

     Revisions of estimates          (2,670,979)                         (2,131,318)                  --

     Other                           (38,260)                            63,247                       --
     -------------------------------------------------------------------------------------------------------------------------------
     Standardized Measure, ending    13,241,078                          5,180,611                    6,173,948
</TABLE>

11.   Restricted Deposits

At June 30, 2005, Restricted deposits includes $301,835 securing a letter of
credit posted with the State of Louisiana for future plugging and abandonment
liabilities related to the Delhi Field, and $560,000 related to the debt service
reserve under the Prospect Facility.

Of these amounts, $201,835 and $200,000 exceed FDIC insurance limits in
depository accounts at Wells Fargo Bank and AmSouth Bank, respectively.

12.   Income Taxes

The tax effect of significant temporary differences representing deferred tax
assets and liabilities at December 31, 2003, June 30, 2004 and June 30, 2005 are
as follows:

<TABLE>
<CAPTION>
                                         June 30,           June 30,         December 31,
                                          2005                2004               2003
                                       -----------        -----------        -----------
<S>                                    <C>                <C>                <C>
Oil and gas properties                 ($  178,144)       ($   69,389)       ($  113,558)
Basis in subsidiary stock                  125,800                  0                  0
Other                                      (10,159)                 0                  0
Net operating loss carryforwards         6,324,900            366,425            228,043
Valuation allowance                     (6,262,397)          (297,036)          (114,485)
                                       -----------        -----------        -----------

Net deferred tax asset                 $         0        $         0        $         0
                                       ===========        ===========        ===========
</TABLE>


The increase in the valuation allowance during fiscal 2003, 2004 and 2005 of
$114,485, $182,551 and $5,965,361 respectively, is the result of net tax losses
incurred during the year. The increase in the valuation allowance in fiscal 2005
is mostly attributable to the recognition of Reality's NOL carryforwards from
prior years, in addition to current year net tax loss. Reality's NOL
carryforwards had not been previously recognized as the tax impact of the
transaction described in the Note 1 was not resolved until fiscal year 2005.

As of June 30, 2005, we have net operating loss carryforwards of approximately
$18,603,000 that will expire in 2023, 2024 and 2025. Future utilization of the
net operating loss carryforwards and other tax attributes, absent a change in
law, will be significantly limited by changes in the ownership of the Company in
May 2004 under section 382 of the Internal Revenue Code.

<PAGE>

The following is a reconciliation of the Company's expected income tax expense
(benefit) based on statutory rates to the actual expense (benefit):

                                                                For the Period
                                Twelve             Six          From September
                                Months            Months          23, 2003
                              Ended June        Ended June      (Inception) to
                               30, 2005          30, 2004      December 31, 2003
                              ---------------- -------------- ------------------
Income taxes (benefit) at      ($735,954)       ($349,412)       ($114,548)
US statutory rate
Non-deductible
amortization and expenses             --          165,141               62
Deferred Stock
Compensation and non-
deductible expenses              240,860               --               --
Deferred tax asset
valuation allowance
adjustment                       495,094          182,551          114,485
Net operating losses                  --               --               --
Other                                  0            1,720                1
                               ---------        ---------        ---------

13.   Leases

The Company is obligated for operating lease payments related to the Company's
headquarters in Houston, Texas, and a gas processing plant servicing the
Company's Delhi Field. Minimum lease payments are as follows:

Fiscal 2006:        $   42,921
Fiscal 2007:        $   33,980
Total               $   76,901

Lease expense was $121,799 for the twelve months ended June 30, 2005; $44,770
for the six months ended June 30, 2004 and $8,541 for the three months ended
December 31, 2003.

14.   Liquidity

As of June 30, 2005, we had $2,548,688 of unrestricted cash and positive working
capital of $2,599,232, versus negative working capital of $383,352 at June 30,
2004, and negative working capital of $360,749 at December 31, 2003. Also at
June 30, 2005, the PV10 value of our proved oil and gas reserves to the face
value of our debt was over 4:1.

Nevertheless, our net losses totaling $2,164,571, $1,027,682 and $336,905 for
the twelve months ended June 30, 2005, the six months ended June 30, 2004 and
the period from September 23 (inception) to December 31, 2003, respectively, and
our requirement to maintain an EBITDA to interest payable coverage of 2:1,
beginning no later than the three month period ending January 31, 2006 under the
Prospect Facility, raises questions about our liquidity. Although our net cash
losses have narrowed on an annualized basis, our ability to comply with the
EBITDA to interest coverage ratio is dependent on achieving certain operating
results, especially with respect to our planned drilling program of proved
undeveloped reserves at our Delhi Field beginning in May 2005. At September 27,
2005, our Delhi drilling program had not yet begun, due to delays caused by
casualty repairs sustained by the drilling contractor for the account of another
customer. Due to these delays, we can give no assurance that the delayed results
from this program will provide sufficient EBITDA to meet the required interest
coverage ratio. If such a covenant breach occurs and is not waived by Prospect,
the debt would become immediately due and payable. Since we do not have
sufficient liquid assets to prepay our debt in full, we would be required to
refinance all or a portion of our existing debt or obtain additional financing.
If we were unable to refinance our debt or obtain additional financing, we would
be required to curtail portions of our development program, sell assets, and/or
reduce capital expenditures. Had we been subject to this requirement on June 30,
2005, we would not have been in compliance.

We are currently addressing these issues by taking actions to expedite the
repair and mobilization of the drilling rig that is causing the delay in our
proved undeveloped reserve drilling program, possibly adding to the expense of
our contract. Alternatively, it may be necessary for us to seek another rig,
although we can give no assurance that one will be available within our
timeframe, given tight industry supplies. We have also obtained covenant relief
from Prospect as discussed under Note 18, "Subsequent Events."

Based on our current estimates of production and current oil and gas prices, and
absent a default causing acceleration of our debt, we currently have sufficient
capital reserves to satisfy our short-term obligations and to fund our
anticipated development activities through December 31, 2005. We will require
more capital or success in our development activities, or both, to execute
additional acquisitions, fund our development plan beyond 2005, replace our
existing depleting reserves or exploit any technology projects we may develop
from time to time.

<PAGE>

15.   Loss per Share

The following table sets forth the computation of basic and diluted loss per
share:

<TABLE>
<CAPTION>
                                                                                                                  For the Period
                                                                                                                from September 23,
                                                                     Twelve Months         Six Months            2003 (Inception)
                                                                     ended June 30,      ended June 30,          to December 31,
                                                                        2005                  2004                    2003
                                                                     -------------       -------------           --------------
<S>                                                                   <C>                    <C>                        <C>
Numerator:
     Net loss applicable to common stockholders                       ($2,164,571)           ($1,027,682)               ($336,905)
     Plus income impact of assumed conversions:
          Preferred Stock dividends                                           N/A                    N/A                      N/A
          Interest on convertible subordinated notes                          N/A                    N/A                      N/A

                                                                  ---------------        ---------------          ---------------
     Net loss applicable to common stockholders plus assumed
conversions                                                            (2,164,571)            (1,027,682)                (336,905)
                                                                  ===============        ===============          ===============

Denominator:                                                           23,533,922             22,057,614               20,091,720

Affect of potentially dilutive common shares:
        Warrants                                                              N/A                    N/A                      N/A
        Employee and director stock options                                   N/A                    N/A                      N/A
        Convertible preferred stock                                           N/A                    N/A                      N/A
        Convertible subordinated notes                                        N/A                    N/A                      N/A
        Redeemable preferred stock                                            N/A                    N/A                      N/A
Denominator for dilutive earnings per share -  weighted average
shares
     Outstanding and assumed conversions                               23,533,922             22,057,614               20,091,720

Loss per common share:
Basic and diluted                                                          ($0.09)                ($0.05)                  ($0.02)
                                                                  ===============        ===============          ===============

Shares issuable from securities that could potentially dilute
earnings per share in the future that were not included in
the computation of loss per share because their effect was
anti-dilutive:                                                          4,222,468                919,932                  600,000
</TABLE>

16.   Commodity Hedging

As required under our credit agreement with Prospect Energy, we have placed
price risk contracts aggregating more than 50% of the production volumes that
our outside petroleum engineers have estimated to occur from our existing proved
developed producing reserves over the next two years. The Prospect Facility also
requires us to extend such coverage on a rolling two-year basis through the five
year term of the Facility.

As a part of this program, we purchased a series of price floors from Wells
Fargo Bank, 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.
In accordance with SFAS No. 133, we have recorded these derivative puts at cost,
and have marked them to market at the end of each month. Through June 30, 2005,
$58,534 has been marked to market and expensed, leaving a remaining asset of
$13,466.

These derivatives are in addition to future forward delivery contracts we
entered into with Plains Marketing L.P., to complete our requirements under the
Prospect Facility.

<PAGE>

17.   Major Customers

All of our crude oil is currently sold to Plains Marketing L.P., all of our
natural gas is currently being sold to Texla Energy Management, Inc. and all of
our natural gas liquids are currently sold to a subsidiary of Enbridge Energy
Partners LP.

18.   Subsequent Events

Effective September 22, 2005, we entered into an amendment to the Prospect
Facility, thereby obtaining covenant relief with respect to our obligation to
maintain an EBITDA to interest payable coverage ratio of 2:1. The amendment
changes our compliance date to begin not later than the three months ended
January 31, 2006, as compared to October 31, 2005 under the original terms of
the agreement. This amendment was effected in order to allow us to proceed with
the delayed drilling program of proved undeveloped reserve locations in our
Delhi Field, the results of which we are relying on to achieve the required
EBITDA coverage ratio. As explained earlier, the drilling program has been
delayed due to a casualty sustained to the contracted rig, while demobilizing
from a previous customer. In exchange for the amendment, we have issued to
Prospect revocable warrants to purchase 200,000 shares of our common stock,
exercisable at $1.36 per share over five years. The warrants will be
automatically revoked in the event we achieve $200,000 in EBITDA, as defined,
for any one month period through April 30, 2006. We also agreed to limit our
acquisitions of additional oil and gas properties to a maximum of $100,000 plus
any new funds raised, until we achieve a trailing three month EBITDA to interest
coverage ratio of 2.0. The limitation does not include any evaluation costs, so
that we may continue to review new projects. For additional details, the
amendment to the Loan Agreement and the Revocable Warrant Agreement are attached
to our Form 10-K for the year ended June 30, 2005, as Exhibits 10.30 and 10.31,
respectively.

All of our oil and gas assets are located in northern Louisiana. On August 29,
2005, the center of Hurricane Katrina, a Category 5 storm, came onshore just
east of New Orleans, Louisiana. None of our oil and gas property suffered
casualty loss from this storm, as the area was minimally affected by rains off
of the west side of Katrina as she progressed inland veering to the east. It is
possible, however, that in the aftermath of the storm we may become subject to
supply chain disruptions affecting the availability of fuel, power, supplies and
the like at any time, although we have not experienced any of these disruptions
to date.

<PAGE>

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Natural Gas Systems, Inc.
Houston, Texas

      We have audited the accompanying consolidated balance sheets of Natural
Gas Systems, Inc. as of June 30, 2005, June 30, 2004 and December 31, 2003 and
the related consolidated statements of operations, stockholders' equity, and
cash flows for the twelve months ended June 30, 2005, the six months ended June
30, 2004 and the period from September 23, 2003 (inception) to December 31,
2003. 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
Natural Gas Systems, Inc. and subsidiaries as of June 30, 2005, June 30, 2004
and December 31, 2003, and the consolidated results of their operations and
their cash flows for each of the periods then ended, and the period from
September 23, 2003 (inception) to December 31, 2003, in conformity with
accounting principles generally accepted in the United States of America.

      As discussed in Note 14 to the financial statements, the Company has
sustained losses since inception and has a requirement under its debt facility
to meet a prescribed interest coverage ratio beginning with the three month
period ended January 31, 2006. At the present time, the Company is not
generating sufficient cash flow from operations to meet the required interest
coverage ratio. If the Company does not meet the interest coverage ratio, the
debt holder has the right to cause the outstanding debt of $4,000,000 to become
immediately due and payable. At the present time, the Company does not have the
resources to pay off the debt in the event it becomes immediately due and
payable.


HEIN & ASSOCIATES LLP


Houston, Texas
August 27, 2005, except for the first paragraph in Note 18 as to which the date
is September 27, 2005.

<PAGE>

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 8A. CONTROLS AND PROCEDURES

Our management evaluated, with the participation of our Chief Executive Officer
and Chief Financial Officer, the effectiveness of our disclosure controls and
procedures, as of the end of the period covered by this report. Based on this
evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the Company's disclosure controls and procedures are effective to ensure
that information required to be disclosed by the Company in the reports that it
files or submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission's rules and forms.

There were no changes in our internal control over financial reporting that
occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.

ITEM 8B. OTHER INFORMATION

<PAGE>

                                    PART III.

ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS

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 year 2005.

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 year 2005.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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 year 2005.

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 year 2005.

<PAGE>

ITEM 13. EXHIBITS AND REPORTS

Index of Exhibits

<TABLE>
<CAPTION>

<S>       <C>                                                                                                    <C>
     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  Certificate of Draw Request, dated as of February 16, 2005, between the Company and Prospect           Previously Filed
          Energy Corporation ("Prospect")
    10.2  Loan Agreement, dated as of February 2, 2005, between the Company and  Prospect                        Previously Filed
    10.3  Mortgage, Collateral Assignment, Security Agreement and Financing Statement by NGS Sub. Corp.,         Previously Filed
          dated as of February 2, 2005
    10.4  Company Promissory Note in favor of Prospect                                                           Previously Filed
    10.5  Security Agreement, dated as of February 2, 2005, between NGS Sub Corp. and Prospect                   Previously Filed
    10.6   Security Agreement, dated as of February 2, 2005, between Natural Gas Systems, Inc., a Delaware       Previously Filed
          corporation, and Prospect
    10.7  Guaranty Agreement, dated as of February 2, 2005, by Natural Gas Systems, Inc., a Delaware             Previously Filed
          corporation, NGS Sub. Corp., Arkla   Petroleum, L.L.C. and Four Star Development Corporation, in
          favor of Prospect
    10.8  Warrant Agreement, dated as of February 2, 2005, between the Company  and Prospect                     Previously Filed
    10.9  Company Common Stock Purchase Warrant in favor of Prospect, dated as of February 2, 2005               Previously Filed
   10.10  Revocable Warrant Agreement, dated as of February 2, 2005, between the Company and Prospect            Previously Filed
   10.11  Company Revocable Common Stock Purchase Warrant in favor of Prospect, dated as of February 2, 2005     Previously Filed
   10.12  Registration Rights Agreement, dated as of February 2, 2005, between the Company and Prospect          Previously Filed
   10.13  Executive Employment Agreement, Robert S. Herlin, dated April 4, 2005                                  Previously Filed
   10.14  Herlin Stock Option Agreement, dated April 4, 2005                                                     Previously Filed
   10.15  Herlin Warrant Agreement, dated April 4, 2005                                                          Previously Filed
   10.16  Amended and Restated Tatum Resources Agreement, dated April 4,  2005                                   Previously Filed
   10.17  Tatum Warrant Agreement, dated April 4, 2005                                                           Previously Filed
   10.18  Executive Employment Agreement, Sterling H. McDonald, dated April 4, 2005                              Previously Filed
</TABLE>

<PAGE>

<TABLE>
<CAPTION>

<S>       <C>                                                                                                    <C>
   10.19  McDonald Stock Option Agreement, dated April 4, 2005                                                   Previously Filed
   10.20  Secured Promissory Note - Laird Q. Cagan, dated August 10, 2004                                        Previously Filed
   10.21  Amendment to Secured Promissory Note - Laird Q. Cagan, dated  September 20, 2004                       Previously Filed
   10.22  Securities Purchase Agreement dated as of May 6, 2005, by and between Natural Gas Systems, Inc.        Previously Filed
          and Rubicon Master Fund
   10.23  Registration Rights Agreement dated as of May 6, 2005, by and between Natural Gas  Systems, Inc.       Previously Filed
          and Rubicon Master Fund
   10.24  Amendment to Consulting Agreement, dated as of May 4, 2005, by and between Natural Gas Systems,        Previously Filed
          Inc., and Liviakis Financial Communications, Inc.
   10.25  Stock Grant Agreement, dated as of May 4, 2005, by and between Natural Gas Systems, Inc. and           Previously Filed
          Liviakis Financial Communications, Inc.
   10.26  Executive Employment Agreement, Daryl V. Mazzanti ("Mazzanti"), dated June 23, 2005                    Previously Filed
   10.27  Mazzanti Stock Option Agreement, dated June 23 2005                                                    Previously Filed
   10.28  Mazzanti Stock Grant Agreement dated June 23, 2005                                                     Previously Filed
   10.29  Mazzanti Revocable Warrant Agreement, dated June 23, 2005                                              Previously Filed
   10.30  Amendment to Prospect Loan Agreement, dated September 27, 2005, between the Company and Prospect       Included
   10.31  Revocable Warrant Agreement , dated as of September 27, 2005, between the Company and Prospect         Included
    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.
</TABLE>

ITEM 14. PRINCIPAL ACCOUNTANT 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 year 2005.

<PAGE>

                                   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.

                                    NATURAL GAS SYSTEMS, INC.


                                    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, 2005

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, 2005       /s/   E. J. DIPAOLO        Director
                               -------------------
                                     E. J. DiPaolo


      September 27, 2005       /s/   GENE STOEVER         Director
                               -------------------
                                     Gene Stoever


      September 27, 2005       /s/   JOHN PIMENTEL        Director
                               -------------------
                                     John Pimentel


      September 27, 2005       /s/   LAIRD CAGAN          Chairman of the Board
                               -------------------
                                     Laird Cagan