UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): April 26, 2006
DYNADAPT SYSTEM, INC.
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(Name of Registrant)
Colorado 84-1491159
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(State of incorporation) (I.R.S. Employer
Identification No.)
Suite 200 E, 10200 W. 44th Ave, WheatRidge, CO 80033
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 940-2090
Check the appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant under any of the
following provisions.
[_] Written communications pursuant to Rule 425 under the Securities Act
(17 CFR240.14d-2(b))
[_] Soliciting material pursuant to Rule 14a-12 under Exchange Act
(17 CFR240.14a-12)
[_] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange
Act (17 CFR240.14d-2(b))
[_] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange
Act (17 CFR240.13e-4(c))
Section 1 - Registrant's Business and Operations
Item 1.01 Entry into a Material Definitive Agreement
The Company entered into a Plan and Agreement of Reorganization on April
21, 2006, with shareholders of Sun River Energy, Inc. and Sun River Energy, Inc.
Under the terms of the Agreement shareholders of Sun River Energy Inc. agreed to
receive a total of 8,633,333 shares of common stock of the Company in exchange
for 8,633,333 shares of Sun River, constituting 100% of the issued and
outstanding common stock of Sun River. The Agreement required delivery of
audited F/S of the Sun River at time of closing. The closing occurred on April
28, 2006, and the company issued 8,633,333 shares of restricted common stock.
Certain short term debts of Sun River totalling $1,164,000 were accepted as part
of the acquisition and are consolidated into the financial statements.
Item 1.02 Termination of a Material Definitive Agreement
None
Item 1.03 Bankruptcy or Receivership
None
Section 2 - Financial Information
Item 2.01 Completion of Acquisition or Disposition of Assets
The Company has adopted a new business plan in the energy industry with the
acquisition of Sun River Energy, Inc. as a wholly owned subsidiary.
General
Dynadapt Systems, Inc. ("the Company") has changed its business plan to
focus on development as an independent energy company engaged in the,
exploration of North American unconventional natural gas properties and
conventional oil and gas exploration. The Company has acquired Sun River Energy,
Inc. as a wholly owned subsidiary which holds 150,000 acres of fee minerals and
7,200 gross acres of leases upon which the company hopes to explore for oil and
gas. Our intended operations are principally energy prospects in the Rocky
Mountain region including a coal bed methane prospect located in the Raton Basin
in Northern New Mexico. and the Company is seeking other opportunities. The
Company is also evaluating the additional prospects it has obtained in Johnson
and Natrona Counties Wyoming.
1
The Company maintains its principal executive offices at #200 E, 10200 W.
44th Ave., Wheat Ridge, CO 80033, telephone (303) 940-2090.
The authorized capitalization of the Company is 100,000,000 shares of no
par value common stock, of which 9,518,000 shares were issued and outstanding at
April 28, 2006.
This report on Form 8-K contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"), including statements regarding, among other items,
(1) the Company's business plans, (2) anticipated trends in the Company's
business and its future results of operations, (3) market conditions in the oil
and gas industry, (4) the ability of the Company to make and integrate
acquisitions, (5) the impact of governmentalregulation, (6) financial market
conditions.
These forward-looking statements are based largely on the Company's
expectations and are subject to a number of risks and uncertainties, many of
which are beyond the Company's control. Actual results could differ materially
from those implied by these forward-looking statements as a result of, among
other things, (1) a decline in oil and natural gas production, (2) a decline in
oil and natural gas prices, (3) incorrect estimations of required capital
expenditures, (4) increases in the cost of drilling, (5) completion and gas
collection, (6) an increase in the cost of production and operations, (7) an
inability to meet schedules (8) changes in general economic conditions or
failure to ever achieve any economic production. These and other risks are
discussed under the heading "--Certain Risks." In light of these and other risks
and uncertainties of which the Company may be unaware or which the Company
currently deems immaterial, there can be no assurance that actual results will
be as projected in the forward-looking statements.
Business Activities and Recent Developments
Raton Basin
The Company's current operations will initially be focused on
exploring a coal bed methane prospect located in the Raton Basin in Northern New
Mexico.
2
The Company has assignments of oil and gas leases in the Raton Basin. The
Company has approximately 8,000 gross acres of coal bed methane prospects in the
Basin some of which are fee (90% interest) and some of which are a lease
assignment. As of this date, the Company had no proved reserves or producing
wells. The Company's drilling program is planned to enable the Company to build
an inventory of additional drilling locations. The Company has identified at
least 10 additional drilling locations on its Raton Basin prospect The Company
will operate all of its prospects in the Raton Basin and holds working interests
of 100% on a 80% NRI.
Customers and Markets
Gas Marketing and Transportation
The Company intends sell any produced gas on an index basis to credit
worthy companies including utilities, other end users and maybe energy marketing
companies. Natural gas production from the Raton Basin maybe sold into the
Mid-Continent through Colorado Interstate Gas Company.
In the United States, oil and natural gas liquids are sold under
contracts extending up to a year based upon monthly refiner price postings,
which generally approximate the price of West Texas Intermediate for crude oil
and Applicable Conway, Kansas posting for natural gas liquids, adjusted to
reflect transportation costs and quality. In Canada, oil and natural gas liquids
are sold under short-term contracts at refiner posted prices for Alberta and
Saskatchewan, adjusted to reflect transportation costs and quality. The
Company's oil and natural gas liquids are sold at spot market prices or under
short-term contracts.
The Company has no transportation commitments.
Major Customers
The Company has no customers that represent in excess of 10% of the
Company's total sales, since there have been no sales. The Company does not
believe that a loss of any or all of these customers would have a material
adverse effect on its business.
3
Competition
The Company competes in virtually all facets of its business with
numerous other companies, including many that have significantly greater
resources. Such competitors may be able to pay more for desirable leases and to
evaluate, bid for and purchase a greater number of properties than the financial
or personnel resources of the Company permit. The ability of the Company to
increase reserves in the future will be dependent on its ability to select and
acquire suitable producing properties and prospects for future exploration and
development. The availability of a market for oil and natural gas production
depends upon numerous factors beyond the control of producers, including but not
limited to the availability of other domestic or imported production, the
locations and capacity of pipelines and the effect of federal, state, provincial
and local regulation on such production.
Government Regulation of the Oil and Gas Industry
General
The Company's business is affected by numerous laws and regulations,
including, among others, laws and regulations relating to energy, environment,
conservation and tax. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil and/or criminal penalties, the
imposition of injunctive relief or both. Moreover, changes in any of these laws
and regulations could have a material adverse effect on the Company's business.
In view of the many uncertainties with respect to current and future laws and
regulations, including their applicability to the Company, the Company cannot
predict the overall effect of such laws and regulations on its future
operations.
The Company believes that its operations comply in all material respects
with applicable laws and regulations and that the existence and enforcement of
such laws and regulations have no more restrictive effect on the Company's
method of operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing.
Federal Regulation of the Sale and Transportation of Oil and Gas
Various aspects of the Company's oil and natural gas operations are
regulated by agencies of the federal government. The Federal Energy Regulatory
Commission ("FERC") regulates the transportation and sale for resale of natural
gas in interstate commerce pursuant to the Natural Gas Act of 1938 ("NGA") and
the Natural Gas Policy Act of 1978 ("NGPA"). In the past, the federal government
has regulated the prices at which oil and gas could be sold. While "first sales"
by producers of natural gas and all sales of crude oil, condensate and natural
gas liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead sales in the
natural gas industry began with the enactment of the NGPA in 1978. In 1989,
4
Congress enacted the Natural Gas Wellhead Decontrol Act (the "Decontrol Act").
The Decontrol Act removed all NGA and NGPA price and non-price controls
affecting wellhead sales of natural gas effective January 1, 1993.
Commencing in April 1992, the FERC issued Orders Nos. 636, 636-A, 636-B,
636-C and 636-D ("Order No. 636"), which require interstate pipelines to provide
transportation services separate, or "unbundled," from the pipelines' sales of
gas. Also, Order No. 636 requires pipelines to provide open access
transportation on a nondiscriminatory basis that is equal for all natural gas
shippers. Although Order No. 636 does not directly regulate the Company's
production activities, the FERC has stated that it intends for Order No. 636 to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company's activities.
The courts have largely affirmed the significant features of Order No.
636 and numerous related orders pertaining to the individual pipelines, although
certain appeals remain pending and the FERC continues to review and modify its
open access regulations. In particular, the FERC is conducting a broad review of
its transportation regulations, including how they operate in conjunction with
state proposals for retail gas marketing restructuring, whether to eliminate
cost-of-service rates for short-term transportation, whether to allocate all
short-term capacity on the basis of competitive auctions, and whether changes to
long-term transportation policies may also be appropriate to avoid a market bias
toward short-term contracts. In February 2000, the FERC issued Order No. 637
amending certain regulations governing interstate natural gas pipeline companies
in response to the development of more competitive markets for natural gas and
natural gas transportation. The goal of Order No. 637 is to "fine tune" the open
access regulations implemented by Order No. 636 and to accommodate subsequent
changes in the market. Key provisions of Order No. 637 include: (1) permitting
value-oriented peak/off peak rates to better allocate revenue responsibility
between short-term and long-term markets; (2) permitting term-differentiated
rates, in order to better allocate risks between shippers and the pipeline; (3)
revising the regulations related to scheduling procedures, capacity,
segmentation, imbalance management, and penalties; (4) retaining the right of
first refusal ("ROFR") and the five-year matching cap for long-term shippers at
maximum rates, but significantly narrowing the ROFR for customers that the FERC
5
does not deem to be captive; and (5) adopting new website reporting requirements
that include daily transactional data on all firm and interruptible contracts
and daily reporting of scheduled quantities at points or segments. Most major
aspects of Order No. 637 were upheld on judicial review, though certain issues,
such as capacity segmentation and rights of first refusal, were remanded to the
FERC, which issued a remand order in October of 2002. In January of 2004, the
FERC denied rehearing of its October 2002 remand order. The Company cannot
predict whether judicial review will be sought of the FERC's remand order and,
if so, whether and to what extent FERC's market reforms will survive such review
and, if they do, whether the FERC's actions will achieve the goal of increasing
competition in markets in which the Company's natural gas is sold. However, the
Company does not believe that it will be affected by any action taken materially
differently than other natural gas producers and marketers with which it
competes.
Commencing in October 1993, the FERC issued a series of rules (Order
Nos. 561 and 561-A) establishing an indexing system under which oil pipelines
will be able to change their transportation rates, subject to prescribed ceiling
levels. The indexing system, which allows pipelines to make rate changes to
track changes in the Producer Price Index for Finished Goods, minus one percent,
became effective January 1, 1995. The Company does not believe that these rules
affect the Company any differently than other oil producers and marketers with
which it competes.
The FERC has also issued numerous orders confirming the sale and
abandonment of natural gas gathering facilities previously owned by interstate
pipelines and acknowledging that if the FERC does not have jurisdiction over
services provided thereon, then such facilities and services may be subject to
regulation by state authorities in accordance with state law. A number of states
have either enacted new laws or are considering the adequacy of existing laws
affecting gathering rates and/or services.
Other state regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, nondiscriminatory take
requirements, but does not generally entail rate regulation. Thus, natural gas
gathering may receive greater regulatory scrutiny of state agencies in the
future. The Company's gathering operations could be adversely affected should
they be subject in the future to increased state regulation of rates or
services, although the Company does not believe that it would be affected by
such regulation any differently than other natural gas producers or gatherers.
In addition, the FERC's approval of transfers of previously regulated gathering
systems to independent or pipeline affiliated gathering companies that are not
subject to FERC regulation may affect competition for gathering or natural gas
marketing services in areas served by those systems and thus may affect both the
costs and the nature of gathering services that may be available to interested
producers or shippers in the future.
6
The Company owns certain natural gas pipeline facilities that it
believes meet the traditional tests the FERC has used to establish a pipeline's
status as a gatherer not subject to the FERC's jurisdiction. Whether on state or
federal land, natural gas gathering may receive greater regulatory scrutiny in
the post-Order No. 636 environment.
The Company may conduct certain operations on federal oil and gas leases,
which are administered by the Minerals Management Service ("MMS"). Federal
leases contain relatively standard terms and require compliance with detailed
MMS regulations and orders, which are subject to change. Among other
restrictions, the MMS has regulations restricting the flaring or venting of
natural gas, and the MMS has proposed to amend such regulations to prohibit the
flaring of liquid hydrocarbons and oil without prior authorization. Under
certain circumstances, the MMS may require any company operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition, cash flows
and operations. The MMS issued a final rule that amended its regulations
governing the valuation of crude oil produced from federal leases. This rule,
which became effective June 1, 2000, provides that the MMS will collect
royalties based on the market value of oil produced from federal leases. On
August 20, 2003, the MMS issued a proposed rule that would change certain
components of its valuation procedures for the calculation of royalties owed for
crude oil sales. The proposed changes included changing the valuation basis for
transactions not at arm's-length from spot to NYMEX prices adjusted for locality
and quality differentials, and clarifying the treatment of transactions under a
joint operating agreement. Final comments on the proposed rule were due on
November 10, 2003. The Company has no way of knowing whether the MMS will
implement the proposed changes in a final rule or what effect such changes, if
implemented, will have on the Company's results of operations, However, the
Company does not believe that this proposed rule would affect it any differently
than other producers and marketers of crude oil. We have no federal leases as of
date hereof.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC, the MMS, state commissions and
the courts. The Company cannot predict when or whether any such proposals and
proceedings may become effective. In the past, the natural gas industry has been
heavily regulated. There is no assurance that the regulatory approach currently
pursued by various agencies will continue indefinitely. Notwithstanding the
foregoing, the Company does not anticipate that compliance with existing
federal, state and local laws, rules and regulations will have a material or
significantly adverse effect upon the capital expenditures, earnings or
competitive position of the Company or its subsidiaries. No material portion of
our business is subject to re-negotiation of profits or termination of
contracts or subcontracts at the election of the federal government.
7
The BLM controls isolated parcels of federally owned surface and/or
minerals in the areas of interests. Drilling and development of federal minerals
and construction activities on federal surface are subject to the National
Environmental Policy Act ("NEPA"). BLM has not completed an environmental
assessment under NEPA. To date, no wells have been drilled on BLM minerals in
the Raton Basin. In the Raton Basin, the BLM must complete an environmental
assessment, and any future wells would need to be approved based on the results
of the environmental assessment. Development of adjacent fee lands and minerals
within the Raton Basin may proceed unhindered and access to fee lands is not
expected to hinder by the presence of isolated parcels of federal surface.
Future activities within the Piceance and Uintah Basins will be subject to NEPA.
The scope and effect are not known at the present time. We do not have any BLM
leases as of this date.
State Regulations
The Company's operations are also subject to regulation at the state
level and, in some cases, county, municipal and local governmental levels. Such
regulation includes (1) requiring permits for the drilling of wells, (2)
maintaining bonding requirements in order to drill or operate wells and (3)
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used and produced in
connection with operations. The Company's operations are also subject to various
conservation laws and regulations. These include (1) proration units, (2) the
density of wells that may be drilled, and (3) the unitization or pooling of oil
and gas properties. In addition, state conservation laws establish maximum rates
of production from oil and gas wells, which generally limit the venting or
flaring of gas and impose certain requirements regarding the ratability of
production. State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements, but (except as noted above) does not generally entail rate
regulation. These regulatory burdens may affect profitability, and the Company
is unable to predict the future cost or impact of complying with such
regulations.
8
Environmental Matters
The Company is subject to extensive federal, state, and local environmental
laws and regulations that, among other things, regulate the discharge or
disposal of substances into the environment and otherwise are intended to
protect the environment. Numerous governmental agencies issue rules and
regulations to implement and enforce such laws, which are often difficult and
costly to comply with and which carry substantial administrative, civil and/or
criminal penalties and, in some cases, injunctive relief for failure to comply.
Some laws and regulations relating to the protection of the environment may, in
certain circumstances, impose "strict liability" for environmental
contamination. Such laws and regulations render a person or company liable for
environmental and natural resource damages, cleanup costs and, in the case of
oil spills in certain states, consequential damages without regard to negligence
or fault. Other laws and regulations may require the rate of oil and natural gas
production to be below the economically optimal rate or may even restrict or
prohibit exploration or production activities in environmentally sensitive
areas. In addition, state laws often require some form of remedial action such
as closure of inactive pits and plugging of abandoned wells to prevent pollution
from former or suspended operations. Moreover, from time to time, legislation or
other initiatives are proposed to Congress or to state and local governments
that would place more onerous conditions on the treatment, storage, disposal or
clean-up of certain oil and gas exploration and production wastes. If such
legislation or other initiatives were to be enacted or adopted, it could have an
adverse impact on the operating costs of the Company, as well as the oil and gas
industry in general. The regulatory burden on the oil and natural gas industry
increases the Company's cost and risk of doing business and consequently affects
its profitability.
Compliance with these environmental requirements, including financial
assurance requirements and the costs associated with the cleanup of any spill,
could have a material adverse effect upon the Company's capital expenditures,
earnings or competitive position. The Company believes that it is in substantial
compliance with current applicable environmental laws and regulations and that
continued compliance with existing requirements will not have a material adverse
impact on it. Nevertheless, changes in environmental laws and regulations have
the potential to adversely affect the Company's operations. For example, the
federal Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended ("CERCLA"), also known as the "Superfund" law, and analogous
state laws impose liability, without regard to fault or the legality of the
original conduct, on certain classes of persons with respect to the release of a
"hazardous substance" into the environment. These persons include the current or
prior owner or operator of the disposal site or sites where the release occurred
and companies that transported, disposed or arranged for the transport or
disposal of the hazardous substances found at the site. Persons who are or were
responsible for releases of hazardous substances under CERCLA may be subject to
strict and joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the federal or state
government to pursue such claims. It is also not uncommon for neighboring
landowners and other third parties to file claims for personal injury or
property or natural resource damages allegedly caused by the hazardous
substances released into the environment. Under CERCLA, certain oil and gas
materials and products are, by definition, excluded from the term "hazardous
substances."
9
The Company may own or lease, numerous properties that have long been used
for oil and gas exploration and production. Although the predecessor owners
utilized operating and disposal practices that were standard for the industry at
the time, hazardous substances in the past may have been disposed of or released
on or under the properties owned or leased by the Company or on or under other
locations where such substances have been taken or placed for disposal. In
addition, many of these properties have from time to time been operated by third
parties whose management of substances was not under the Company's control.
These properties and the substances disposed thereon may be subject to CERCLA,
the Resource Conservation and Recovery Act, as amended, and analogous state laws
and regulations. Under such laws and regulations, the Company could be required
to remove or remediate previously disposed wastes (including wastes disposed of
or released by prior owners or operators) or property contamination (including
groundwater contamination by prior owners or operators), or to perform remedial
plugging or pit closure operations to prevent future contamination. The Company
has no knowledge of any environmental hazards as of date hereof.
In connection with the Company's coal bed methane gas exploration the
Company from time to time may conduct production enhancement techniques,
including various activities designed to induce hydraulic fracturing of the coal
bed. While the Company may perform its production enhancement techniques in
substantial compliance with the requirements set forth by the State laws,
neither State nor the federal Environmental Protection Agency ("EPA") regulates
this coal bed formation hydraulic fracturing as a form of underground injection.
It is possible that hydraulic fracturing of coal beds for methane gas production
will become regulated within the United States as a form of underground
injection, resulting in the imposition of stricter performance standards (which,
if not met, could result in diminished opportunities for methane gas production
enhancement) and increased administrative and operating costs for the Company.
Management cannot predict whether potential future regulation of hydraulic
fracturing as a form of underground injection would have an adverse material
effect on the Company's operations or financial position. However, such
regulation is not expected to be any more burdensome to the Company than it
would be to other similarly situated companies involved in coal bed methane gas
production or tight gas sands production within the United States.
In the Company's coal bed methane gas exploration the Company typically may
bring naturally occurring groundwater to the surface as a by-product of the
production of methane gas. This "produced water" is either re-injected into the
subsurface or stored or disposed of in evaporation ponds or permitted natural
collection features located on the surface at or near the well-site in
compliance with federal and state statutes and regulations. In some cases, the
produced water is used for stock watering, agricultural or dust suppression
10
purposes, also in substantial compliance with federal, state and local laws and
regulations. Under the Federal Water Pollution Control Act (also referred to as
the "Clean Water Act") and various other state requirements and regulations, the
EPA and the State of Colorado's Department of Public Health and the Environment
assert administrative and regulatory enforcement authority over the discharge of
produced water. Where the Company can meet federal and state regulatory
requirements and applicable water quality standards, disposal of produced water
by discharge to surface water is an option.
The Clean Water Act imposes restrictions and strict controls regarding the
discharge of produced waters and other oil and gas wastes into navigable waters.
Permits must be obtained to discharge pollutants into state and federal waters.
The Clean Water Act and analogous state laws provide for civil, criminal and
administrative penalties for any unauthorized discharges of oil and other
hazardous substances in reportable quantities and may impose substantial
potential liability for the costs of removal, remediation and damages. State
water discharge regulations and the federal National Pollutant Discharge
Elimination System permits applicable to the oil and gas industry generally
prohibit the discharge of produced water, sand and some other substances into
coastal waters. The cost to comply with zero discharges mandated under federal
and state law is not expected to have a material adverse impact on the Company's
financial condition and results of operations. Some oil and gas exploration and
production facilities are required to obtain permits for their storm water
discharges. Costs may be incurred in connection with treatment of wastewater or
developing storm water pollution prevention plans.
The Company's operations may involve the use of gas-fired compressors to
transport collected gas; these compressors are subject to federal and state
regulations for the control of air emissions. The Company will obtain
construction permits for compression it enjoys production from any coal bed
methane. However, in the future, additional facilities could become subject to
additional monitoring and pollution control requirements as compressor
facilities are expanded.
11
The Oil Pollution Act of 1990 ("OPA") imposes regulations on
"responsible parties" related to the prevention of oil spills and liability for
damages resulting from spills in waters of the United States. A "responsible
party" includes the owner or operator of an onshore facility, vessel or
pipeline, or the lessee or permittee of the area in which an offshore facility
is located. OPA assigns strict, joint and several liability to each responsible
party for oil removal costs and a variety of public and private damages,
including natural resource damages. While liability limits apply in some
circumstances, a party cannot take advantage of liability limits if the spill
was caused by gross negligence or willful misconduct or resulted from violation
of a federal safety, construction or operating regulation, or if the party fails
to report a spill or to cooperate fully in the cleanup. Even if applicable, the
liability limits for onshore facilities require the responsible party to pay all
removal costs, plus up to $350 million in other damages. Few defenses exist to
the liability imposed by OPA. Failure to comply with ongoing requirements or
inadequate cooperation during a spill event may subject a responsible party to
administrative, civil or criminal enforcement.
At this time, the Company is not required and otherwise has no plans to
make any material capital expenditures to install pollution control devices at
any facilities.
Title to Properties
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time the Company acquires leases of properties
believed to be suitable for drilling operations. Prior to the commencement of
drilling operations, a thorough title examination of the drill site tract is
conducted by independent attorneys. Once production from a given well is
established, the Company prepares a division order title report indicating the
proper parties and percentages for payment of production proceeds, including
royalties. The Company believes that the titles to its leasehold properties are
good and defensible in accordance with standards generally acceptable in the oil
and gas industry.
Employees
At April 28, 2006, the Company no employees.
Certain Risks
Oil and gas prices are volatile, and an extended decline in prices
would hurt the Company's profitability and financial condition.
The Company's management expects the markets for oil and gas to continue
to be volatile. Any substantial or extended decline in the price of oil or gas
would negatively affect the Company's financial condition and results of
operations. Company revenues, operating results, profitability, future rate
of growth and the carrying value of oil and gas properties depend heavily on
prevailing market prices for oil and gas. A material decline could reduce the
Company's cash flow and borrowing capacity, as well as the value and the amount
of its oil and gas reserves. Various factors beyond the Company's control can
affect prices of oil and gas. These factors include:
12
o
worldwide and domestic supplies of oil and gas;
o the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and production
controls;
o
political instability or armed conflict in oil or gas producing
regions;
o
the price and level of foreign imports;
o
worldwide economic conditions;
o
marketability of production;
o
the level of consumer demand;
o
the price, availability and acceptance of alternative fuels;
o
the availability of pipeline capacity;
o
weather conditions; and
o
actions of federal, state, and local authorities.
These external factors and the volatile nature of the energy markets
make it difficult to estimate future commodity prices.
In addition, the Company may be required to write down or impair the
carrying value of the Company's oil and gas properties when oil and gas prices
are depressed or unusually volatile. If a write-down is required, it would
result in a charge to earnings and book value. Once incurred, a write-down of
oil and gas properties is not reversible at a later date. The Company reviews,
on a quarterly basis, the carrying value of its oil and gas properties under the
full cost accounting rules of the SEC. Under these rules, capitalized costs of
13
proved oil and gas properties, as adjusted for estimated asset retirement
obligations, may not exceed the present value of estimated future net revenues
from proved reserves, discounted at 10%. Application of the ceiling test
generally requires pricing future revenue at the unescalated prices in effect as
of the end of each fiscal quarter, after giving effect to the Company's cash
flow hedge positions, and requires a write-down for accounting purposes if the
ceiling is exceeded, even if prices were depressed for only a short period of
time.
The Company's intended operations will require large amounts of capital
that may not be recovered.
If the Company's future revenues were to decrease due to lower oil and
natural gas prices, decreased production or other reasons, and if it could not
obtain capital through its credit facilities or otherwise, the Company's ability
to execute its development plans, replace its reserves or maintain its
production levels could be greatly limited. The company's current development
plans will require it to make large capital expenditures for the exploration and
development of its oil and natural gas properties.
Historically, the Company has funded its capital expenditures through a
combination of funds generated the issuance of equity, and short-term financing
arrangements. Additional financing may not be available to the Company on
acceptable terms. Future cash flows and the availability of financing will be
subject to a number of variables, such as:
o
the success of the Company's prospects in the Raton,
and Powder River Basins;
o
the Company's success in locating and producing reserves;
o
the prices of oil and natural gas.
Issuing equity securities to satisfy the Company's financing
requirements could cause substantial dilution to existing stockholders. In
addition, debt financing could lead to a diversion of cash flow to satisfy debt
servicing obligations and restrictions on the Company's operations.
The Company's exploratory and development drilling activities may not
be successful.
14
The Company's future drilling activities may not be successful, and the
Company's management cannot be sure that the Company's overall drilling success
rate or the Company's drilling success rate for activity within a particular
area will not decline. In addition, the wells that the Company drills may not
recover all or any portion of the Company's capital investment in the wells,
infrastructure or the underlying leaseholds. The Company is currently in the
early stages of various exploration projects in the Rocky Mountain area of the
United States and the Company can offer no assurance that the development of
these projects will occur as scheduled or that actual results will be in line
with the Company's initial estimates. Unsuccessful drilling activities could
negatively affect the Company's results of operations and financial condition.
The cost of drilling, completing and operating wells is often uncertain, and a
number of factors can delay or prevent drilling operations, including: o
unexpected drilling conditions;
o
pressure or irregularities in formations;
o
equipment failures or accidents;
o
ability to hire and train personnel for drilling and completion
services;
o
adverse weather conditions;
o
compliance with governmental requirements; and
o
shortages or delays in the availability of drilling rigs and the
delivery of equipment.
In addition, the Company may not be able to obtain any options or lease
rights in potential drilling locations that it identifies. There is no guarantee
that the potential drilling locations that the Company has identified will ever
produce oil or natural gas.
The Company's acquisition activities may not be successful.
15
As part of the Company's growth strategy, the Company may make
additional acquisitions of businesses and properties. However, suitable
acquisition candidates may not be available on terms and conditions it finds
acceptable, and acquisitions pose substantial risks to the Company's business,
financial condition and results of operations. In pursuing acquisitions, the
Company competes with other companies, many of which have greater financial and
other resources to acquire attractive companies and properties. Even if future
acquisitions are completed, the following are some of the risks associated with
acquisitions:
o
the acquired businesses or properties may not produce revenues,
earnings or cash flow at anticipated levels;
o
the Company may assume liabilities that were not disclosed or that
exceed the Company's estimates;
o
the Company may be unable to integrate acquired businesses successfully
and realize anticipated economic, operational and other benefits in a
timely manner, which could result in substantial costs and delays or
other operational, technical or financial problems;
o
acquisitions could disrupt the Company's ongoing business, distract
management, divert resources and make it difficult to maintain the
Company's current business standards, controls and procedures;
o
the Company may finance future acquisitions by issuing common stock for
some or all of the purchase price, which could dilute the ownership
interests of the Company's stockholders; and
o
the Company may incur additional debt related to future acquisitions.
The Company may be affected by the gas prices in the Rocky Mountain
region.
The Company faces strong competition in the oil and gas industry, and
many of its competitors have greater resources than the Company.
The Company operates in a highly competitive industry. The Company
competes with major oil companies, independent producers and institutional and
individual investors, which are actively seeking oil and gas properties
throughout the world, along with the equipment, labor and materials required to
operate properties. Many of the Company's competitors have financial and
technological resources vastly exceeding those available to Company Many oil
and gas properties are sold in a competitive
16
bidding process in which the Company may lack the technological information or
expertise available to other bidders. The Company can offer no assurance that it
will be successful in acquiring and developing profitable properties in the face
of this competition.
The Company's operations are subject to the business and financial risk
of oil and gas exploration.
The business of exploring for and, to a lesser extent, developing oil
and gas properties is an activity that involves a high degree of business and
financial risk. Property acquisition decisions generally are based on various
assumptions and subjective judgments that are speculative. It is impossible to
predict accurately the ultimate production potential, if any, of a particular
property or well. Moreover, the successful completion of an oil or gas well does
not ensure a profit on investment. A variety of factors, both geological and
market-related, can cause a well to become uneconomic or marginally economic.
The Company's business is subject to operating hazards that could
result in substantial losses.
The oil and natural gas business involves operating hazards such as well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental hazards and
risks, any of which could cause the Company a substantial loss. In addition, the
Company may be held liable for environmental damage caused by previous owners of
property it owns or leases. As a result, the Company may face substantial
liabilities to third parties or governmental entities, which could reduce or
eliminate funds available for exploration, development or acquisitions or cause
the Company to incur losses. An event that is not fully covered by
insurance--for example, losses resulting from pollution and environmental risks,
which are not fully insurable--could have a material adverse effect on the
Company's financial condition and results of operations.
The Company may face unanticipated water disposal costs.
17
Where groundwater produced from coal bed methane projects
fails to meet the quality requirements of applicable regulatory agencies or
methane wells produce water in excess of the applicable volumetric permit
limit, the Company may have to drill additional disposal wells to re-inject the
produced water back into deep underground rock formations. The costs to dispose
of this produced water may increase if any of the following occur:
o
The Company cannot obtain future permits from applicable regulatory
agencies;
o
water of lesser quality is produced;
o
Methane wells produce excess water; or
o
new laws or regulations require water to be disposed of in a different
manner.
The Company has limited protection for its technology and depends on
technology owned by others.
The Company intends to use operating practices that management believes are
of value in developing coal bed methane resources. In most cases, patent or
other intellectual property protection is unavailable for this technology. The
Company's use of independent contractors in most aspects of its drilling and
some completion operations makes the protection of such technology more
difficult. Moreover, the Company relies on the technological expertise of the
independent contractors that it retains for its oil and gas operations. The
Company has no long-term agreements with these contractors, and management
cannot be sure that the Company will continue to have access to this expertise.
The Company must comply with complex federal, state, and local laws and
regulations.
Federal, state, and local authorities extensively regulate the oil and gas
industry. Noncompliance with these statutes and regulations may lead to
substantial penalties, and the overall regulatory burden on the industry
increases the cost of doing business and, in turn, decreases profitability.
Regulations affect various aspects of oil and gas drilling and production
activities, including the pricing and marketing of oil and gas production, the
drilling of wells (through permit and bonding requirements), the positioning of
wells, the unitization or pooling of oil and gas properties, environmental
matters, safety standards, the sharing of markets, production limitations,
plugging and abandonment and restoration. These laws and regulations are under
constant review for amendment or expansion.
18
The Company may incur substantial costs to comply with stringent
environmental regulations.
The Company's operations are subject to stringent and constantly changing
environmental laws and regulations adopted by federal, state, and local
governmental authorities. The Company could be forced to expend significant
resources to comply with new laws or regulations, or changes to current
requirements. Governmental environmental agencies have relatively little
experience with the regulation of coal bed methane operations, which are
technologically different from conventional oil and gas operations. This
inexperience has created uncertainty regarding how these agencies will interpret
air, water and waste laws and regulations and other requirements to coal bed
methane drilling, fracture stimulation methods, production and water disposal
operations. The Company will continue to be subject to uncertainty associated
with new regulatory interpretations and inconsistent interpretations between
governmental environmental agencies. The Company could face significant
liabilities to the government and third parties for discharges of oil, natural
gas or other pollutants into the air, soil or water, and the Company could have
to spend substantial amounts on investigations, litigation and remediation.
Moreover, failure by the Company to comply with these laws and regulations may
result in the assessment of administrative, civil and criminal penalties, the
imposition of investigatory and remedial obligations and the issuance of
injunctions that restrict or prohibit the performance of operations. See
"--Government Regulation of the Oil and Gas Industry--Environmental Matters."
The Company's business will depend on transportation facilities owned by
others.
The marketability of the Company's gas production depends in part on the
availability, proximity and capacity of pipeline systems owned by third parties,
and changes in the Company's contracts with these third parties could materially
affect the Company's operations. The Company, through its subsidiaries, has
entered into a series of firm transportation service agreements with pipeline
companies providing for the transportation of the Company's natural gas
production from the Raton Basin to the Mid-Continent markets. See "--Customers
and Markets--Gas Marketing and Transportation."
In addition, federal, state, and local regulation of gas and oil production
and transportation, tax and energy policies, changes in supply and demand,
pipeline pressures, and general economic conditions could adversely affect the
Company's ability to transport its natural gas.
Market conditions could cause the Company to incur losses on its
transportation contracts.
19
The Company has gas transportation contracts that require it to
transport minimum volumes of natural gas. If the Company ships smaller volumes,
it may be liable for the shortfall. Unforeseen events, including production
problems or substantial decreases in the price for natural gas, could cause the
Company to ship less than the required volumes, resulting in losses on these
contracts.
The Company depends on key personnel and does not have employment
agreements with its executive officers.
The Company's success depends on the continued services of its executive
officers and a limited number of other senior management and technical
personnel, and the Company does not have employment agreements with these
employees. Loss of the services of any of these people could result in financial
losses and interruptions in operations.
The Company does not pay dividends.
The Company has never declared nor paid any cash dividends on its common
stock and management has no intention to do so in the near future.
The Company's stock price is likely to be extremely
volatile in the future
The market price for the Company stock has no history and there is no
volume, accordingly, investors should expect the stock price to be erratic and
volatile and the stock should be considered illiquid.
Raton Basin Area of Interest
The Raton Basin covers an area that is approximately 80 miles long, north
to south, and about 50 miles wide, east to west, encompassing southeastern
Colorado and northeastern New Mexico. The Raton Basin contains two coal-bearing
formations, the Vermejo formation coals located at depths of between 450 and
4,000 feet and the shallower Raton formation coals, located at the surface to
approximately 3,000 feet in depth. Production from the Vermejo coals represents
approximately 79% of the total production from the Raton Basin and approximately
78% of the total proved reserves in the Raton Basin. To date, the majority of
methane production has been from the Vermejo formation coals in Colorado;
however, the Company believes it can successfully develop Raton formation
coal seams and interbedded sandstones as well.
Development History
Exploration for coal bed methane in the Raton Basin began in the late
1970s and continued through the late 1980s, with several companies drilling and
testing more than 100 wells during this period. The absence of a pipeline to
transport gas from the Raton Basin prevented full-scale development until
January 1995, when Colorado Interstate Gas Company completed the construction of
the Picketwire Lateral.
The Company has working interests of between 80% and 100% in the known coal
bed of the Raton Basin Areas comprising approximately 6,000 gross acres.
20
Raton Basin Geology
The Company seeks to explore for and produce coal bed methane from the high
quality bituminous coal resource of the Raton Basin. The basin is a large
asymmetric sedimentary trough that developed along the western margin of an
ancient Rocky Mountain seaway during the Cretaceous and Tertiary period between
65 to 45 million years ago. Today, the geologic history of what was once a lush
tropical coastline and alluvial plain cut by meandering rivers, which
subsequently underwent deep burial, tectonism, igneous intrusion, and uplift, is
recorded in the rocks of the region; the continued exploration of the basin by
geologists is increasing the understanding of the coal bed methane resource base
and identifying new hydrocarbon systems and additional unconventional reservoir
types.
The Company's prospect acreage sits in the southernly half of the basin and
contains some of the thickest documented net coal packages in the region. The
coal-bearing strata are located primarily in two major groups, the Vermejo and
Raton formations, and represent coal development in two slightly contrasting
environments. The Vermejo coals represent peat accumulation on an expansive
flat-lying flood-plain which was partially protected from erosion by sandy
coastal barriers of the underlying Trinidad Sandstone, while the Raton coals
represent peat development on a broad, open, humid alluvial fan. Collectively,
both formations reflect the development of substantial peat swamps and thick
boggy mires, which covered most of the region during Cretaceous and Tertiary
times. Subsequent burial under high pressures and temperatures has caused the
original peat accumulation to convert into coal, which has high rank and
consequentially high gas storage capacity. During burial, small fractured
surfaces (cleats) developed throughout the coal, which, coupled with the
tectonic forces acting on the region during the building of the Rocky Mountains,
has provided significant permeability within the coals, allowing for the
extraction of coal bed methane gas and associated water.
The Company hopes to produce methane from wells that are generally
completed in the laterally continuous Vermejo coal. Individual Vermejo coal
seams can be readily traced over several miles, commonly from well to well.
Total net Vermejo coal thickness can locally approach up to 100 feet in many
individual seams, which may vary in thickness from one to 10 feet.
The shallower Raton formation coals are generally less continuous from well
to well, but increasingly represent a very significant resource throughout the
basin. Total net Raton coal thickness locally approaches 90 feet in many
individual seams, which may vary in thickness from one to 10 feet. Occasionally
interbedded with the Raton coals are large sandstone channel complexes, which
are increasingly identified as additional potential tight-gas and unconventional
sand reservoirs.
Coal Bed Methane Versus Traditional Natural Gas
Methane is the primary commercial component of the natural gas stream
produced from traditional gas wells. Methane also exists in its natural state in
coal seams. Natural gas produced from traditional wells also contains, in
varying amounts, other hydrocarbons. However, the natural gas produced from coal
beds generally contains only methane and, after simple dehydration, becomes
pipeline-quality gas.
21
Coal bed methane production is similar to traditional natural gas
production in terms of the physical producing facilities and the product
produced. However, the subsurface mechanisms that allow the gas to move to the
wellbore and the producing characteristics of coal bed methane wells differ
greatly from traditional natural gas production. Unlike conventional gas wells,
which require a porous and permeable reservoir, hydrocarbon migration and a
natural structural and/or stratigraphic trap, coal bed methane gas is trapped in
the molecular structure of the coal itself until released by pressure changes
resulting from the removal of in situ water or natural gas in the micropore
system.
Methane is created as part of the coalification process, though coals
vary in their methane content per ton. In addition to residing in open spaces in
the coal structure, methane is absorbed onto the inner coal surfaces. When the
coal is hydraulically fracture stimulated and exposed to lower pressures through
the de-watering process, the gas is released from (desorbs from) the coal.
Whether a coal bed will produce commercial quantities of methane gas depends on
the coal quality, its original content of gas per ton of coal, the thickness of
the coal beds, the reservoir pressure, the rate at which gas is released from
the coal (diffusivity) and the existence of natural fractures and cleating
(permeability) through which the released gas can flow to the wellbore.
Frequently, coal beds are partly or completely saturated with water. As the
water is produced, internal pressures on the coal are decreased, allowing the
gas to desorb from the coal and flow to the wellbore. Unlike traditional gas
wells, new coal bed methane wells often produce water for several months and
then, as the water production decreases, natural gas production increases as the
coal seams de-water.
In order to establish commercial gas production rates, a permanent
conduit between the individual coal seams and the wellbore must be created. This
is accomplished by hydraulically creating, and propping open with special
quality sand, artificial fractures within the coal seams (known as "fracing" in
the industry) so the pathway for water and gas migration to the wellbore is
enhanced. These fractures are filled (propped) with uniform sized sand and
become the enhanced conduits for water and methane to reach the well. The rate
at which the gas is released from the coal and the ability of gas to move
through the coal to the wellbore are the key determinants of the rate at which a
well will produce.
22
Deep Fractured Shales, Raton Conglomerate and Sandstone Reservoirs
There are possible additional unconventional reservoir systems throughout
the Raton Basin. The Company intends to study gas-charged sandstones and
conglomerates interbedded within the currently producing Vermejo and Raton
formation coals and deeper gas-bearing shales, which underlie the entire region.
The conglomerate and sandstones sought, reflect stacked large scale
meandering river channel complexes and regional sandy braided alluvial fans that
at one time crosscut the Cretaceous-Tertiary peat swamps. During burial, excess
gas generated during the coalification process locally became trapped within the
pore spaces of these sandstones and now form "Tight-Gas Sand" reservoirs. The
increasing recognition of the orientation in the subsurface of such ancient
drainage system is allowing the strategic sighting of wells in specific sand
prone areas, which may ultimately increase the region's total resource base.
The Raton Basin shales, termed the Niobrara and Pierre Shale formations,
are approximately 1,000 to 3,000-feet thick and underlie the currently producing
intervals. The shales collectively reflect deposits of blanket-like organic rich
mudstones, which accumulated in quiet water condition on the sea floor. Deeper
exploratory test wells (2,000 to 6,000 feet) may identify areas of enhanced
fracture permeability and could open a significant "Shale Gas" resource.
Coal Bed Methane Technology
Thin multi-layer coal bed methane and unconventional tight-gas
reservoirs create a multitude of challenges for drilling, reservoir and
production engineers, including the challenge of minimizing formation damage and
then isolating and completing individual zones in order to maximize recovery of
the resource in place.
Damage to the Raton Basin coals from conventional drilling mud systems
invading the cleat fracture surfaces and reducing their permeability has been
mitigated by utilizing specialized air-drilling techniques using percussion
air-hammers.
All coals in the Raton Basin require hydraulic fracture stimulation to
attain economic production rates. New techniques uses high quality nitrogen
foamed fluids as the fracturing media and combined with coiled tubing fracturing
units to selectively place proppant in individual seams. The Company believes
that this fracturing technique will assist developing some of the region's
resources.
23
Water Production and Disposal
Based on industry practice, management believes that the groundwater
produced from the Raton Basin coal seams will not exceed permit levels and will
be suitable for discharge into arroyos, surface water, well-site pits or
evaporation ponds pursuant to permits obtained from the State laws. Recent gas
analyses confirm that the gas stream is 99% pure methane and lacks other
hydrocarbon sources of contamination. In some cases the water is of such quality
that it can be discharged to arroyos and surface water under general water
discharge permits. These permits may give the Company the flexibility to add
water discharge points on an as-needed basis. The Company contract with an
independent water sampling company that collects the water samples and monitors
all the Company's water management program. These monitoring costs are directly
related to the number of well-site pits, evaporation ponds and discharge points.
Because water originates in a natural groundwater system, there is some
uncertainty whether water currently being discharged to streams and arroyos will
continue to meet permit standards for total iron and suspended solids. Water not
meeting these discharge standards can be disposed of in well-site pits and
evaporation ponds. When water of lesser quality is discovered or Company wells
produce water in excess of the applicable permit limits, the Company may have to
drill additional disposal wells to re-inject the produced water into deeper
sandstone horizons. Such drilling and disposal would require the Company to
obtain permits, similar to those obtained in the past.
Raton Basin Production Characteristics
Because of the importance of removing water from the coal seams to enhance
gas production, the Company expects that production from meagre wells may
increase because of the beneficial ambient effect of pressure reduction in
adjacent, more productive wells. Each well creates its own "cone of depression"
around the wellbore. The Company believes that Raton Basin wells on adjacent
160-acre sites will create overlapping cones of depression, enhancing gas
production in each well within this pattern. In some cases this pattern of
interference can be enhanced by drilling a fifth and sixth well in the 640-acre
section.
Raton Basin gas contains insignificant amounts of contaminants, such as
hydrogen sulfide, carbon dioxide or nitrogen, that are sometimes present in
conventional natural gas production. Therefore, the properties of Raton Basin
gas, such as heat content per unit volume (British Thermal units, or "Btu"), are
close to the average properties of pipeline gas from conventional gas wells.
The Company has no proven oil or gas or coalbed methane reserves, nor any
production. The Company intends to explore its Wyoming Acreage for conventional
Oil & Gas.
24
2006 2005 2004
---- ---- ----
Natural Oil Natural Oil Natural Oil
Gas (Mbbl) Gas (Mbbl) Gas (Mbbl)
(MMcf) (MMcf) (MMcf)
Raton Basin 0 0 0 0 0 0
Wyoming 0 0 0 0 0 0
Wyoming 0 0 0 0 0 0
New Mexico 0 0 0 0 0 0
Total 0 0 0 0 0 0
Productive Wells
The following table sets forth the number of gross and net producing
wells the Company had as of April 28, 2006: None
Acreage
At April 28, 2006, the Company held undeveloped acreage as set forth below:
Developed Acres Undeveloped Acres Total Acres
Location
Gross Net Gross Net Gross Net
Raton 0 0 152,235 136,788 152,2350 136,788
Basin
Wyoming 0 0 2,560 2,137 2,560 2,137
Wyoming 0 0 640 512 640 512
Total 0 0 157,200 141,249 157,200 141,249
25
Drilling Activities
The Company's drilling activities for the periods indicated are set
forth below:
Year Ended April 30, 2006
2006 2005
Gross Net Gross Net
Domestic
Exploratory
Wells
Productive
Water 0 0 0 0
Disposal
Dry 0 0 0 0
Total 0 0 0 0
Development
Wells
Productive 0 0 0 0
Water 0 0 0 0
Dry 0 0 0 0
Total 0 0 0 0
Office and Operations Facilities
The Company leases its corporate offices in Wheat Ridge, Colorado. The
lease covers approximately 400 square feet and is month to month.
DESCRIPTION OF PROPERTIES/ASSETS/OIL AND GAS PROSPECTS
(a) Real Estate. None.
(b) Title to properties. None.
(c) Oil and Gas Leases
and Interests See discussion of Interests
contained at pages 20-23 hereof.
(d) Patents. None.
PRINCIPAL SHAREHOLDERS
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AS OF APRIL 24,
2006.
There are currently 9,518,333 common Shares outstanding after the acquisitions
of and Sun River Energy, Inc.
The following sets forth information with respect to the Company's Common Stock
beneficially owned by each Officer and Director, and by all Directors and
Officers as a group as of May 2, 2006,
Title of Class Name and Address Amount and Nature Percent of
Of Beneficial Owner* of Beneficial Ownership Class
Common Stock Wesley F. Whiting 25,000 less than 1%
Common Stock Redginald T. Green 25,000 less than 1%
All Directors and Executive
Officers as a Group (2 persons) 50,000 less than 1%
- -----------------------------
* The beneficial owner's address is the same as the Company's principal office.
26
The following sets forth information with respect to the Company's Common Stock
beneficially owned by holders of 5% or more of the currently issued and
outstanding stock of the Company as of April 28, 2006.
Robert A. Doak (through his assigns
New Mexico Energy, LLC of which he is manager) 7,333,333 77%
DIRECTORS AND EXECUTIVE OFFICERS
CURRENT OFFICERS (as of May 2, 2006)
Name Age Position
- ---- --- --------
Wesley F. Whiting 74 President
Redginald T. Green 52 Secretary
- ----------------
WESLEY F. WHITING, Director, age 74. Mr. Whiting was President, director, and
Secretary of Berge Exploration, Inc. (1978-88) and President, Vice President,
and director of NELX, Inc. (1994-1998), and was Vice President and director of
Intermountain Methane Corporation (1988-91), and President of Westwind
Production, Inc. (1997-1998). He was a director of Kimbell deCar Corporation
from 1998, until 2000 and he has been President and a director of Dynadapt
System, Inc. since 1998. He was a Director of Colorado Gold & Silver, Inc. from
1999 to 2000. He was President and director of Business Exchange Holding Corp.
from 2000 to 2002 and Acquisition Lending, Inc. (2000 to 2002). He was director
and Vice President of Utilitec, Inc, 1999 to 2002, and has been Vice President
and director of Agro Science, Inc. since 2001. He was President and director of
Premium Enterprises, Inc. from October 2002 to December 31, 2002. He was
appointed Director and Secretary of BSA SatelLINK, Inc. in 2002. He was
President and Director of Fayber Group, Inc. (2003-2005). He has also been
Director of Life USA, Inc. since 2003. He is a President and Director in
Evergreen Associate, Inc. and Resource Sciences, Inc. since 2003. He was a
Director of Mind2Market, Inc. in 2004-2005 and was a Director of Baymark
Technologies, Inc. in 2005, resigning in 2006.
REDGINALD T. GREEN, age 52. Mr. Green has been Secretary and Director of
Dynadapt System, Inc. since 1998. Mr. Green has been co-owner and operator of
Green's B&R Enterprises, a wholesale donut baker since 1983. He has been an
active investor in small capital and high tech adventures since 1987. Mr. Green
was a director of Colorado Gold & Silver, Inc. in 2000. He was a director for
Houston Operating Company in late 2004 until December 2004. He was elected as a
director for Mountains West Exploration, Inc. in March 2005. He was a director
of Baymark Technologies, Inc. from September 2005 - December, 2006. He acted as
a director of Mind2Market, Inc. from 2004-2005.
The following individuals comprise the Directors as of May 2, 2006.
Board of Directors
Name Age Position
- ---- --- --------
Wesley F. Whiting (1) 74 Director
Redginald T. Green (1) 52 Director
- ----------------------------
(1) See biographical information listed above.
27
Director Nominees
The following persons are expected to accept Board positions or be elected to
the Board at the shareholders meeting later in 2006.:
Name Age
- --------- ---
Thomas Anderson 40
Stephen W. Weathers 44
David Surgnier 57
- -----------------
Biographical information for the Director Nominees is as follows:
THOMAS ANDERSON, age 40, presently works as a Senior Environmental Scientist for
the Energy and Environmental Engineering Division of Apogen Technologies in Los
Alamos, New Mexico. He earned his B.S. in Geology from Denison University and
his M.S. in Environmental Science and Engineering from Colorado School of Mines.
Mr. Anderson has worked for past 16 years in the environmental consulting field,
providing environmental compliance, characterization and remediation services to
Department of Energy, Department of Defense, and industrial clients. He formerly
worked as a Senior Environmental Scientist at Concurrent Technologies Corp. from
November 2000 to December 2004. From March 2000 to November 2000 he was employed
as a hydrologist at Stone & Webster Engineering, Inc. From July 1998 to March
2000 he was employed by advanced Integrated Management Services as an
Environmental Scientist/Engineer. From 1997 to 1998 he was a graduate research
assistant at Colorado School of Mines in the Environmental Science and
Engineering Program.
STEPHEN W. WEATHERS, age 44, earned his B. S. in Geology from Boise State
University. He has worked as an environmental geologist both in the mining
industry and oil and gas industry. His duties included permitting, environmental
compliance, environmental remediation/reclamation and natural gas asset
acquisitions both in the United States and Canada. Mr. Weathers worked for
Maxxim Environmental/Terracon from 1997 through 1999 and presently works in the
environmental remediation division for a Duke Energy Field Services which is a
natural gas processing company (1999-2002). Mr. Weathers also serves as a
director of Sun River Mining, Inc. which is seeking a business acquisition.
DAVID SURGNIER, age 57, Director Nominee, earned his B.S. in Mathematics in 1971
from the University of Oklahoma, his B.S. in Petroleum Engineering in 1972 from
the University of Oklahoma, and his M.S. in Petroleum Engineering in 1984 from
the University of Texas.
Mr. Surgnier currently serves as President/Engineer for Delta Gas Corporation
and Delta Environmental since 1992. From 1986 to 1992 he was the Rocky Mountain
Regional Manager for Completion Technology International of Denver, Colorado.
Mr. Surgnier was the Manager of Special Projects for Texas Iron Works of
Houston, Texas from 1980-1986. Mr. Surgnier was the Drilling and Production
Engineer from 1972-1980 for Atlantic Richfield Oil Company located in Houston,
Texas and ARCO Alaska.
28
Mr. Surgnier has 33 years experience as a Petroleum Engineer, Project and
Regional Manager, Technical writer and presenter. Developer, Inventor and
co-Inventor of Patented and Proprietary equipment and products, for the
Petroleum and Environmental Industry. He has operated and managed projects
onshore and offshore in North & South America, North Slope of Alaska, Cook Inlet
of Alaska and the Middle East.
He has also drilled and completed domestic water supply wells for individuals,
the Chickasaw, Choctaw and Seminole Nations, and U.S. Public Health Service.
Oilfield water supply wells for Cities Service Co., Framers Energy Corporation,
Botcher Gas Company, Cameron Oil Company and Phillips Petroleum Corporation.
Municipal Water Supply Wells for the Cities of Stewart, McAlister, Stonewall Ada
and Tribbey, Oklahoma.
Environmental Consultant to Environmental Resource Management, Biotreatment,
Inc., Aarow Environmental, Inc., Argonne National Laboratory and the University
of Chicago.
He has numerous Patents & Inventions and has written many professional Articles
involving petroleum engineering.
The term of office for each director is one (1) year, or until his/her successor
is elected at the Company's annual meeting and qualified. The term of office for
each officer of the Company is at the pleasure of the board of directors.
The board of directors has no nominating, auditing committee or a compensation
committee. Therefore, the selection of person or election to the board of
directors was neither independently made nor negotiated at arm's length.
COMPENSATION
Executive and Directors Compensation
Summary of Scheduled Executive Compensation
Annual Compensation
- ------------------------------------- --------- ------------ ------------ ------------------- ------------- --------------
Name & Principal Position Fiscal Salary ($) Bonus ($) Other Annual Restricted Securities
Year Compensation ($) Stock Underlying
2006 Award(s) ($) Options/
SARS (#)
- ------------------------------------- --------- ------------ ------------ ------------------- ------------- --------------
- ------------------------------------- --------- ------------ ------------ ------------------- ------------- --------------
Wesley F. Whiting, President $0 $0 $0 $0 0
- ------------------------------------- --------- ------------ ------------ ------------------- ------------- --------------
Redginald T. Green, Secretary $0 $0 $0 $0 0
- ------------------------------------- --------- ------------ ------------ ------------------- ------------- --------------
No compensation has been paid to any officer or director in the past three
years.
EMPLOYEES STOCK COMPENSATION PLAN:
The Company has no a stock compensation plan for employees which provide
schedules of earnout and vesting based upon longevity of service.
29
(b) Compensation of Certain Significant Employees. None.
(c) Family Relationships. None.
Conflicts of Interest
All of the Company's Officers and Directors have been in the past and may
continue to be active in the natural resource business with other companies and
on their own behalf. All Officers and Directors have retained the right to
conduct their own independent business interests. These activities could give
rise to potential conflicts with the interests of the Company. Pursuant to a
resolution of the Board of Directors of the Company, the Officers have agreed
that if a business opportunity in the natural resources industry comes to the
attention of its Officers, such opportunity will be made available to the
Company and the Company shall have a right of first refusal with regard to such
opportunity. Another resolution of the Board of Directors sets forth that if a
business opportunity comes to the attention of a Director and such opportunity
is located within an area of interest and defined by resolution of the Board of
Directors or if an opportunity is presented to a Director in his capacity as
such, it must be disclosed to the Company and made available to it. As of the
date of this Memorandum, the only areas of interest defined by the Company's
Board of Directors relate to the immediate vicinity surrounding the Company's
existing prospects. Any future designated areas of interest will be determined
by the Company's Board of Directors after appropriate discussion and
deliberation. If an Officer or Director owes a fiduciary duty to another entity
similar to the duty owed to the Company, it is possible that the conflict may be
impossible to resolve in a manner that is equitable to both entities.
A majority of disinterested Directors may reject a corporate opportunity for
various reasons, including geologic, geographic and economic considerations,
among others. If the Company rejects such opportunity, of it is rejects an area
of interest and later an opportunity is presented to a Director or Officer
within such area of interests, then any Director or Officer may avail himself or
themselves of such opportunity. In addition, if a prospect or other opportunity
is presented to the Company, and one or more of the Company's Officers or
Directors has an outside interest in the opportunity, the opportunity will be
reviewed at a meeting of the Board of Directors and the interested Director(s)
will not vote on issues relating to such opportunity.
30
To the best ability and in the best judgment of the Officers and Directors of
the Company, any conflicts of interests between the Company and the personal
interests of the Officers and Directors of the Company will be resolved in a
fair manner which will protect the interests of the Company.
The Company has no current plans to acquire any interest in any oil and gas
properties in which any of the Company's officers or directors have any direct
or indirect interest by security holdings, contracts, options or otherwise.
However, such acquisitions may occur in the future if the directors of the
Company determine that any such acquisition is in the best interest of the
Company. Further, the Company may, and it reserves the right to, enter into or
form joint ventures, partnerships, or other types of associations customary in
the oil and gas industry with one or more of its directors or their affiliates,
for the acquisition, exploration or development of a specific oil and gas
interest if the Board of Directors of the Company deems such arrangement to be
proper and in the best interests of the Company. If such arrangements are
entered into, they could constitute a benefit to the interested director or
affiliate and such benefits could be substantial. The Company has no current
plans to engage in drilling activities on properties near properties in which
any of the Company's officers or directors have any direct or indirect interest.
However, such drilling may occur in the future and the Company does not have a
policy which would prohibit such activity.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company issued 7,333,333 shares to New Mexico Energy LLC, (beneficially
Robert A. Doak, Jr.) and 1,700,000 shres to other shareholders of Sun River
Energy, Inc. in exchange for 100% of the issued and outstanding shares of Sun
River Energy, Inc. Mr. Doak is considered a related party in this transaction.
LEGAL PROCEEDINGS
The Company is not a party to any pending legal proceedings, and no such
proceedings are known to be contemplated.
No director, officer or affiliate of the Company, and no owner of record or
beneficial owner of more than 5.0% of the securities of the Company, or any
associate of any such director, officer or security holder is a party adverse to
the Company or has a material interest adverse to the Company in reference to
any litigation.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted by the Company to a vote of the Company's
shareholders through the solicitation of proxies or otherwise, during the fourth
quarter of the fiscal year covered by this report.
31
Item 2.02 Results of Operations and Financial Condition
The Company intends to commence a Private Placement of units @ $.50 per unit
consisting of 2 common shares and one warrant exerciseable @ $.75 per share, to
attempt to raise $750,000 in capital.
The Company has acquired 100% of Sun River Energy, Inc. which hold mineral
interests and leases upon which it intends to conduct exploration activities.
The Company plan of operations is as follows:
Milestones
April 2006- Initiation of Private Offering Memorandum
2nd Quarter 2006 - Acquisition of mineral prospects and commence
exploration
Register SB-2
3rd Quarter 2006 - Continuation of exploration operations
4th Quarter 2006 - Complete SB-2/achieve additional funding
Continuation of exploration
The Company Budget for operations in next year is as follows:
Maximum Offering
-------------------------------
Acquisitions $500,000
Exploration Expenses $3,000,000
Debt Payments $984,000
General and Administrative $250,000
Working Capital $1,000,000
-------------------------------
Total $5,734,000
The Company reserves the right to change any or all of the budget categories in
the execution of its business attempts without purchaser approval. None of the
line items is to be considered fixed or unchangeable in the budget.
32
The Company will need substantial additional capital to support its budget. The
Company has no revenues. The Company has no committed source for any funds as of
date here. No representation is made that any funds will be available when
needed. In the event funds cannot be raised when needed, the Company may not be
able to carry out its business plan, may never achieve sales or royalty income,
and could fail in business as a result of these uncertainties.
Decisions regarding future participation in exploration wells or geophysical
studies or other activities will be made on a case-by-case basis. The Company
may, in any particular case, decide to participate or decline participation. If
participating, the Company will pay its proportionate share of costs to maintain
its proportionate interest through Company cash flow or debt or equity
financing. If participation is declined, the Company may elect to farm out,
non-consent, sell or otherwise negotiate a method of cost sharing in order to
maintain some continuing interest in the prospect.
Limited Financing.
- -----------------
Assuming that all Units hereby offered are sold, of which there is no assurance,
the monies raised by the offering may not be sufficient for the continued
proposed operations of the Company. There is no assurance that additional monies
or financing will be available in the future or, if available, will be at terms
favorable to the Company. In the event that at least the minimum amount of the
Units are sold to permit the Company to receive the funds from the escrow
account, but less than all of the Units offered hereby are sold, the Company
will have substantially less funds available to engage in its proposed business,
and will limit its business to lease acquisitions and joint venture syndication
for drilling. (See "Company Business Summary")
The Company may borrow money to finance its future operations, although it does
not currently contemplate doing so. Any such borrowing will increase the risk of
loss to the investor in the event the Company is unsuccessful in repaying such
loans.
The Company may issue additional Units or Shares to finance its future
operations, although it does not currently contemplate doing so. Any such
issuance will reduce the control of previous investors (see "Risk Factor -
Control") and may result in substantial additional dilution to investors
purchasing Units from this offering.
The Company may attempt to conserve its available funds by acquiring properties
through options or long-term purchase contracts. If the Company is financially
unable to exercise options or make contract payments when due, the Company could
be forced to forfeit all of its interest in such properties.
LIQUIDITY
The Company had minimal cash or other liquid assets at date hereof, and will be
reliant upon shareholder loans or private placements of equity to fund any kind
of operations. There are no secured sources of loans or private placements at
this time.
33
Short Term.
- ----------
On a short-term basis, the Company does not generate revenue sufficient to cover
operations. Based on prior experience, the Company believes it will continue to
have insufficient revenue to satisfy current and recurring liabilities as it
seeks to explore its prospects. For short term needs the Company will be
dependent on receipt, if any, of private placement proceeds, and any loans it
can arrange.
RESULTS OF OPERATIONS FOR THE QUARTER ENDED JANUARY 31, 2006 COMPARED TO SAME
QUARTER IN 2005.
The Company had no revenues during the quarter ended January 31, 2006 or 2005.
The Company incurred no expenses in the quarter in 2006 or in 2005. The net loss
for the quarter was none in 2006 and in 2005. The loss per share was none in the
quarter in 2006 and in 2005.
RESULTS OF OPERATION FOR THE NINE MONTH PERIOD ENDED JANUARY 31, 2006 COMPARED
TO SAME PERIOD ENDED JANUARY 31, 2005.
The Company had no revenues during the nine month period ended January 31, 2006
nor in the same period ended January 31, 2005. The Company had no expenses in
the nine month period ended January 31, 2006 or in the same period in 2005. The
net loss for the period ended January 31, 2006 was none and none in the same
period ending January 31, 2005. The net loss per share in the period was none in
2006 and 2005. The trend of operating losses will continue until a profitable
business operation can be achieved for which there is no assurance.
Long Term.
- ---------
The Company has no cash commitments to fund its long-term prospects and has no
plan in place to resolve this issue. Failure to obtain long-term capital could
result in failure of the Company.
CAPITAL RESOURCES
The only capital resources of the Company are its common stock.
As of the date of the Private Placement, the Company has no material commitments
for capital expenditures within the next year, however if operations are
commenced, substantial capital will be needed to pay for evaluation,
acquisition, stimulation and working capital.
34
Cash Flows:
- ----------
The Company has achieved no cash flows to date.
Need for Additional Financing.
The Company does not have capital sufficient to meet the Company's cash needs.
The Company will have to seek loans or equity placements to cover such cash
needs. Once exploration commences, the Company's needs for additional financing
is likely to increase substantially.
No commitments to provide additional funds have been made by management or other
stockholders. Accordingly, there can be no assurance that any additional funds
will be available to the Company to allow it to cover its expenses as they may
be incurred.
Irrespective of whether the Company's cash assets prove to be inadequate to meet
the Company's operational needs, the Company may compensate providers of
services by issuances of stock in lieu of cash.
Item 2.03 Creation of a Direct Financial Obligation or an Obligation Under an
Off-Balance Sheet Arrangement of a Registrant
As part of the Plan and Agreement of Reorganization, the Company
consolidated a total of $1,164,000 in debt carried on the books of its
acquired subsidiary Sun River Energy, Inc. onto its financial statements. All
of the debt is short term, and is unsecured.
The debt schedule is as follows:
Principal Interest Rate Payments due
- --------- ------------- ------------
$ 64,000 6% In full September 30, 2006
150,000 6% 2 equal installments 9/30/06 - 1/15/07
600,000 6% 2 equal installments 5/30/06 - 1/15/07
150,000 None On demand
200,000 None On demand
Item 2.04 Triggering Events That Accelerate or Increase a Direct Financial
Obligation or an Obligation Under an Off-Balance Sheet Arrangement
None
Item 2.05 Costs Associated with Exit or Disposal Activities
None
Item 2.06 Material Impairments
None
35
Section 3 - Securities Trading Markets
Item 3.01 Notice of Delisting or Failure to Satisfy a Continued Listing Rule or
Standard; Transfer of Listing
None
Item 3.02 Unregistered Sales of Equity Securities
The Company issued a total of 8,633,333 restricted common shares to the
shareholders of Sun River Energy, Inc. in exchange for 100% of the issued
and outstanding shares of Sun River Energy, Inc. pursuant to the exemptions from
registration under Sections 4(2) and 4(6) of the Securities Act of 1933,
pursuant to the Plan and Agreement of Reorganization with Sun River Energy, Inc.
In addition the Company issued 400,000 shares of restricted common stock to one
person in partial consideration for the acquisition of 4 sections of oil and gas
prospect leases in Johnson and Natrona Counties, Wyoming. The transaction was
exempt from Registration under Sections 4(2) and 4(6) of the Securities Act of
1933.
Item 3.03 Material Modification to Rights of Security Holders
None
Section 4 - Matters Related to Accountants and Financial Statements
Item 4.01 Changes in Registrant's Certifying Accountant
None
Item 4.02 Non-Reliance on Previously Issued Financial Statements or a Related
Audit Report or Completed Interim Review
None.
Section 5 - Corporate Governance and Management
Item 5.01 Changes in Control of Registrant
The Company experienced a change of control in its acquisition of Sun
River Energy, Inc. Sun River's principal shareholder, Robert A. Doak, Jr.
through his holding company, New Mexico Energy, LLC received 7,333,333 common
shares constituting 90% of the total outstanding shares of the Company
immediately after the share exchange transaction with the shareholders of Sun
River Energy, Inc.
Item 5.02 Departure of Directors or Principal Officers; Election of Directors;
Appointment of Principal Officers
None
Item 5.03 Amendments to Articles of Incorporation or Bylaws; Change in Fiscal
Year
None
36
Item 5.04 Temporary Suspension of Trading Under Registrant's Employee Benefit
Plans
None
Item 5.05 Amendments to the Registrant's Code of Ethics, or Waiver of a Provi-
sion of the Code of Ethics.
Item 5.06 Change in Shell
(see also 2.01 Company Status)
The Company entered into a Plan and Agreement of Reorganization on April 21,
2006, with shareholders of Sun River Energy, Inc. and Sun River Energy, Inc.
Under the terms of the Agreement, shareholders of Sun River Energy Inc. received
a total of 8,633,333 shares of common stock of the Company in exchange for
8,633,333 shares of Sun River, constituting 100% of the issued and outstanding
common stock of Sun River. The Agreement required delivery of audited F/S of the
Sun River at time of closing. The closing occurred on April 28, 2006, and the
company issued 8,633,333 shares of restricted common stock. Certain short term
debts of Sun River totalling $1,164,000 were accepted as part of the acquisition
and will be consolidated into the financial statements.
Section 6 - [Reserved]
Section 7 - Regulation FD
Item 7.01 Regulation FD Disclosure
None
Section 8 - Other Events
Item 8.01 Other Events
The Company has adopted a new Business Plan in the Energy sector, through
its acquisition of Sun River Energy, Inc. (See Item 2.01 and Item 2.03)
Section 9 - Financial Statements and Exhibits
Item 9.01 Financial Statements and Exhibits
Financial Statements
1) Audited Financial Statements for Sun River Energy, Inc.
2) Consolidated Pro Forma Balance Sheet (Post Transaction with Sun River Energy)
Exhibits
3.3 Articles of Incorporation - Sun River Energy, Inc.
3.4 Bylaws of Sun River Energy, Inc.
10.3 Promissory Note to Robert A. Doak
10.4 Promissory Note to Nova Leasing, LLC
10.5 Promissory Note to Sharon Fowler
10.6 Assignment of Lease - (Nova - Wyoming)
10.7 Assignment of Lease - (Fowler - Wyoming)
10.8 Assignment of Lease - (Colfax County N.M)
10.9 Deed to Mineral Interests - Colfax County N.M.
10.10 Asset Purchase Agreement - Sun River Energy, Inc. and Robert A. Doak, Jr.
10.11 Plan and Merger of Reorganization (Previously filed)
37
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Date: May 3, 2006 DYNADAPT SYSTEM, INC.
By: /s/ Wesley F. Whiting
---------------------------
Wesley F. Whiting, President
38
JASPERS + HALL, PC
CERTIFIED PUBLIC ACCOUNTANTS
- --------------------------------------------------------------------------------
9175 E. Kenyon Avenue, Suite 100
Denver, CO 80237
303-796-0099
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
Sun River Energy, Inc.
We have audited the accompanying consolidated balance sheet of Sun River Energy,
Inc. (a development stage company) as of December 31, 2005 and 2004 and the
related consolidated statement of operations, stockholders' equity, and cash
flows for the years then ended and for the period from inception (October 22,
2002) through December 31, 2005. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with 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. 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 financial position of Health Partnership
Inc. as of December 31, 2005 and 2004, and the results of their operations and
their cash flows for the years then ended and for the period from inception
through December 31, 2005, in conformity with generally accepted accounting
principles of the United States.
March 27, 2006
/s/ Jaspers + Hall, PC
SUN RIVER ENERGY, INC.
(A Development Stage Company)
Balance Sheets
December 31,
2005 2004
---- ----
ASSETS $ - $ -
----- -----
Total Assets $ - $ -
===== =====
LIABILITIES & STOCKHOLDERS' EQUITY:
LIABILITIES $ - $ -
----- -----
STOCKHOLDER'S EQUITY:
Common stock, $.001 par value, 100,000,000 shares authorized, $ 1 $ 1
1,000 shares issued and outstanding as of December 31, 2005
and 2004.
Additional Paid-In Capital 49 49
Deficit accumulated during exploratory stage (50) (50)
----- -----
Total Stockholders' Equity - -
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $ - $ -
===== =====
The accompanying notes are an integral part of these financial statements.
SUN RIVER ENERGY, INC.
(A Development Stage Company)
Statements of Operations
October 22, 2002
(Inception) to
December 31,
2005 2004 2005
------------ ------------- ------------
REVENUES
$ - $ - $ -
------------ ------------- ------------
EXPENSES
Legal Fees
- - 50
------------ ------------- ------------
Net income (loss)
$ - $ - $ (50)
============ ============= ============
Per Share Information
Weighted average number of common shares outstanding
1,000 1,000
------------ -------------
Net Gain (Loss) per share common stock
- -
------------ -------------
The accompanying notes are an integral part of these financial statements.
SUN RIVER ENERGY, INC
(A Development Stage Company)
Statements of Cash Flows
October 22, 2002
(Inception) to
December 31, December 31,
2005 2004 2005
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss) $ - $ - $ (50)
Net cash used by operating activities - - (50)
CASH FLOWS FROM INVESTING ACTIVITIES:
- - -
----- ----- -----
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock - - 50
----- ----- -----
Net increase in cash and cash equivalents - - -
Cash and cash equivalents at beginning of period - - -
Cash and cash equivalents at end of period $ - $ - $ -
===== ===== =====
Supplemental disclosure of cash flow information:
Cash paid for interest $ - $ - $ -
===== ===== =====
Cash paid for taxes $ - $ - $ -
===== ===== =====
The accompanying notes are an integral part of these financial statements.
SUN RIVER ENERGY, INC.
(A Development Stage Company)
Statements of Stockholders' Equity (Deficit)
As of December 31, 2005
Deficit
Accumulated
Additional During the
COMMON STOCK Paid-In Exploratory
Shares Amount Capital Stage Total
------ ------ ------- ----- -----
Balance - October 22, 2002 $ - $ - $ - $ -
Common stock issued $.0001 per share on December 27,2002 1,000 1 49 50
Net Loss for Period - - (50)
----- ----- ----- ----- -----
Balance - December 31, 2002 1,000 1 49 (50)
----- ----- ----- ----- -----
Net Loss for Year - - - -
----- ----- ----- ----- -----
Balance - December 31, 2003 1,000 1 49 (50) -
----- ----- ----- ----- -----
Net Loss for Year - - - -
----- ----- ----- ----- -----
Balance - December 31, 2004 1,000 1 49 (50) -
----- ----- ----- ----- -----
Net Loss for Year - - - -
----- ----- ----- ----- -----
Balance - December 31, 2005 1,000 $ 1 $ 49 $ (50) $ -
===== ===== ===== ===== =====
The accompanying notes are an integral part of these financial statements.
DYNADAPT SYSTEM, INC.
(A Development Stage Company)
Unaudited Pro-Forma Financial Statements
For the Twelve Months Ended April 28, 2006
Consolidated with Sun River Energy, Inc.
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
APRIL 30, 2006
Pro Forma Pro Forma
DYNADAPT SUN RIVER Adjustments Combined
ASSETS
Cash and cash equivalents $ - $ 999 $ - $ 999
Leases (Note 3) - 284,000 - 284,000
Fee Minerals (Note 4) - 966,667 - 966,667
------------------------------------------------------------------
Total Assets - 1,251,666 - 1,251,666
Less Goodwill in excess of basis - (866,667) - (866,667)
------------------------------------------------------------------
Net Assets - 384,000 - 384,000
LIABILITIES & STOCKHOLDERS' EQUITY
Accounts Payable 16,325 1,164,000 - 1,180,325
Notes Payable - Stockholder 4,550 - - 4,550
------------------------------------------------------------------
Total Liabilities 20,875 1,164,000 - 1,184,875
Capital stock 48 8,633 (1) 8,681
Paid in capital 23,506 375,367 1 398,873
Retained earnings (deficit) (44,429) (50) - (44,479)
-------------------------------------------------------------------
Total Stockholders' Equity (20,875) 383,950 - 363,075
Total liabilities & stockholders'
Equity (deficit) - (780,050) - (821,800)
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
(Year Ended April 30, 2006)
Pro Forma
DYNADAPT SUN RIVER Combined
-------- --------- -----------
ASSETS
Net Revenue - - -
---------------------------------------------------------------
Gross Profit - - -
---------------------------------------------------------------
Expenses
Consulting 0 150,000 150,000
Accounting/Legal Fees 0 200,050 200,050
Office Expense 0 - -
Bank Charges 0 - -
---------------------------------------------------------------
Operating Expense 0 350,050 350,050
---------------------------------------------------------------
Other Income/Expense
Interest expense 0 - -
Interest income 0 - -
---------------------------------------------------------------
Total Other Income/Expense 0 - -
---------------------------------------------------------------
Net Income/(loss) 0 (350,050) (350,050)
---------------------------------------------------------------
PerShare Data
Net Loss per Share $ (0.63)
Weighted average shares outstanding 556,500
DYNADAPT SYSTEM, INC.
(A Development Stage Company)
Note to Pro-Forma Financial Statements
April 28, 2006
(Unaudited)
Note 1 - Unaudited Pro-Forma Results:
The following unaudited pro-forma financial information presents the combined
results of operations of the Company and Sun river Energy, Inc. as if the
consolidation took place April 28, 2006.
Note 2 - Going Concern:
The Company's financial statements have been presented on the basis that it is a
going concern, which contemplates the realization of assets and the satisfaction
of liabilities in the normal course of business.
The Company is in the development stage and has not earned any revenue from
operations. The Company's ability to continue as a going concern is dependent
upon its ability to develop additional sources of capital or develop cash flow
and ultimately, achieve profitable operations. The accompanying financial
statements do not include any adjustments that might result from the outcome of
these uncertainties. Management is seeking new capital to capitalize the
Company.
Note 3 - Unrelated Party Transactions
Cost Acres/leases
$180,000 2,560 $150,000 note 300,000 shares of stock $15,000 value
+
$104,000 640 $64,000 note 400,000 shares of stock $20,000 value
Note 4 - Related Party Transaction Fee Minerals & Leases
(Predecessor Basis - $100,000)
Note Payable 600,000
7,333,333 shares of stock $366,667 value $733,333
Total consideration $966,667
Less goodwill (amount in excess of predecessor basis) $866,667