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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal Year Ended December 31, 2004
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number: 0-26321
GASCO ENERGY, INC.
(Exact name of registrant as specified in its charter)
NEVADA 98-0204105
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
14 Inverness Drive East, Building H, Suite 236, Englewood, CO 80112
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 483-0044
Securities registered under Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
COMMON STOCK, $0.0001 PAR VALUE AMERICAN STOCK EXCHANGE
Securities registered under Section 12(g) of the Exchange Act: None.
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of the registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes X No __
As of June 30, 2004, approximately 45,344,954 shares of Common Stock, par value
$0.0001 per share were outstanding, and the aggregate market value of the
outstanding shares of Common Stock of the Company held by non-affiliates was
approximately $88,422,660. As of March 15, 2005, approximately 70,517,209 Common
Stock, par value $0.0001 per share were outstanding.
Documents incorporated by reference:
Certain information required by Items 10, 11, 12, 13 and 14 of Part III is
incorporated by reference from portions of the registrant's definitive proxy
statement relating to its 2005 annual meeting of stockholders to be filed within
120 days after December 31, 2004.
Table of Contents
Part I
Item 1. Description of Business...............................................2
Business of Gasco................................................2
History..........................................................2
Acquisition, Exploration and Development Expenses................3
Principal Products or Services and Markets.......................3
Competitive Business Conditions, Competitive Position in the
Industry and Methods of Competition...........................3
Governmental Regulations and Environmental Laws..................4
Number of Total Employees and Number of Full-Time Employees......5
Risk Factors.....................................................6
Cautionary Statement Regarding Forward-Looking Statements.......17
Item 2. Description of Property..............................................18
Petroleum and Natural Gas Properties............................18
Company Reserve Estimates.......................................21
Volumes, Prices and Operating Expenses..........................22
Development, Exploration and Acquisition Capital Expenditures...22
Productive Gas Wells............................................23
Oil and Gas Acreage.............................................23
Drilling Activity...............................................25
Office Space....................................................25
Item 3. Legal Proceedings....................................................25
Item 4. Submission of Matters to a Vote of Security Holders..................25
Part II
Item 5. Market for Common Equity and Related Stockholder Matters.............26
Equity Compensation Plans.......................................26
Securities Transactions.........................................28
Item 6. Selected Financial Data..............................................29
Item 7. Management's Discussion and Analysis.................................29
Forward Looking Statements......................................29
Overview........................................................29
Liquidity and Capital Resources.................................31
Capital Budget..................................................33
Schedule of Contractual Obligations.............................34
Critical Accounting Policies and Estimates......................35
Results of Operations...........................................37
Recent Accounting Pronouncements................................39
Table of Contents (continued)
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..........41
Item 8. Financial Statements................................................42
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..............................................75
Item 9A. Controls and Procedures.............................................75
Item 9B. Other Information...................................................76
Part III
Item 10. Directors and Executive Officers of the Registrant..................77
Item 11. Executive Compensation..............................................77
Item 12. Security Ownership of Certain Beneficial Owners and Management......77
Item 13. Certain Relationships and Related Transactions......................77
Item 14. Principal Accountant Fees and Services..............................77
Item 15. Exhibits and Financial Statement Schedules..........................77
PART I
ITEM 1 - DESCRIPTION OF BUSINESS
Business of Gasco
Gasco Energy, Inc. ("Gasco" or "the Company") is a natural gas and petroleum
exploitation, development and production company engaged in locating and
developing hydrocarbon prospects, primarily in the Rocky Mountain region. "Our",
"we", and "us" as used in this annual report, also refer to Gasco Energy, Inc.
The Company's principal business strategy is to enhance stockholder value by
using technologies new to a specific area to generate and develop high-potential
exploitation prospects in this area. The Company's principal business is the
acquisition of leasehold interests in petroleum and natural gas rights, either
directly or indirectly, and the exploitation and development of properties
subject to these leases. The Company is currently focusing its drilling efforts
in the Riverbend Project located in the Uinta Basin of northeastern Utah,
targeting the Wasatch, Mesaverde and Blackhawk formations.
History
Gasco (formerly known as San Joaquin Resources Inc. ("SJRI")) was incorporated
on April 21, 1997 under the laws of the State of Nevada, as "LEK International,
Inc." The Company operated as a "shell" company until December 31, 1999, when
the Company combined with San Joaquin Oil & Gas Ltd., a Nevada corporation ("Oil
& Gas"). As a result of that transaction, Oil & Gas became a wholly owned
subsidiary of Gasco.
In February 2001, a subsidiary of the Company merged with Gasco Production
Company (formerly know as Pannonian Energy, Inc.) ("GPC"), a private corporation
incorporated under the laws of the State of Delaware. GPC was an independent
energy company engaged in the exploration, development and acquisition of crude
oil and natural gas reserves in the western United States. Prior to closing of
the merger GPC divested itself of all assets not associated with its "Riverbend"
area of interest (the "non-Riverbend assets"). The "spin-offs" were accounted
for at the recorded amounts. The net book value of the non-Riverbend assets in
the United States transferred, including cash of $1,000,000 and liabilities of
$555,185, was approximately $1,850,000. The non-Riverbend assets located outside
of the United States were held by Pannonian International Ltd. ("PIL"), the
shares of which were distributed to the GPC stockholders. The net book value of
PIL as of the date of distribution was approximately $174,000.
Certain shareholders of SJRI surrendered for cancellation 2,438,930 common
shares of the Company's capital stock on completion of the transaction
contemplated by the GPC Agreement.
Upon completion of the transaction, GPC became a wholly owned subsidiary of the
Company. However, since this transaction resulted in the existing shareholders
of GPC acquiring control of the Company, for financial reporting purposes the
business combination is accounted for as a reverse acquisition with GPC as the
accounting acquirer. All information presented for periods prior to March 30,
2001 represents the historical information of GPC.
2
Acquisition, Exploration and Development Expenses
During the year ended December 31, 2004 the Company entered into agreements with
third party service providers and investors who contributed approximately 70% of
the cost of developing designated wells. During 2004, the Company completed a
property acquisition of additional working interests in six producing wells and
certain acreage and gathering system assets for a net purchase price of
approximately $2,400,000, acquired approximately 16,000 net acres in Uinta and
Duchesne Counties Utah for approximately $3,432,000 and spent $18,441,782 in
development and exploration activities. During the year ended December 31, 2003,
the Company spent $5,283,426 in development and exploration activities. During
the year ended December 31, 2002, the Company spent $32,962,855, including the
issuance of 9,500,000 shares of common stock valued at $18,525,000, in the
acquisition of additional leases and in the development and exploitation of the
properties subject to these leases. During 2004, the Company also completed the
expansion of a gathering system located in Uinta County Utah that currently
gathers approximately 97% of the Company's gas production in this area. As of
December 31, 2004, the Company held working interests in 266,886 gross acres
(136,922 net acres) located in Utah, Wyoming and California. As of December 31,
2004, the Company held an interest in 21 gross (7.1 net to the Company's
interest) producing gas wells and 3 gross (1.6 net) shut-in gas wells located on
these properties. As of March 15, 2005 the Company operates 25 wells, of which
23 are currently producing. See "Item 2 - Description of Properties".
Principal Products or Services and Markets
Gasco focuses its exploitation activities on locating natural gas and crude
petroleum. The principal markets for these commodities are natural gas
transmission pipeline companies, utilities, refining companies and private
industry end-users. Historically, nearly all of the Company's sales have been to
a few customers. However, Gasco is not confined to, nor dependent upon, any one
purchaser or small group of purchasers. Accordingly, the loss of a single
purchaser would not materially affect the Company's business because there are
numerous other purchasers in the areas in which Gasco sells its production. For
the years ended December 31, 2004, 2003 and 2002, purchases by the following
company exceeded 10% of the total oil and gas revenues of the Company.
Percent of Production Purchased
For the Year Ended December 31,
------------------------------------------------
2004 2003 2002
---- ---- ----
ConocoPhillips Company 93% 93% 98%
Competitive Business Conditions, Competitive Position in the Industry and
Methods of Competition
The Company's natural gas and petroleum exploration activities take place in a
highly competitive and speculative business atmosphere. In seeking suitable
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natural gas and petroleum properties for acquisition, Gasco competes with a
number of other companies operating in its areas of interest, including large
oil and gas companies and other independent operators with greater financial
resources. Management does not believe that Gasco's competitive position in the
petroleum and natural gas industry will be significant.
Management anticipates a competitive market for obtaining drilling rigs and
services, and the manpower to run them. The current high level of drilling
activity in Gasco's areas of exploration may have a significant adverse impact
on the timing and profitability of Gasco's operations. In addition, as discussed
under Risk Factors, Gasco will be required to obtain drilling and right of way
permits for its wells, and there is no assurance that such permits will be
available timely or at all.
The prices of the Company's products are controlled by domestic and world
markets. However, competition in the petroleum and natural gas exploration
industry also exists in the form of competition to acquire the most promising
acreage blocks and obtaining the most favorable prices for transporting the
product. Gasco, and ventures in which it participates, are relatively small
compared to other petroleum and natural gas exploration companies. As a result,
it may have difficulty acquiring additional acreage and/or projects, and may
have difficulty arranging for the transportation of the oil or natural gas it
produces.
Governmental Regulations and Environmental Laws
We are subject to stringent federal, state, and local laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations may require the
acquisition of permits before drilling commences, limit or prohibit operations
on environmentally sensitive lands such as wetlands or wilderness areas, result
in capital expenditures to limit or prevent emissions or discharges, and place
restrictions on the management of wastes. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties, the imposition of remedial obligations, and the issuance of
injunctive relief. Any changes in environmental laws and regulations that result
in more stringent and costly waste handling, disposal or cleanup requirements
could have a material adverse effect on our operations. While we believe that we
are in substantial compliance with current environmental laws and regulations
and that continued compliance with existing requirements would not materially
affect us, there is no assurance that this trend will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, as
amended, also known as "CERCLA" or "Superfund," and comparable state laws impose
liability without regard to fault or the legality of the original conduct, on
certain classes of persons who are considered to be responsible for the release
of a hazardous substance into the environment. Under CERCLA, these "responsible
persons" may be subject to joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment, for
damages to natural resources, and for the costs of certain health studies, and
it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the release
of hazardous substances into the environment. We also may incur liability under
the Resource Conservation and Recovery Act, also known as "RCRA", which imposes
requirements relating to the management and disposal of solid and hazardous
wastes. While there exists an exclusion from the definition of hazardous wastes
for "drilling fluids, produced waters, and other wastes associated with the
exploration, development, or production of crude oil, natural gas or geothermal
energy," in the course of our operations, we may generate ordinary industrial
wastes, including paint wastes, waste solvents, and waste compressor oils that
may be regulated as hazardous waste.
We currently own or lease, and have in the past owned or leased, properties that
for a number of years have been used for the exploration and production of oil
and gas. Although we have utilized operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
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disposed of or released on or under the properties owned or leased by us or on
or under other locations where such wastes have been taken for disposal. In
addition, some of these properties may have been operated by third parties whose
disposal or release of hydrocarbons or other wastes was not under our control.
These properties and the wastes disposed thereon may be subject to CERCLA, RCRA,
and analogous state laws. Under such laws, we could be required to remove or
remediate previously disposed wastes or property contamination or to perform
remedial operations to prevent future contamination.
The Federal Water Pollution Control Act of 1972, as amended, also known as the
"Clean Water Act" and analogous state laws impose restrictions and strict
controls regarding the discharge of pollutants, including produced waters and
other oil and gas wastes, into state or federal waters. The discharge of
pollutants into regulated waters is prohibited, except in accord with the terms
of a permit issued by EPA or the state. The Clean Water Act provides civil and
criminal penalties for any discharge of oil in harmful quantities and imposes
liabilities for the costs of removing an oil spill.
The Clean Air Act, as amended ("CAA"), restricts the emission of air pollutants
from many sources, including oil and gas operations. New facilities may be
required to obtain permits before work can begin, and existing facilities may be
required to incur capital costs in order to remain in compliance. In addition,
more stringent regulations governing emissions of toxic air pollutants are being
developed by the EPA, and may increase the costs of compliance for some
facilities.
Under the National Environmental Policy Act ("NEPA"), a federal agency, in
conjunction with a permit holder, may be required to prepare an environmental
assessment or a detailed environmental impact statement, also known as an "EIS,"
before issuing a permit that may significantly affect the quality of the
environment. We are currently in negotiations with the U.S. Bureau of Land
Management or "BLM" regarding the preparation of an EIS in connection with
certain proposed exploration and production operations in the Uinta Basin of
Utah. We expect that the EIS will take approximately 18 to 24 months to
complete, at an estimated cost to us of about $500,000. Until the EIS is
completed and issued by the BLM, we will be limited in the number of oil and gas
wells that we can drill in the areas undergoing EIS review. While we do not
expect that the EIS process will result in a significant curtailment in future
oil and gas production from this particular area, we can provide no assurance
regarding the outcome of the EIS process.
5
Number of Total Employees and Number of Full-Time Employees
As of March 15, 2005, Gasco had thirteen full-time employees.
Risk Factors
Due to the nature of the Company's business and the present stage of exploration
on its oil and gas prospects, the following risk factors apply to Gasco's
operations:
We have incurred losses since our inception and will continue to incur losses in
the future.
To date our operations have not generated sufficient operating cash flows to
provide working capital for our ongoing overhead, the funding of our lease
acquisitions and the exploration and development of our properties. Without
adequate financing, we may not be able to successfully develop any prospects
that we have or acquire and we may not achieve profitability from operations in
the near future or at all.
During the years ended December 31, 2004 and 2003, we incurred a net loss of
$4,205,830 and $2,526,525, respectively. As of December 31, 2004, we had an
accumulated deficit of $29,497,591. Our failure to achieve profitability in the
future could adversely affect the trading price of our common stock, our ability
to raise additional capital and our ability to continue as a going concern.
The volatility of natural gas and oil prices could have a material adverse
effect on our business.
A sharp decline in the price of natural gas and oil prices would result in a
commensurate reduction in our income from the production of oil and gas. In the
event prices fall substantially, we may not be able to realize a profit from our
production and would continue to operate at a loss. In recent decades, there
have been periods of both worldwide overproduction and underproduction of
hydrocarbons and periods of both increased and relaxed energy conservation
efforts. Such conditions have resulted in periods of excess supply of, and
reduced demand for, crude oil on a worldwide basis and for natural gas on a
domestic basis. These periods have been followed by periods of short supply of,
and increased demand for, crude oil and natural gas. The excess or short supply
of crude oil has resulted in dramatic price fluctuations even during relatively
short periods of seasonal market demand. Among the factors that can cause the
price volatility are:
o worldwide or regional demand for energy, which is affected by
economic conditions;
o the domestic and foreign supply of natural gas and oil;
o weather conditions;
o domestic and foreign governmental regulations;
6
o political conditions in natural gas or oil producing regions;
o the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production
levels;
o the price and availability of alternative fuels.
o acts of war, terrorism or vandalism; and
o market manipulation.
All of our production is currently located in, and all of our future production
is anticipated to be located in, the Rocky Mountain Region of the United States.
The gas prices that we and other operators in the Rocky Mountain region have
received and are currently receiving are at a discount to gas prices in other
parts of the country. Factors that can cause price volatility for crude oil and
natural gas within this region are:
o the availability of gathering systems with sufficient capacity to
handle local production;
o seasonal fluctuations in local demand for production;
o local and national gas storage capacity;
o interstate pipeline capacity; and
o the availability and cost of gas transportation facilities from
the Rocky Mountain region.
In addition, because of our size we do not own or lease firm capacity on any
interstate pipelines. As a result, our transportation costs are particularly
subject to short-term fluctuations in the availability of transportation
facilities. Our management believes that the steep discount in the prices it
receives may be due to pipeline constraints out of the region, but there is no
assurance that increased capacity will improve the prices to levels seen in
other parts of the country in the future. Even if we acquire additional pipeline
capacity, conditions may not improve due to other factors listed above.
It is impossible to predict natural gas and oil price movements with certainty.
Lower natural gas and oil prices may not only decrease our revenues on a per
unit basis but also may reduce the amount of natural gas and oil that we can
produce economically. A substantial or extended decline in natural gas and oil
prices may materially and adversely affect our future business, financial
condition, results of operations, liquidity and ability to finance planned
capital expenditures. Further, oil prices and natural gas prices do not
necessarily move together.
7
Our oil and gas reserve information is estimated and may not reflect our actual
reserves.
Estimating accumulations of gas and oil is complex and is not exact because of
the numerous uncertainties inherent in the process. The process relies on
interpretations of available geological, geophysical, engineering and production
data. The extent, quality and reliability of this technical data can vary. The
process also requires certain economic assumptions, some of which are mandated
by the SEC, such as gas and oil prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The accuracy of a reserve
estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions; and
o the judgment of the persons preparing the estimate.
The proved reserve information as of December 31, 2004, included herein is based
on estimates prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
The most accurate method of determining proved reserve estimates is based upon a
decline analysis method, which consists of extrapolating future reservoir
pressure and production from historical pressure decline and production data.
The accuracy of the decline analysis method generally increases with the length
of the production history. Since most of our wells had been producing less than
three years as of December 31, 2004, their production history was relatively
short, so other (generally less accurate) methods such as volumetric analysis
and analogy to the production history of wells of other operators in the same
reservoir were used in conjunction with the decline analysis method to determine
our estimates of proved reserves. As our wells are produced over time and more
data is available, the estimated proved reserves will be redetermined on an
annual basis and may be adjusted based on that data.
Actual future production, gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable gas and oil
reserves most likely will vary from our estimates. Any significant variance
could materially affect the quantities and present value of our reserves. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development and prevailing gas and oil
prices. Our reserves may also be susceptible to drainage by operators on
adjacent properties.
It should not be assumed that the present value of future net cash flows
included herein is the current market value of our estimated proved gas and oil
reserves. In accordance with SEC requirements, we generally base the estimated
discounted future net cash flows from proved reserves on prices and costs on the
date of the estimate. Actual future prices and costs may be materially higher or
lower than the prices and costs as of the date of the estimate.
8
Future changes in commodity prices or our estimates and operational developments
may result in impairment charges to our reserves.
We may be required to write down the carrying value of our gas and oil
properties when gas and oil prices are low or if there is substantial downward
adjustments to the estimated proved reserves, increases in the estimates of
development costs or deterioration in the exploration results.
We follow the full cost method of accounting, under which, capitalized gas and
oil property costs less accumulated depletion and net of deferred income taxes
may not exceed an amount equal to the present value, discounted at 10%, of
estimated future net revenues from proved gas and oil reserves plus the cost, or
estimated fair value, if lower of unproved properties.
Should capitalized costs exceed this ceiling, an impairment would be recognized.
The present value of estimated future net revenues is computed by applying
current prices of gas and oil to estimated future production of proved gas and
oil reserves as of period-end, less estimated future expenditures to be incurred
in developing and producing the proved reserves assuming the continuation of
existing economic conditions. Once an impairment of gas and oil properties is
recognized, it is not reversible at a later date even if oil or gas prices
increase.
The development of oil and gas properties involves substantial risks that may
result in a total loss of investment.
The business of exploring for and producing oil and gas involves a substantial
risk of investment loss that even a combination of experience, knowledge and
careful evaluation may not be able to overcome. Drilling oil and gas wells
involves the risk that the wells will be unproductive or that, although
productive, the wells do not produce oil and/or gas in economic quantities.
Other hazards, such as unusual or unexpected geological formations, pressures,
fires, blowouts, loss of circulation of drilling fluids or other conditions may
substantially delay or prevent completion of any well. Adverse weather
conditions can also hinder drilling operations.
A productive well may become uneconomic in the event water or other deleterious
substances are encountered, which impair or prevent the production of oil and/or
gas from the well. In addition, production from any well may be unmarketable if
it is contaminated with water or other deleterious substances.
We may not be able to obtain adequate financing to continue our operations.
We have relied in the past primarily on the sale of equity capital and farm-out
and other similar types of transactions to fund working capital and the
acquisition of our prospects and related leases. Failure to generate operating
cash flow or to obtain additional financing could result in substantial dilution
of our property interests, or delay or cause indefinite postponement of further
exploration and development of our prospects with the possible loss of our
properties.
We will require significant additional capital to fund our future activities and
to service current and any future indebtedness. In particular, we face
uncertainties relating to our ability to generate sufficient cash flows from
operations to fund the level of capital expenditures required for our oil and
9
gas exploration and production activities and our obligations under various
agreements with third parties relating to exploration and development of certain
prospects. Our failure to find the financial resources necessary to fund our
planned activities and service our debt and other obligations could adversely
affect our ability to continue as a going concern.
We compete with larger companies in acquiring properties and operating and
drilling services.
Our natural gas and petroleum exploration activities take place in a highly
competitive and speculative business atmosphere. In seeking suitable natural gas
and petroleum properties for acquisition, we compete with a number of other
companies operating in our areas of interest, including large oil and gas
companies and other independent operators with greater financial resources. We
do not believe that our competitive position in the petroleum and natural gas
industry will be significant.
We anticipate a competitive market for obtaining drilling rigs and services, and
the manpower to operate them. The current high level of drilling activity in our
areas of exploration may have a significant adverse impact on the timing and
profitability of our operations. In addition, we are required to obtain drilling
and right of way permits for our wells, and there is no assurance that such
permits will be available on a timely basis or at all.
We may suffer losses or incur liability for events that we or the operator of a
property have chosen not to insure against.
Although management believes the operator of any property in which we may
acquire interests will acquire and maintain appropriate insurance coverage in
accordance with standard industry practice, we may suffer losses from
uninsurable hazards or from hazards, which we or the operator have chosen not to
insure against because of high premium costs or other reasons. We may become
subject to liability for pollution, fire, explosion, blowouts, cratering and oil
spills against which we cannot insure or against which we may elect not to
insure. Such events could result in substantial damage to oil and gas wells,
producing facilities and other property and personal injury. The payment of any
such liabilities may have a material adverse effect on our financial position.
We may incur losses as a result of title deficiencies in the properties in which
we invest.
If an examination of the title history of a property that we have purchased
reveals a petroleum and natural gas lease that has been purchased in error from
a person who is not the owner of the mineral interest desired, our interest
would be worthless. In such an instance, the amount paid for such petroleum and
natural gas lease or leases would be lost.
It is our practice, in acquiring petroleum and natural gas leases, or undivided
interests in petroleum and natural gas leases, not to undergo the expense of
retaining lawyers to examine the title to the mineral interest to be placed
under lease or already placed under lease. Rather, we will rely upon the
judgment of petroleum and natural gas lease brokers or landmen who perform the
fieldwork in examining records in the appropriate governmental office before
attempting to acquire a lease in a specific mineral interest.
10
Prior to the drilling of a petroleum and natural gas well, however, it is the
normal practice in the petroleum and natural gas industry for the person or
company acting as the operator of the well to obtain a preliminary title review
of the spacing unit within which the proposed petroleum and natural gas well is
to be drilled to ensure there are no obvious deficiencies in title to the well.
Frequently, as a result of such examinations, certain curative work must be done
to correct deficiencies in the marketability of the title, and such curative
work entails expense. The work might include obtaining affidavits of heirship or
causing an estate to be administered.
Our ability to market the oil and gas that we produce is essential to our
business.
Several factors beyond our control may adversely affect our ability to market
the oil and gas that we discover. These factors include the proximity, capacity
and availability of oil and gas pipelines and processing equipment, market
fluctuations of prices, taxes, royalties, land tenure, allowable production and
environmental protection. The extent of these factors cannot be accurately
predicted, but any one or a combination of these factors may result in our
inability to sell our oil and gas at prices that would result in an adequate
return on our invested capital. For example, we currently distribute the gas
that we produce through a single pipeline. If this pipeline were to become
unavailable, we would incur additional costs to secure a substitute facility in
order to deliver the gas that we produce.
We could become subject to certain Questar Pipeline Company Gas Requirements.
We currently deliver all of our gathered gas into a Questar Pipeline Company
("Questar") main line transportation system. Questar is currently evaluating
their gas quality requirements to transport gas on their system. These
requirements could and most likely, would be imposed on all companies delivering
gas into their main line. If Questar should require companies to meet more
strict quality requirements, there is no assurance that we could meet the new
requirements in the short term future. It is possible that we would need to make
significant capital expenditures to meet the new gas quality requirements and/or
to transport our gas. During this process and/or adding new transportation
facilities, our production could be severely curtailed or even shut -in
completely.
Environmental costs and liabilities and changing environmental regulation could
materially affect our cash flow
Our operations are subject to stringent federal, state and local laws and
regulations relating to environmental protection. These laws and regulations may
require the acquisition of permits or other governmental approvals, limit or
prohibit our operations on environmentally sensitive lands, and place burdensome
restrictions on the management and disposal of wastes. Failure to comply with
these laws may result in the assessment of administrative, civil and criminal
penalties, the imposition of remedial obligations, and the issuance of
injunctions that may delay or prevent our operations. Any stringent changes to
these environmental laws and regulations may result in increased costs to us
with respect to the disposal of wastes, the performance of remedial activities,
and the incurrence of capital expenditures. Please read "Governmental
Regulations and Environmental Laws," above.
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We are subject to complex governmental regulations which may adversely affect
the cost of our business.
Petroleum and natural gas exploration, development and production are subject to
various types of regulation by local, state and federal agencies. We may be
required to make large expenditures to comply with these regulatory
requirements. Legislation affecting the petroleum and natural gas industry is
under constant review for amendment and expansion. Also, numerous departments
and agencies, both federal and state, are authorized by statute to issue and
have issued rules and regulations binding on the petroleum and natural gas
industry and its individual members, some of which carry substantial penalties
for failure to comply. Any increases in the regulatory burden on the petroleum
and natural gas industry created by new legislation would increase our cost of
doing business and, consequently, adversely affect our profitability. A major
risk inherent in drilling is the need to obtain drilling and right of way
permits from local authorities. Delays in obtaining drilling and/or right of way
permits, the failure to obtain a drilling and/or right of way permit for a well
or a permit with unreasonable conditions or costs could have a materially
adverse effect on our ability to effectively develop our properties.
Our competitors may have greater resources which could enable them to pay a
higher price for properties and to better withstand periods of low market prices
for hydrocarbons.
The petroleum and natural gas industry is intensely competitive, and we compete
with other companies, which have greater resources. Many of these companies not
only explore for and produce crude petroleum and natural gas but also carry on
refining operations and market petroleum and other products on a regional,
national or worldwide basis. Such companies may be able to pay more for
productive petroleum and natural gas properties and exploratory prospects or
define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, such
companies may have a greater ability to continue exploration activities during
periods of low hydrocarbon market prices. Our ability to acquire additional
properties and to discover reserves in the future will be dependent upon our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment.
We may have difficulty managing growth in our business.
Because of our small size, growth in accordance with our business plans, if
achieved, will place a significant strain on our financial, technical,
operational and management resources. As we expand our activities and increase
the number of projects we are evaluating or in which we participate, there will
be additional demands on our financial, technical and management resources. The
failure to continue to upgrade our technical, administrative, operating and
financial control systems or the occurrence of unexpected expansion
difficulties, including the recruitment and retention of experienced managers,
geoscientists and engineers, could have a material adverse effect on our
business, financial condition and results of operations and our ability to
timely execute our business plan.
12
Because our reserves and production are concentrated in a small number of
properties, production problems or significant changes in reserve estimates
related to any property could have a material impact on our business.
Our current reserves and production primarily come from producing properties in
Utah and Wyoming. If mechanical problems, depletion or other events reduced a
substantial portion of the production, our cash flows would be adversely
affected. If the actual reserves associated with our fields are less than our
estimated reserves, our results of operations and financial condition could be
adversely affected.
Financial difficulties encountered by our partners or third-party operators
could adversely affect the exploration and development of our prospects.
Liquidity and cash flow problems encountered by our partners or the co-owners of
our properties may prevent or delay the drilling of a well or the development of
a project. Our partners and working interest co-owners may be unwilling or
unable to pay their share of the costs of projects as they become due. In the
case of a farm-out partner, we would have to find a new farm-out partner or
obtain alternative funding in order to complete the exploration and development
of the prospects subject to the farm-out agreement. In the case of a working
interest owner, we could be required to pay the working interest owner's share
of the project costs. We cannot assure you that we would be able to obtain the
capital necessary to fund either of these contingencies or that we would be able
to find a new farm-out partner.
Shortages of supplies, equipment and personnel may adversely affect our
operations.
Our ability to conduct operations in a timely and cost effective manner depends
on the availability of supplies, equipment and personnel. The oil and gas
industry is cyclical and experiences periodic shortages of drilling rigs,
supplies and experienced personnel. Shortages can delay operations and
materially increase operating and capital costs.
Hedging our production may result in losses.
We currently have no hedging agreements in place. However, we may in the future
enter into arrangements to reduce our exposure to fluctuations in the market
prices of oil and natural gas. We may enter into oil and gas hedging contracts
in order to increase credit availability. Hedging will expose us to risk of
financial loss in some circumstances, including if:
o production is less than expected;
o the other party to the contract defaults on its obligations; or
o there is a change in the expected differential between the
underlying price in the hedging agreement and actual prices
received.
In addition, hedging may limit the benefit we would otherwise receive from
increases in the prices of oil and gas. Further, if we do not engage in hedging,
we may be more adversely affected by changes in oil and gas prices than our
competitors who engage in hedging.
13
Our success depends on our key management personnel, the loss of any of whom
could disrupt our business.
The success of our operations and activities is dependent to a significant
extent on the efforts and abilities of our management. The loss of services of
any of our key managers could have a material adverse effect on our business. We
have not obtained "key man" insurance for any of our management. Mr. Erickson is
the Chief Executive Officer and Mr. Decker is an Executive Vice President and
Chief Operating Officer of Gasco. The loss of their services may adversely
affect our business and prospects.
Our officers and directors are engaged in other businesses which may result in
conflicts of interest
Certain of our officers and directors also serve as directors of other companies
or have significant shareholdings in other companies. For example, our chairman,
Marc A. Bruner, is the largest shareholder and Chairman of the Advisory
Committee of Galaxy Energy Corporation. As Advisory Committee Chairman, Mr.
Bruner is involved in identifying and acquiring large land packages for
exploitation and development by Galaxy. In addition, another of our directors,
C. Tony Lotito, is Executive Vice President, Chief Financial Officer, Treasurer
and Director of Galaxy.
To the extent that such other companies participate in ventures in which we may
participate, or compete for prospects or financial resources with us, these
officers and directors will have a conflict of interest in negotiating and
concluding terms relating to the extent of such participation. In the event that
such a conflict of interest arises at a meeting of the board of directors, a
director who has such a conflict must disclose the nature and extent of his
interest to the board of directors and abstain from voting for or against the
approval of such participation or such terms.
In accordance with the laws of the State of Nevada, our directors are required
to act honestly and in good faith with a view to the best interests of Gasco. In
determining whether or not we will participate in a particular program and the
interest therein to be acquired by it, the directors will primarily consider the
degree of risk to which we may be exposed and its financial position at that
time.
It may be difficult to enforce judgments predicated on the federal securities
laws on some of our board members who are not U.S. residents.
Two of our directors reside outside the United States and maintain a substantial
portion of their assets outside the United States. As a result it may be
difficult or impossible to effect service of process within the United States
upon such persons, to bring suit in the United States or to enforce, in the U.S.
courts, any judgment obtained there against such persons predicated upon any
civil liability provisions of the U.S. federal securities laws.
Foreign courts may not entertain original actions against our directors or
officers predicated solely upon U.S. federal securities laws. Furthermore,
14
judgments predicated upon any civil liability provisions of the U.S. federal
securities laws may not be directly enforceable in foreign countries.
Risks Related to Our Common Stock
Our common stock has experienced, and may continue to experience, price
volatility and a low trading volume.
The trading price of our common stock has been and may continue to be subject to
large fluctuations, which may result in losses to investors. Our stock price may
increase or decrease in response to a number of events and factors, including:
o the results of our exploratory drilling;
o trends in our industry and the markets in which we operate;
o changes in the market price of the commodities we sell;
o changes in financial estimates and recommendations by securities
analysts;
o acquisitions and financings;
o quarterly variations in operating results;
o the operating and stock price performance of other companies that
investors may deem comparable; and
o purchases or sales of blocks of our common stock.
This volatility may adversely affect the price of our common stock regardless of
our operating performance.
Shares eligible for future sale may cause the market price for our common stock
to drop significantly, even if our business is doing well.
If our existing shareholders sell our common stock in the market following this
offering, or if there is a perception that significant sales may occur, the
market price of our common stock could drop significantly. In such case, our
ability to raise additional capital in the financial markets at a time and price
favorable to us might be impaired. In addition, our board of directors has the
authority to issue additional shares of our authorized but unissued common stock
without the approval of our shareholders. Additional issuance of common stock
would dilute the ownership percentage of existing shareholders and may dilute
the earnings per share of our common stock. As of December 31, 2004, we had
70,517,209 shares of common stock issued and outstanding. As of such date, there
were 8,460,678 shares of common stock issuable upon exercise of outstanding
options and conversion of our Series B Convertible Preferred Stock ("Preferred
Stock"). Additional options may be granted to purchase 3,825,721 shares of
common stock under our stock option plan and an additional 179,150 shares of
common stock are issuable under our restricted stock plan. As of December 31 of
15
each year, the number of shares of common stock issuable under our stock option
plan automatically increases so that the total number of shares of common stock
issuable under such plan is equal to 10% of the total number of shares of common
stock outstanding on such date.
Assuming all of the notes are converted at the applicable conversion prices, the
number of shares of our common stock outstanding would increase by approximately
16,250,000 shares to approximately 86,767,209 shares (this number assumes no
exercise of the options or rights described above or conversion of the Preferred
Stock).
We have not previously paid dividends on our common stock and we do not
anticipate doing so in the foreseeable future.
We have not in the past paid, and do not anticipate paying in the foreseeable
future, cash dividends on our common stock. Any future decision to pay a
dividend and the amount of any dividend paid, if permitted, will be made at the
discretion of our board of directors.
We have anti-takeover provisions in our certificate of incorporation and by-laws
that may discourage a change of control.
Our articles of incorporation and bylaws contain several provisions that could
delay or make more difficult the acquisition of us through a hostile tender
offer, open market purchases, proxy contest, merger or other takeover attempt
that a stockholder might consider in his or her best interest, including those
attempts that might result in a premium over the market price of our common
stock.
Under the terms of our articles of incorporation and as permitted under Nevada
law, we have elected not to be subject to Nevada's anti-takeover law. This law
provides that specified persons who, together with affiliates and associates,
own, or within three years did own, 15% or more of the outstanding voting stock
of a corporation could not engage in specified business combinations with the
corporation for a period of three years after the date on which the person
became an interested stockholder. With the approval of our stockholders, we may
amend our articles of incorporation in the future to become governed by the
anti-takeover law. This provision would then have an anti-takeover effect for
transactions not approved in advance by our board of directors, including
discouraging takeover attempts that might result in a premium over the market
price for the shares of our common stock.
Available Information
Our Internet website is http://www.gascoenergy.com and you may access, free of
charge, through the Investor Relations portion of our website, our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K and amendments to such reports filed or furnished pursuant to Section 13(a)
or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as
reasonably practicable after we electronically file such material with, or
furnish it to, the SEC. Information contained on our website is not part of this
report.
16
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the information in this annual report, contains forward-looking
statements within the meanings of Section 27A of the Securities Act of 1933.
These statements express, or are based on, our expectations about future events.
Forward-looking statements give our current expectations or forecasts of future
events. Forward-looking statements generally can be identified by the use of
forward looking terminology such as "may," "will," "expect," "intend,"
"project," "estimate," "anticipate," "believe" or "continue" or the negative
thereof or similar terminology. They include statements regarding our:
o financial position;
o business strategy;
o budgets;
o amount, nature and timing of capital expenditures;
o estimated reserves of natural gas and oil;
o drilling of wells;
o acquisition and development of oil and gas properties;
o timing and amount of future production of natural gas and oil;
o operating costs and other expenses; and
o cash flow and anticipated liquidity.
Although we believe the expectations and forecasts reflected in these and other
forward-looking statements are reasonable, we can give no assurance they will
prove to have been correct. They can be affected by inaccurate assumptions or by
known or unknown risks and uncertainties. Factors that could cause actual
results to differ materially from expected results are described under "Risk
Factors" and include:
o our ability to generate sufficient cash flow to operate;
o the lack of liquidity of our common stock;
o the risks associated with exploration;
o natural gas and oil price volatility;
o the fluctuation in the demand for natural gas and oil;
17
o uncertainties in the projection of future rates of production and
timing of development expenditures;
o operating hazards attendant to the natural gas and oil business;
o downhole drilling and completion risks that are generally not
recoverable from third parties or insurance;
o potential mechanical failure or under-performance of significant
wells;
o climatic conditions;
o availability and cost of material and equipment;
o delays in anticipated start-up dates;
o actions or inactions of third-party operators of our properties;
o our ability to find and retain skilled personnel;
o availability of capital;
o the strength and financial resources of our competitors;
o regulatory developments;
o environmental risks; and
o general economic conditions.
Any of the factors listed above and other factors contained in this annual
report could cause our actual results to differ materially from the results
implied by these or any other forward-looking statements made by us or on our
behalf. We cannot assure you that our future results will meet our expectations.
When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this annual report.
Our forward-looking statements speak only as of the date made.
ITEM 2 - DESCRIPTION OF PROPERTY
Petroleum and Natural Gas Properties
Gasco is a natural gas and petroleum exploitation and development company
engaged in locating and developing hydrocarbon prospects primarily in the Rocky
Mountain Region. Gasco's strategy is to enhance stockholder value by using new
technologies to generate high-potential exploitation prospects in this area. The
Company's principal business is the acquisition of leasehold interests in
18
petroleum and natural gas rights, either directly or indirectly, and the
exploitation and development of properties subject to these leases.
The Company's corporate strategy is to grow through drilling projects. The
Company has been focusing its drilling efforts in the Riverbend Project located
in the Uinta Basin of northeastern Utah. The higher oil and gas prices during
2003 and 2004 due to factors such as inventory levels of gas storage, different
temperatures in parts of the country and changing demand in the United States,
combined with the continued instability in the Middle East have increased the
profitability of the Company's drilling projects in this area. The increased
drilling activity resulting from the higher oil and gas prices have decreased
the availability of drilling rigs and experienced personnel in this area and my
continue to do so.
Riverbend Project
The Riverbend Project comprises approximately 134,963 gross acres in the Uinta
Basin of northeastern Utah, of which Gasco hold interests in approximately
68,615 net acres as of December 31, 2004. The Company can also earn interests in
approximately 2,685 gross acres in this area under farm-out and other
agreements. The Company's engineering and geologic focus is concentrated on
three tight-sand formations in the Uinta basin: the Wasatch, Mesaverde and
Blackhawk formations.
On January 20, 2004 the Company entered into agreements, which were subsequently
amended in July 2004, with a group of industry providers (together, the "Service
Parties") to accelerate the development of Gasco's oil and gas properties by
drilling up to 50 wells in Gasco's Riverbend Project in Utah's Uinta Basin.
Gasco has agreed that the Service Parties, which includes Schlumberger Oilfield
Services, will have the exclusive right to provide their services in the
development of the Riverbend acreage. The agreement initially provided for the
group to develop a bundle of 10 wells during 2004 using a single rig.
Thereafter, drilling was accelerated with the use of an additional rig.
General Terms of the Agreement:
o Contract Area consists of Gasco's leasehold position in portions
of Carbon,Duchesne and Uintah Counties, Utah.
o Gasco is permitted to independently develop its acreage subject
to certain limitations and provisions of the agreement.
o Schlumberger will coordinate most operational activities under
Gasco's direction as operator of record.
o Gasco has elected to fund approximately 30% of each of the wells
drilled under this agreement. Gasco's interest in the production
stream from a bundle, net of royalties, taxes and lease operating
expenses, is estimated to equal the proportion of the total well
costs that it funds.
o The Service Parties have undertaken to provide approximately 45%
of the costs of each project bundle in return for a net profits
interest in each bundle proportionate to their costs contributed.
19
o A third party investor, who also became a party to the Agreement,
has undertaken to provide approximately 25% of the costs of each
project bundle in return for a net profits interest in each
bundle proportionate to its costs contributed.
To secure its obligations under the agreement, described above, the Company has
pledged its interests in each of the wells in each bundle.
In connection with the Service Parties agreements, the Company completed a
disposition of net profits interests of between 18.75% and 25% in the 8 wells
that have been drilled in the Riverbend area in Utah during 2004 for total cash
consideration of $4,314,984, net of adjustments and commissions. The purpose of
this transaction was to allow the third party investor to become a party to our
service provider arrangements. The consideration paid to the Company in this
transaction represented the share of such investor's development costs of the 8
wells completed as of such date. This investor has the opportunity to continue
to participate in the development program under the service provider arrangement
by funding 25% of future development costs.
During the fourth quarter of 2004, the Service Parties agreed to proceed with
the second bundle of ten wells. The drilling of the second bundle commenced late
in 2004. The Company's capital budget for this area during 2005 is anticipated
to be $38,000,000 for the drilling of 20 wells in this area.
During the year ended December 31, 2004, the Company spudded twelve wells in the
Riverbend area, which are part of the first and second ten well bundles
contemplated by the agreements with the Service Parties and investor, as
described above. As of March 15, 2005, all of these wells are producing. The
Company increased its drilling activity in the Riverbend area during 2004 by
adding a second drilling rig during April 2004 and by adding a third drilling
rig during December 2004. The Company also successfully recompleted one
additional well in this area during 2004.
During December 2004, the Company completed the acquisition of approximately
16,000 net acres in the Riverbend Area for a purchase price of approximately
$3,432,000. Pursuant to an existing contract, an unrelated third party had the
right to purchase 25% of the acquired acreage at a price equal to 25% of the
purchase price. This right was exercised by the third party during January 2005
which had the effect of reducing the Company's interest in the acquired acreage
to 12,000 net acres and reducing the purchase price of the acquisition to
approximately $2,575,000.
During July 2004, the Company began construction on an additional ten-mile
pipeline as part of the gathering system in the Riverbend area to create
additional pipeline capacity for the Company's drilling projects in this area.
This pipeline was completed in early November and currently gathers
approximately 97% of the Company's gas across the Riverbend Project.
On March 9, 2004, the Company completed the acquisition of additional working
interests in six producing wells, 13,062 net acres and gathering system assets
located in the Uinta Basin in Utah for approximately $3,175,000. During May 2004
an unrelated third party exercised its right to purchase 25% of the acquired
properties at the acquisition price, which had the effect of reducing the
purchase price to approximately $2,400,000 and reducing the Company's interest
20
in the acquisition to 75%. The effective date of the acquisition was January 1,
2004; however, the net revenue from the producing wells during the period from
January 1, 2004 through March 9, 2004 was recorded as a reduction to the
purchase price.
During October 2003, the Company completed a transaction in which it settled an
outstanding amount owed of $1,606,982 to an oilservice provider arising from
drilling and completion expenditures on five Gasco-operated wells, by paying the
provider $400,000 in cash and conveying to the provider a portion of its
interests in two Riverbend wells. Subsequent to the transaction, the Company
retained a 30% working interest in the two subject wells and the ownership in
remaining three wells is unchanged.
Greater Green River Basin Project
As of December 31, 2004, the Company has a leasehold interest in approximately
128,055 gross acres and 65,666 net acres in this area. The Company holds an
operated interest in five nonproducing wells in this area and an operated
interest in one producing well in this area. Additionally, the Company owns a
non-operated interest in two producing wells in this area. During 2004, the
Company re-entered a previously drilled well in this area which began producing
from one zone which is currently shut-in.
The Company is currently considering additional options for this area such as
the farm-out of some of our acreage and other similar type transactions.
During 2003, the Company impaired certain of its unproved acreage in Wyoming by
reclassifying $1,725,000 of costs associated with this acreage into the full
cost pool. The impairment represented the cost of certain of the Company's
acreage that the Company no longer considered prospective. These costs became
subject to amortization during the fourth quarter of 2003.
Southern California Project
The Company has a leasehold interest in approximately 3,868 gross acres (2,641
net acres) in Kern and San Luis Obispo Counties of Southern California. The
Company itself has no drilling or development plans for this acreage during 2005
and plans to continue paying leasehold rentals and other minimum geological
expenses to preserve the Company's acreage positions on these prospects. The
Company is actively pursuing a partner to test this acreage for hydrocarbon
potential.
Company Reserve Estimates
The following table summarizes the Company's estimated reserve data as of
December 31, 2004, as estimated by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers. The present value of future net cash flows is
based on prices at December 31, 2004 of $5.56 per Mcf of gas and $42.25 per bbl
of oil. All of the Company's proved reserves are located within the state of
Utah.
21
Proved Reserve Quantities Present Value of Future Net Cash Flows
Proved Proved
Mcf of Gas Bbls of Oil Undeveloped Developed Total
Total 39,700,156 274,074 $ 17,592,000 $ 14,709,600 $ 32,301,600
=========== ======== ============= ============= ============
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of any estimate. A decrease in price of $0.10 per Mcf
for natural gas and $1.00 per barrel of oil would result in a decrease in the
Company's December 31, 2004 present value of future net cash flows of
approximately $2,083,000.
No estimates of proved reserves comparable to those included herein have been
included in reports to any federal agency other than the Securities and Exchange
Commission.
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes,
average sales prices received and average production costs associated with the
Company's sales of natural gas for the periods indicated.
For the Years Ended December 31,
------------------------------------------
2004 2003 2002
------------ ----------- --------------
Natural gas production (Mcf) 505,967 257,035 66,444
Average sales price per Mcf $5.79 $4.69 $ 2.47
Oil production (Bbl) 5,080 1,988 -
Average sales price per Bbl $38.43 $28.52 -
Expenses per Mcfe:
Lease operating $1.19 $1.25 $ 1.80
General and administrative $7.81 $10.48 $ 76.46
Depletion and impairment $2.06 $2.06 $ 9.73
Development, Exploration and Acquisition Capital Expenditures
During the year ended December 31, 2004, the Company spent $23,462,908 in
development and exploration activities, including a property acquisition for a
net purchase price of approximately $2,400,000 and an acreage acquisition in the
Riverbend Area for approximately $3,432,000. Pursuant to an existing contract,
an unrelated third party had the right to purchase 25% of the acquired acreage
at a price equal to 25% of the purchase price. This right was exercised by the
third party during January 2005 which had the effect of reducing the Company's
purchase price of the acquisition to approximately $2,575,000. During the year
ended December 31, 2003, the Company spent $5,283,426 in development and
exploration activities. During the year ended December 31, 2002, the Company
spent $32,962,855, including the issuance of 9,500,000 shares of common stock
valued at $18,525,000, in the acquisition of additional leases and in the
development and exploitation of the properties subject to these leases. As of
December 31, 2004, the Company held working interests in 266,886 gross acres
(136,922 net acres) located in Utah, Wyoming and California. As of December 31,
22
2004, the Company held an interest in 21 gross (7.1 net to Gasco's interest)
producing gas wells and 3 gross (1.6 net) shut-in gas wells located on these
properties.
The following table presents information regarding the Company's net costs
incurred in the purchase of proved and unproved properties and in exploration
and development activities:
For the Years Ended December 31,
-----------------------------------------------------------
2004 2003 2002
------------------- ------------------- ------------------
Property acquisition costs:
Unproved $ 5,021,126 $ 667,557 $22,324,547
Proved 723,9012 -- --
Exploration costs (a) 216,165 396,967 3,319,124
Development costs 17,501,7162 4,218,9022 7,319,184
----------- ---------- ----------
Total excluding asset retirement obligation 23,462,908 5,283,426 32,962,855
========== ========= ==========
Total including asset retirement obligation $23,398,559 $ 5,398,678 $ 32,962,855
=========== ========== ===========
(a) Includes seismic data acquisitions of $850,000 during the year ended
December 31, 2002.
Productive Gas Wells
The following summarizes the Company's productive and shut-in gas wells as of
December 31, 2004. Productive wells are producing wells and wells capable of
production. Shut-in wells are wells that are capable of production but are
currently not producing. Gross wells are the total number of wells in which the
Company has an interest. Net wells are the sum of the Company's fractional
interests owned in the gross wells.
Productive Gas Wells
Gross Net
Producing gas wells 21 7.1
Shut-in gas wells 3 1.3
-- ---
24 8.4
== ===
The Company operates all of the above producing wells and one of the shut-in
wells. The remaining two shut-in wells are located in Sublette County Wyoming
and were drilled and are operated by Burlington Oil & Gas, L.P.
Oil and Gas Acreage
The following table sets forth the undeveloped and developed leasehold acreage,
by area, held by the Company as of December 31, 2004. Undeveloped acres are
acres on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas, regardless of
whether or not such acreage contains proved reserves. Developed acres are acres,
which are spaced or assignable to productive wells. Gross acres are the total
23
number of acres in which Gasco has a working interest. Net acres are the sum of
Gasco's fractional interests owned in the gross acres. The table does not
include acreage that the Company has a contractual right to acquire or to earn
through drilling projects, or any other acreage for which the Company has not
yet received leasehold assignments. In certain leases, the Company's ownership
is not the same for all depths; therefore, the net acres in these leases are
calculated using the greatest ownership interest at any depth. Generally this
greater interest represents Gasco's ownership in the primary objective
formation.
Undeveloped Acres Developed Acres
-------------------------------- --------------------------------
Gross Net Gross Net
Utah 134,963 68,615 880 344
Wyoming 128,055 65,666 320 68
California 3,868 2,641 - -
-------- --------- ------ -----
Total acres 266,886 136,922 1,200 412
========= ========= ====== =====
The following table summarizes the gross and net undeveloped acres by area that
will expire in each of the next three years. The Company's acreage positions are
maintained by the payment of delay rentals or by the existence of a producing
well on the acreage.
Expiring in 2005 Expiring in 2006 Expiring in 2007
Gross Net Gross Net Gross Net
Utah 5,268 1,670 10,609 5,144 8,861 3,582
Wyoming 38,543 23,283 8,352 4,492 4,644 3,628
California 777 433 - - - -
------ ------ ------ ------- ------ -----
Total 44,588 25,386 18,961 9,636 13,505 7,210
====== ====== ====== ===== ====== =====
During 2003, the Company impaired certain of its unproved acreage in Wyoming by
reclassifying $1,725,000 of costs associated with this acreage into the full
cost pool. The impairment represented the cost of certain of the Company's
acreage expiring in 2004 that the Company no longer considered prospective.
These costs became subject to amortization during the fourth quarter of 2003.
The impaired acreage (approximately 9,136 net acres) is excluded from the tables
above.
As of December 31, 2004, approximately 79% of the acreage that Gasco holds is
located on federal lands and approximately 19% of the acreage is located on
state lands. It has been Gasco's experience that the permitting process related
to the development of acreage on federal lands is more time consuming and
expensive than the permitting process related to acreage on state lands. The
Company has generally been able to obtain state permits within 30 days, while
obtaining federal permits has taken several months or longer. Accordingly, if
the development of the Company's acreage located on federal lands is delayed
significantly by the permitting process, the Company may have to operate at a
loss for an extended period of time.
24
Drilling Activity
The following table sets forth the Company's drilling activity during the years
ended December 31, 2004, 2003 and 2002. In the table, "gross" refers to the
total wells in which we have a working interest, and "net" refers to gross wells
multiplied by the Company's working interest.
For the Year Ended December 31,
-----------------------------------------------------------------------------
2004 2003 2002
---------------- ------------------------ ----------------------------
Gross Net Gross Net Gross Net
Exploratory Wells:
Productive - - - - 2 0.7
Dry - - - - 1 1.0
-- -- -- -- -- ---
Total wells - - - - 3 1.7
== == == == == ===
Development Wells:
Productive 11 3.0 - - 6 3.3
Dry - - - - - -
- ---- -- -- -- ---
Total wells 11 3.0 - - 6 3.3
== ==== == == == ===
During the first quarter of 2005, the Company drilled and cased three successful
wells and is currently in the process of drilling three additional wells, all of
which are located in the Uinta Basin of Utah.
Office Space
During 2004, the Company leased approximately 3,255 square feet of office space
in Englewood, Colorado for approximately $46,000 per year, under a lease, which
terminates on August 30, 2005. Subsequent to December 31, 2004, as a result of
the Company's growth, the Company entered into a new lease for approximately
6,234 square feet of office space which commences April 1, 2005. The lease
terminates on March 31, 2010 and the average rent for this space over the life
of the lease is approximately $86,500 per year. The Company believes that this
new space will meet its needs for the next five years.
ITEM 3 - LEGAL PROCEEDINGS
None.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
25
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock commenced trading on the OTC bulletin board on March
30, 2001, under the symbol "GASE.OB." On December 6, 2004, Gasco's common stock
commenced trading as a listed security on the American Stock Exchange under the
symbol "GSX." As of March 15, 2005, the Company had 110 record shareholders of
its common stock. During the last two fiscal years, no cash dividends were
declared on Gasco's common stock. The Company's management does not anticipate
that dividends will be paid on its common stock in the near future.
The following table sets forth, for the periods indicated, the high and low
sales prices per share of the Company's common stock as reported on the OTC
bulletin board for the periods indicated through December 5, 2004, and as
reported on the American Stock Exchange from December 6, 2004 through December
31, 2004.
High Low
2003
First Quarter $0.75 $0.46
Second Quarter 0.90 0.42
Third Quarter 0.90 0.51
Fourth Quarter 1.32 0.54
2004
First Quarter 2.45 1.15
Second Quarter 2.54 1.59
Third Quarter 3.45 1.78
Fourth Quarter 4.30 2.75
Equity Compensation Plans
The table below provides information relating to the Company's equity
compensation plans as of December 31, 2004.
26
Number of securities
remaining available
Number of securities Weighted-average for future issuance
to be issued exercise price of under compensation
upon exercise of outstanding plans (excluding
outstanding options, options, securities reflected
Plan Category warrants and rights warrants and rights in first column)
- ------------- ------------------- ------------------- ----------------
Equity compensation plans
approved by security holders
Stock option plan 3,226,000 $ 1.48 3,825,721(a)
Restricted stock plan 820,850 N/A (b) -
Equity compensation plans
not approved by security holders 3,817,250 $ 2.17 (c)
--------- -----------
Total 7,864,100 $ 1.85(d) 3,825,721
========= ==== =========
(a) As of December 31 of each year, the number of shares of common stock
issuable under our stock option plan automatically increases so that
the number of shares of common stock issuable under the plan will be
equal to 10% of the total number of shares of common stock outstanding
on that date.
(b) The restricted shares vest 20% on the first anniversary, 20% on the
second anniversary and 60% on the third anniversary of the awards,
provided the holder remains employed by the Company.
(c) The equity compensation plan not approved by shareholders is comprised
of individual common stock option agreements issued to directors,
consultants and employees of the Company, as summarized below. The
common stock options vest between zero and two years of the date of
issue and expire within ten years of the vesting date. The exercise
prices of these options range from $1.00 per share to $3.70 per share.
Since these options are issued in individual compensation arrangements,
there are no options available under any plan for future issuance. The
material terms of these options are as follows:
Options Issued to: Number of Options Exercise Price Vesting Dates Expiration Dates
Employees 3,394,750 $1.00 - $3.15 2001 - 2003 2006 - 2008
Consultants 272,500 $3.00 - $3.70 2001 - 2003 2006 - 2008
Directors 150,000 $3.00 - $3.15 2001 - 2003 2006 - 2008
-------
Total Issued 3,817,250
=========
(d) Weighted average exercise price of options to purchase a total of 7,043,250
shares of common stock.
27
Securities Transactions
The Company's securities transactions during the year ended December 31, 2004
that were not registered under the Securities Act of 1933 are described as
follows:
On February 11, 2004 the Company completed the sale through a private placement
of 14,333,334 shares of its common stock to a group of accredited investors at a
price of $1.50 per share. Financing fees of $1,118,000 and $279,500 associated
with this transaction were paid to First Albany Capital and Pritchard Capital
Partners, respectively.
On October 20, 2004, the Company closed the private placement of $65 million in
aggregate principal amount of its 5.50% Convertible Senior Notes due 2011 (the
"Notes") pursuant to an Indenture dated as of October 20, 2004, between the
Company and Wells Fargo Bank, National Association, as trustee. The amount sold
consisted of $45 million principal amount originally offered plus the exercise
by the initial purchasers of their option to purchase an additional $20 million
principal amount. The Notes were sold only to qualified institutional buyers in
reliance on Rule 144A under the Securities Act of 1933. Financing fees of
$2,383,875 and $541,125 associated with this transaction were paid to JP Morgan
and First Albany Capital, respectively.
Immediately prior to and in connection with the closing of the offering of the
Notes, the holders of the Company's 8.00% Convertible Debentures converted the
entire $2.5 million principal amount thereof into 4,166,665 shares of common
stock in accordance with the terms of such Debentures. In connection with the
conversion, the Company paid the holders $270,247, representing 120% of the
future interest payments under the Debentures through November 15, 2005. The
issuance of these shares of common stock was exempt from registration under the
Securities Act of 1933 pursuant to Section 3(a)(9) thereof.
During 2004, certain holders of the Company's Series B Convertible Preferred
Stock ("Preferred Stock") converted 9,479 shares of Preferred Stock into
5,958,226 shares of common stock in accordance with the terms of such Preferred
Stock. The issuance of these shares of common stock was exempt from registration
under the Securities Act of 1933 pursuant to Section 3(a)(9) thereof.
During 2004, the Company granted an additional 1,410,000 options to purchase
shares of common stock to employees, directors and consultants of the Company,
at exercise prices ranging from $1.61 to $2.15 per share. The options vest 16
2/3% at the end of each four-month period after the issuance date and expire
within ten years from the grant date.
During the year ended December 31, 2004, the Company paid dividends to the
holders of its Preferred Stock consisting of 41,959 shares of common stock and
$61,960 in cash.
Unless otherwise noted, each of the above sales of securities by the Company
were exempt from registration under the Securities Act of 1933 pursuant to
Section 4(2) thereof, inasmuch as each such sale was conducted as a private
placement to a limited number of sophisticated buyers.
28
The aggregate net proceeds from the securities offerings during 2004 were
approximately $81,870,000. The proceeds were used for the development and
exploitation of the Company's Riverbend Project and for general corporate
purposes during 2004 and will be used for the same purposes during 2005.
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected financial data, derived from the
consolidated financial statements, regarding Gasco's financial position and
results of operations as the dates indicated. All information for periods prior
to March 30, 2001 represents the historical information of GPC because GPC was
considered the acquiring entity for accounting purposes.
As of and for the Year Ended December 31,
2004 2003 2002 2001 2000
---- ---- ---- ---- ----
Summary of Operations
Oil and gas revenue $3,123,888 $1,263,443 $ 164,508 $ 36,850 $ -
General & administrative expense 4,191,978 2,819,675 5,080,287 4,326,065 951,734
Net loss (4,205,830) (2,526,525) (5,649,682) (4,129,459) (843,261)
Net loss per share (0.07) (0.07) (0.16) (0.63) (0.06)
As of and for the Year Ended December 31,
2004 2003 2002 2001 2000
---- ---- ---- ---- ----
Balance Sheet
Working capital (deficit) $52,719,245 $1,192,246 $ (2,857,539) $11,860,584 $ (420,370)
Cash and cash equivalents 25,717,081 3,081,109 2,089,062 12,296,585 881,041
Oil and gas properties, net 50,820,383 28,470,917 24,760,149 9,152,740 1,991,290
Total assets 117,368,168 33,059,179 27,505,501 21,658,525 3,007,259
Long-term obligations 65,108,566 2,483,084 -
- -
Stockholders' equity 46,213,198 27,382,083 22,014,265 21,065,425 1,578,905
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward Looking Statements
Please refer to the section entitled "Cautionary Statement Regarding Forward
Looking Statements" under Item 1. For a discussion of factors which could affect
the outcome of forward looking statements used by the Company.
Overview
Gasco is a natural gas and petroleum exploitation and development company
engaged in locating and developing hydrocarbon prospects, primarily in the Rocky
Mountain region. The Company's mission is to enhance shareholder value by using
new technologies to generate and develop high-potential exploitation prospects
in this area. The Company's principal business is the acquisition of leasehold
interests in petroleum and natural gas rights, either directly or indirectly,
and the exploitation and development of properties subject to those leases.
29
The Company's corporate strategy is to grow through drilling projects. The
Company has been focusing its drilling efforts in the Riverbend Project located
in the Uinta Basin of northeastern Utah. The higher oil and gas prices during
2003 and 2004 due to factors such as inventory levels of gas storage, different
temperatures in parts of the country and changing demand in the United States,
combined with the continued instability in the Middle East have increased the
profitability of the Company's drilling projects in this area. The wells in the
Riverbend Project tend to have multiple productive zones. The increased drilling
activity resulting from the higher oil and gas prices has decreased the
availability of drilling rigs and experienced personnel in this area and may
continue to do so in the future.
The Company's capital budget for fiscal year 2004 was approximately $13 million
for the drilling, completion and pipeline connection of wells in the Riverbend
Project. In connection with Gasco's exploitation efforts, we have entered into
agreements with third party service providers and investors who contribute
approximately 70% of the cost of developing designated wells. During the twelve
months ended December 31, 2004, twelve wells were spudded in the Riverbend area,
nine of which were producing at year end and all of which are currently
producing. The Company increased its drilling activities in the Riverbend area
in April 2004 by adding a second drilling rig and added a third drilling rig,
which began drilling operations during December 2004.
During 2004, the Company completed the acquisition of additional interests in
six producing wells, 13,062 net acres and certain other assets located in the
Uinta Basin in Utah for net purchase price of approximately $2,400,000. The
Company also acquired approximately 16,000 net acres in the Riverbend area for
approximately $3,432,000.
The following table presents the Company's reserve information as of December 31
of each of last three years and production information for each of the three
years ended December 31, 2004. The Mcfe calculations assume a conversion of 6
Mcf's for each Bbl of oil.
For the Years Ended December 31,
-----------------------------------------
2004 2003 2002
------------ ------------- --------------
Natural gas production (Mcf) 505,967 257,035 66,444
Average sales price per Mcf $5.79 $4.69 $ 2.47
Year-end proved gas reserves (Mcf) 39,700,156 13,601,003 20,622,266
Oil production (Bbl) 5,080 1,988 -
Average sales price per Bbl $38.43 $28.52 -
Year-end proved oil reserves (Bbl) 274,074 100,987 141,652
Production (Mcfe) 536,447 268,963 66,444
Year-end proved reserves (Mcfe) 41,344,600 14,206,925 21,472,178
During 2004, the Company's oil and gas production increased by approximately
171% primarily due to the drilling projects and working interest acquisitions
discussed above. During 2004, on a combined basis, the oil and gas reserve
quantities have increased by approximately 191% primarily due to reserve
30
additions of 196% and purchases of reserves of 56% partially offset by
production of 4%, property sales of 21% and revisions of previous estimates of
36%. The previous estimate revisions relate to the write down of the reserves
related to two wells and their offset locations resulting from scale deposits in
the wellbores.
The Company's oil and gas production increased by approximately 300% during 2003
as compared with 2002 primarily due to the Company's completions, recompletions
and the installation of a compressor during 2003. During 2003, on a combined
basis, the oil and gas reserve quantities declined by approximately 34%
primarily due to normal decline curves of approximately 30%, property sales of
7%, annual production of 1% and revisions of previous estimates of 18% partially
offset by extensions and discoveries of 22%.
The Company's capital budget for 2005 is anticipated to be $38 million for the
drilling, completion and pipeline connection of wells in the Riverbend Project.
The Company plans to drill and complete 20 gross or 13 to 14 net wells in
Gasco's Riverbend Project in the Uinta Basin of Utah. Pending notification by
industry partners of their decision to participate in Gasco's proposed 2005
drilling program, the Company would expect to spend up to an additional $5
million to drill 10 gross and two net wells. The initial capital budget does not
include surface infrastructure costs associated with gathering system
improvements. The anticipated 2005 gathering system budget is $2 million to $3
million, or approximately $100,000 per well for compression and pipeline
hook-up. If we choose to proceed with the drilling of the 10 additional wells,
the Company would need to add a fourth drilling rig during the last six months
of the year. The overall increase in drilling activity has made it more
difficult for the Company to obtain additional drilling rigs as well as
experienced personnel, which may reduce the number of wells the Company is able
to drill during 2005. The Company anticipates an overall increase in its salary
expense because it will have to hire additional employees to manage the workload
associated with its operational plan for 2005. Management believes it has
sufficient capital for its 2005 operational budget, but will need to raise
additional capital for its capital budget in 2006. The Company will consider
several options for raising additional funds such as entering into a revolving
line of credit, selling securities, selling assets or farm-outs or similar type
arrangements. Any financing obtained through the sale of Gasco equity will
likely result in substantial dilution to the Company's stockholders.
Liquidity and Capital Resources
The following table summarizes the Company's sources and uses of cash for each
of the three years ended December 31, 2004, 2003 and 2002.
For the Year Ended December 31,
-----------------------------------------------------
2004 2003 2002
---- ---- ----
Net cash used in operations $ (905,369) $ (2,191,914) $ (1,390,306)
Net cash used in investing activities (48,336,958) (5,286,690) (14,541,197)
Net cash provided by financing activities 71,878,299 8,470,651 5,723,980
Net cash flow (deficit) 22,635,972 992,047 (10,207,523)
31
Cash used in operations during 2002 was primarily comprised of the Company's
general and administrative expenses partially offset by gas revenue from the
wells drilled throughout the year. The increase in cash used in operations
during 2003 was primarily due to the increase in revenue resulting from a 300%
increase in production due to the Company's drilling activity during 2002 and
2003, partially offset by a decrease in the changes in operating assets and
liabilities primarily due to the timing of the Company's operational activity.
Oil and gas production increased another 100% during 2004 as the Company
continued their drilling activity and completed the acquisition of additional
working interests in six wells resulting in a decrease in the cash used in
operations. General and administrative expenses decreased as well during 2003
due primarily to the Company's cost cutting measures, but increased during 2004
due to the Company's increase in drilling activity as well as its fund raising
projects during 2004. See further discussion under Results of Operations.
The Company's investing activities during 2003, and 2002 related primarily to
the Company's development and exploration activities. During 2002 the Company
acquired acreage for approximately $22,000,000 in cash and stock and the
remaining $11,000,000 was used to fund the Company's drilling projects. The
Company's unproved acquisitions during 2003 decreased to approximately $700,000
and related primarily to delay rentals and other leasehold costs. The remaining
$ 4,600,000 in property costs was spent on the Company's drilling projects in
the Riverbend Project. During 2004, the Company completed acquisitions of
acreage and additional working interests in producing wells for approximately
$5,800,000 and the remaining $19,936,066 in property costs was primarily spent
on the Company's drilling projects in the Riverbend Project. Additionally, the
Company invested $27,000,000 in short-term investments during 2004.
Historically, the Company has relied on the sale of equity capital and farm-outs
and other similar types of transactions to fund working capital, the acquisition
of its prospects and its drilling and development activities. The financing
activities in each of the years presented is comprised of the net proceeds from
the sale of equity in the Company, as further described below.
During 2004, the Company completed the sale through a private placement of
14,333,334 shares of its common stock to a group of accredited investors at a
price of $1.50 per share, receiving net proceeds of $20,070,000 and closed the
private placement of $65,000,000 in aggregate principal amount of its 5.50%
Convertible Senior Notes due 2011, receiving net proceeds of $61,793,000.
During 2003 the Company closed the sale of $2,500,000 of 8% Convertible
Debentures ("Debentures") in a private placement offering, sold through a
private placement, 11,052 shares of Series B Convertible Preferred Stock
("Preferred Stock") to a group of accredited investors, including members of
Gasco's management for $440 per share resulting in net proceeds of approximately
$4,797,000 and completed the sale through a private placement of 4,788,436
shares of its common stock to a group of accredited previous investors at a
selling price of $0.58 per common share for net proceeds of approximately
$2,765,000.
On August 14, 2002, the Company issued 6,500,000 shares of common stock for net
proceeds of approximately $6,000,000 in a private placement.
32
Capital Budget
In January 16, 2004 the Company entered into agreements, which were subsequently
amended during July 2004, with a group of industry providers (together, the
"Service Parties") to accelerate the development of Gasco's oil and gas
properties by drilling up to 50 wells in Gasco's Riverbend Project in Utah's
Uinta Basin. Gasco has agreed that the Service Parties will have the exclusive
right to provide their services in the development of the Riverbend acreage. The
agreement provides for the group to initially proceed with the first 10-well
bundle, which approximates one year of drilling with a single rig, with the
drilling of additional 10-well bundles being subject to the approval of the
group. The Company is currently using three drilling rigs and has commenced
drilling of the second 10-well bundle under this project. If the group agrees,
drilling may be accelerated using additional rigs. Gasco's 2004 capital budget
was approximately $13 million for the drilling, completion and pipeline
connection of wells in this area. Two of the drilling rigs are currently
drilling the second 10-well bundle. Under this agreement, the Company has agreed
to fund approximately 30% of the development costs of each of the wells drilled,
with the service providers providing drilling and completion services equivalent
to 45% of the total development costs and an additional capital partner
providing 25% of the total development costs. The service providers are not
required to expend more than a total of $13.5 million for development of a given
bundle. Furthermore, the service providers are not obligated to provide any
services unless each is satisfied that we will be able to meet our cash
expenditure requirements. The Company's interest in the production stream from
each 10-well bundle of wells, net of royalties, taxes and lease operating
expenses, is estimated to equal the proportion of the total well costs that we
fund.
To secure its obligations under the agreement described above, the Company has
pledged its interests in each of the wells in each bundle.
During the fourth quarter of 2004, the Service Parties agreed to proceed with
the second bundle of ten wells. The drilling of the second bundle commenced upon
completion of the first bundle. The Company and the Service Parties are
currently negotiating the third 10-well bundle which is anticipated to commence
during the last half of 2005.
During 2004, the Company completed the sale through a private placement of
14,333,334 shares of its common stock to a group of accredited investors at a
price of $1.50 per share for gross proceeds of $21,500,001 and closed the
private placement of $65,000,000 in aggregate principal amount of its 5.50%
Convertible Senior Notes due 2011. The proceeds from these sales are being used
for the development and exploitation of Gasco's Riverbend Project in the Uinta
Basin in Uintah County, Utah and for general corporate purposes.
The Company's use of the funds from this transaction and its cash on hand
included the following projects:
- The March 9, 2004 acquisition of additional interests in six producing
wells, 13,062 net acres and certain other assets located in the Uinta
Basin in Utah.
- The Company's planned expenditures for the drilling, completion and
pipeline connection of nine wells in this area.
- The completion of a gathering system within the Riverbend Area.
33
The Company's capital budget for 2005 is anticipated to be $38 million for the
drilling, completion and pipeline connection of 20 gross or 13 to 14 net wells
in Gasco's Riverbend Project in the Uinta Basin of Utah. Pending notification by
industry partners of their decision to participate in Gasco's proposed 2005
drilling program, the Company would expect to spend up to an additional $5
million to drill 10 gross and two net wells. The initial capital budget does not
include surface infrastructure costs associated with gathering system
improvements. The anticipated 2005 gathering system budget is $2 million to $3
million, or approximately $100,000 per well for compression and pipeline
hook-up. The Company plans to add a fourth drilling rig during the first six
months of the year.
Management believes it has sufficient capital for its 2005 operational budget,
but will need to raise additional capital for its capital budget in 2006. The
Company will consider several options for raising additional funds such as
entering into a revolving line of credit, selling securities, selling assets or
farm-outs or similar type arrangements. Any financing obtained through the sale
of Gasco equity will likely result in substantial dilution to the Company's
stockholders.
Schedule of Contractual Obligations
The following table summarizes the Company's obligations and commitments to make
future payments under its notes payable, operating leases, employment contracts
and consulting agreement for the periods specified as of December 31, 2004.
Payments due by Period
Contractual Obligations Total 1 year 2-3 years 4-5 years After 5 years
- ----------------------- ----- ------ --------- --------- -------------
Convertible Notes Principal
and Interest $89,180,903 $3,575,000 $7,150,000 $ 7,150,000 $ 71,305,903
Operating Lease - office space 462,424 85,796 164,172 187,862 24,594
Employment Contracts 509,167 470,000 39,167 - -
Consulting Agreement 130,000 120,000 10,000 - -
----------- ---------- ---------- ------------ --------- -
Total Contractual Cash
Obligations $ 90,282,494 $ 4,250,796 $7,363,339 $ 7,337,862 $71,330,497
============ =========== ========== =========== ===========
The Company current office lease expires on August 30, 2005. Subsequent to
December 31, 2004, the Company entered into a new lease which commences April 1,
2005 and terminates on March 31, 2010. The table above includes future
obligations that will exist as a result of the new lease.
The Company has not included asset retirement obligations as discussed in Note 2
of the accompanying financial statements, as the Company cannot determine with
accuracy the timing of such payments.
34
Critical Accounting Policies and Estimates
The preparation of the Company's consolidated financial statements in conformity
with generally accepted accounting principles in the United States requires
management to make assumptions and estimates that affect the reported amounts of
assets, liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. The
following is a summary of the significant accounting policies and related
estimates that affect the Company's financial disclosures.
Oil and Gas Reserves
Gasco follows the full cost method of accounting whereby all costs related to
the acquisition and development of oil and gas properties are capitalized into a
single cost center referred to as a full cost pool. Depletion of exploration and
development costs and depreciation of production equipment is computed using the
units of production method based upon estimated proved oil and gas reserves.
Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes may not exceed an
amount equal to the present value, discounted at 10%, of estimated future net
revenues from proved oil and gas reserves plus the cost, or estimated fair value
if lower, of unproved properties. Should capitalized costs exceed this ceiling,
an impairment would be recognized.
Estimated reserve quantities and future net cash flows have the most significant
impact on the Company because these reserve estimates are used in providing a
measure of the Company's overall value. These estimates are also used in the
quarterly calculations of depletion, depreciation and impairment of the
Company's proved properties.
Estimating accumulations of gas and oil is complex and is not exact because of
the numerous uncertainties inherent in the process. The process relies on
interpretations of available geological, geophysical, engineering and production
data. The extent, quality and reliability of this technical data can vary. The
process also requires certain economic assumptions, some of which are mandated
by the Securities and Exchange Commission ("SEC"), such as gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. The accuracy of a reserve estimate is a function of the quality and
quantity of available data; the interpretation of that data; the accuracy of
various mandated economic assumptions; and the judgment of the persons preparing
the estimate.
The most accurate method of determining proved reserve estimates is based upon a
decline analysis method, which consists of extrapolating future reservoir
pressure and production from historical pressure decline and production data.
The accuracy of the decline analysis method generally increases with the length
of the production history. Since most of the Company's wells have been producing
less than two years, their production history is relatively short, so other
(generally less accurate) methods such as volumetric analysis and analogy to the
production history of wells of other operators in the same reservoir were used
in conjunction with the decline analysis method to determine the Company's
estimates of proved reserves including developed producing, developed
35
non-producing and undeveloped. As the Company's wells are produced over time and
more data is available, the estimated proved reserves will be redetermined on an
annual basis and may be adjusted based on that data.
Actual future production, gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable gas and oil
reserves most likely will vary from the Company's estimates. Any significant
variance could materially affect the quantities and present value of the
Company's reserves. In addition, the Company may adjust estimates of proved
reserves to reflect production history, acquisitions, divestitures, ownership
interest revisions, results of exploration and development and prevailing gas
and oil prices. The Company's reserves may also be susceptible to drainage by
operators on adjacent properties.
Impairment of Long-lived Assets
The cost of the Company's unproved properties is withheld from the depletion
base as described above, until such a time as the properties are either
developed or abandoned. These properties are reviewed periodically for possible
impairment. During 2003, the Company's management reviewed the unproved property
located within the state of Wyoming and determined that it would not be
developing some of the acres that were not considered to be prospective. As a
result, the Company estimated the value of these acres for the purpose of
recording the related impairment. The impairment was estimated by calculating a
per acre value from the total unproved costs incurred for the Wyoming acreage
divided by the total net acres owned by the Company. This per acre estimate was
applied to the acres that the Company did not plan to develop to calculate the
impairment. A change in the estimated value of the acreage could have a material
impact on the total of the impairment recorded by the Company.
Revenue Recognition
The Company's revenue is derived from the sale of oil and gas production from
its producing wells. This revenue is recognized as income when the production is
produced and sold. The Company typically receives its payment for production
sold one to three months subsequent to the month the production is sold. For
this reason, the Company must estimate the revenue that has been earned but not
yet received by the Company as of the reporting date. The Company uses actual
production reports to estimate the quantities sold and the Questar Rocky
Mountain spot price less marketing and transportation adjustments to estimate
the price of the production. Variances between our estimates and the actual
amounts received are recorded in the month the payment is received.
Stock Based Compensation
The Company accounts for its stock-based compensation using the intrinsic value
recognition and measurement principles detailed in Accounting Principles Board's
Opinion No. 25 ("APB No. 25"). No stock-based compensation expense has been
reflected in the Company's financial statements for the options granted to its
36
employees as these options had exercise prices equal to or higher than the
market value of the underlying common stock on the date of grant. The Company
uses the Black-Scholes option valuation model to calculate the required
disclosures under SFAS 123. This model requires the Company to estimate a risk
free interest rate and the volatility of the Company's common stock price. The
use of a difference estimate for any one of these components could have a
material impact on the amount of calculated compensation expense.
Results of Operations
The following table presents information regarding the production volumes,
average sales prices received and average production costs associated with the
Company's sales of natural gas for the periods indicated.
For the Year Ended December 31,
-----------------------------------------------
2004 2003 2002
---- ---- ----
Natural gas production (Mcf) 505,967 257,035 66,444
Average sales price per Mcf $ 5.79 $ 4.69 $2.47
Oil production (Bbl) 5,080 1,988 -
Average sales price per Bbl $38.43 $28.52 -
2004 Compared to 2003
Oil and gas revenue increased $1,860,445 during 2004 compared with 2003 due to
an increase in gas production of 248,932 Mcf and an increase in oil production
of 3,092 bbls during 2004 combined with an increase in the average gas and oil
prices of $1.10 per Mcf and $9.91 per bbl during 2004. The increase in
production is primarily due to the Company's 2004 drilling and recompletion
activity as well as the acquisition of additional working interests in six wells
during March 2004.
The gathering income of $143,326 during the year ended December 31, 2004
represents the income earned from the Riverbend area pipeline that was
constructed by the Company during 2004.
Interest income increased $313,014 from 2003 to 2004 primarily due to higher
average cash and cash equivalent and short-term investment balances during 2004
relating primarily to proceeds from the Company's $65,000,000 Convertible Note
issuance during October 2004 and its $21,500,000 common stock offering during
February 2004.
General and administrative expense increased by $1,372,303 during 2004 as
compared with 2003, primarily due to the Company's increased operational
activity. The increase in these expenses is comprised of approximately $305,000
in salary expense due to the hiring of additional full-time employees and
employee and officer bonuses, approximately $280,000 in stock based compensation
primarily related to the Company's restricted stock issuance, approximately
$215,000 related to increased shareholder communication due to the Company's
expanded operational activity during 2004, approximately $245,000 in consulting
expenses due to the increased operational activity, approximately $185,000 in
37
audit and legal fees related to the property and financing transactions during
the year and approximately $140,000 of increased administrative expenses related
to the operations of the Company's corporate office resulting from the increased
operational activity and the increase number of consultants and employees during
2004. The remaining increase in general and administrative expenses is due to
the fluctuation in numerous other expenses, none of which are individually
significant.
Lease operating expense increased by $300,989, during 2004, primarily due to
increased operating costs and production taxes relating to the increased
production discussed above.
Gathering operation expense during 2004 relates to the operations of the
Company's pipeline in the Riverbend area that was constructed by the Company
during 2004.
Depletion, depreciation and amortization expense during 2004 is comprised of
$1,025,100 of depletion expense related to the Company's proved oil and gas
properties, $60,812 of depreciation expense related to the Company's equipment,
furniture, fixtures and other assets and $16,663 of accretion expense related
the Company's asset retirement obligation. The corresponding expense during 2003
consists of $480,000 of depletion expense, $61,128 of depreciation expense and
$11,795 of accretion expense. The increase in depletion expense during 2004 as
compared with 2003 is due primarily to the increase in production resulting from
the Company's increased drilling and completion activity as well as the property
acquisition discussed above.
Interest expense during 2004 consists of interest expense related to the
Company's outstanding Convertible Notes which were issued on October 20, 2004
and interest expense related to the Company's outstanding Debentures that were
converted into common stock in October 2004. The interest expense during 2003
consists of the interest incurred on an outstanding note payable that was repaid
during February 2004 as well as interest on the Company's outstanding
Debentures.
2003 Compared to 2002
Oil and gas revenue increased $1,098,935 during 2003 compared with 2002 due to
an increase in gas production from 66,444 Mcf during 2002 to 257,035 Mcf during
2003 combined with an increase in the average gas price from $2.47 during 2002
to $4.69 per Mcf during 2003. During 2003, the Company also produced 1,988 bbls
of oil at an average price of $28.52 per bbl. The increase in production was
primarily due to the Company's completion and recompletion activity during 2003
as well as the compressor installation discussed above which occurred during
February 2003.
Interest income decreased by 84% from 2002 to 2003 primarily due to lower
average cash and cash equivalent balances during 2003.
General and administrative expense decreased from $5,080,287 to $2,819,675
during 2003 as compared with 2002, primarily due to the Company's efforts to
decrease its overhead expenses. The $2,260,612 decrease in these expenses was
38
comprised of approximately $775,000 in salary reductions due to the
implementation, during January 2003, of a 36% annual reduction in the cash
component of the Company's senior management compensation, a $300,000 reduction
in compensation expense due to the one time payment of a bonus to an employee of
the Company, a $565,000 reduction in legal fees and $246,000 in accounting fees
as a result of fewer transaction related fees during 2003 and a $400,000
decrease in consulting fees that were incurred in connection with the 2002
property transactions discussed above.
Lease operating expense increased $217,469 during 2003 as compared with the
2002. The increase was due a greater number of producing wells during 2003
resulting from the Company's drilling activity during 2002 and 2003.
Depletion, depreciation and amortization expense during 2003 was comprised of
$480,000 of depletion expense related to the Company's proved oil and gas
properties, $61,128 of depreciation expense related to the Company's furniture,
fixtures and other assets and $11,795 of accretion expense related the Company's
asset retirement obligation. The corresponding expense during 2002 consisted of
$105,321 of depletion expense and $43,788 of depreciation expense. The increase
in depletion expense during 2003 as compared with 2002 was due primarily to the
increase in production discussed above.
Impairment expense during 2002 represented costs associated with a well drilled
in the Southwest Jonah field located in the Greater Green River Basin in
Sublette County, Wyoming. The well was plugged and abandoned during March of
2002. The Company recognized impairment expense of $541,125 associated with this
well during 2002 because the Company believed that the costs incurred for this
well exceeded the present value, discounted at 10%, of the future net revenues
from its proved oil and gas reserves.
Interest expense during 2003 represented the interest expense related to the
Company's outstanding Debentures.
The cumulative effect of change in accounting principle during 2003 represented
the Company's recognition of an asset retirement obligation in connection with
the adoption of SFAS 143 on January 1, 2003.
Recent Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which
is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No.
123(R) is effective for public companies for interim or annual periods beginning
after June 15, 2005, supersedes APB Opinion No. 25, Accounting for Stock Issued
to Employees, and amends SFAS No. 95, Statement of Cash Flows.
SFAS No. 123(R) requires all share-based payments to employees, including grants
of employee stock options, to be recognized in the income statement based on
their fair values. Pro-forma disclosure is no longer an alternative. The new
standard will be effective for the Company, beginning August 1, 2005. SFAS No.
123R permits companies to adopt its requirements using either a "modified
prospective" method, or a "modified retrospective" method. Under the "modified
39
prospective" method, compensation cost is recognized in the financial statements
beginning with the effective date, based on the requirements of SFAS No. 123R
for all share-based payments granted after that date, and based on the
requirements of SFAS No. 123 for all unvested awards granted prior to the
effective date of SFAS No. 123R. Under the "modified retrospective" method, the
requirements are the same as under the "modified prospective" method, but also
permits entities to restate financial statements of previous periods, either for
all prior periods presented or to the beginning of the fiscal year in which the
statement is adopted, based on previous pro forma disclosures made in accordance
with SFAS No. 123. The Company has not yet determined which of the methods it
will use upon adoption. The Company has not yet completed their evaluation but
expects the adoption SFAS No. 123(R) to have an effect on the financial
statements similar to the pro forma effects reported in the Stock Based
Compensation disclosure in Item 8. Note 2.
The FASB issued SFAS 153, Exchanges of Nonmonetary Assets, which changes the
guidance in APB Opinion 29, Accounting for Nonmonetary Transactions. This
Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges
of similar productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. SFAS
153 is effective during fiscal years beginning after June 15, 2005. The Company
does not believe the adoption of SFAS 153 will have a material impact on the
Company's financial statements.
In March 2004, the FASB issued consensus on EITF 03-6, "Participating Securities
and the Two-Class Method Under FASB Statement No. 128, Earnings Per Share,"
related to calculating earnings per share with respect to using the two-class
method for participating securities. This pronouncement is effective for all
periods after March 31, 2004, and requires prior periods to be restated. As, the
Company has incurred net losses in the current and prior periods, and as the
Company's preferred stock does not have a contractual obligation to share in the
losses of the Company, the adoption of EITF 03-6 had no impact on the Company's
financial condition, or its results of operations. The Securities and Exchange
Commission issued Staff Accounting Bulletin (SAB) No. 106 in September 2004
regarding the application of SFAS No. 143, "Accounting for Asset Retirement
Obligations," for oil and gas producing entities that follow the full cost
accounting method. SAB No. 106, states that after adoption of SFAS No. 143, the
future cash outflows associated with settling asset retirement obligations that
have been accrued on the balance sheet should be excluded from the present value
of estimated future net cash flows used for the full cost ceiling test
calculation. The Company has calculated its ceiling test computation in this
manner since the adoption of SFAS No. 143 and, therefore, SAB No. 106 had no
effect on the Company's financial statements, effective in the fourth quarter of
2004.
40
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risk relates to changes in the pricing applicable
to the sales of gas production in the Uinta Basin of northeastern Utah and the
Greater Green River Basin of west central Wyoming. This risk will become more
significant to the Company as more wells are drilled and begin producing in
these areas. Although the Company is not using derivatives at this time to
mitigate the risk of adverse changes in commodity prices, it may consider using
them in the future. The Company does not have any obligations that are subject
to variable rates of interest.
41
ITEM 8 - FINANCIAL STATEMENTS
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firms 43-44
Consolidated Balance Sheets at December 31, 2004 and 2003 45-46
Consolidated Statements of Operations for the Years Ended
December 31, 2004, 2003 and 2002 47
Consolidated Statements of Stockholders' Equity for the Years
Ended December 31, 2004, 2003 and 2002 48
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2004, 2003 and 2002 49
Notes to Consolidated Financial Statements 50-74
42
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Gasco Energy, Inc.:
We have audited the consolidated balance sheet of Gasco Energy, Inc. and
subsidiaries (the "Company") as of December 31, 2004, and the related
consolidated statements of operations, stockholders' equity and cash flows for
the year ended December 31, 2004. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provided 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 the Company as of
December 31, 2004, and the results of their operations and their cash flows the
year ended December 31, 2004, in conformity with U.S. generally accepted
accounting principles.
/s/ Hein & Associates LLP
Denver, Colorado
March 15, 2005
43
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Gasco Energy, Inc.:
We have audited the consolidated balance sheet of Gasco Energy, Inc. (the
"Company") and its subsidiaries as of December 31, 2003, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the two years in the period ended December 31, 2003. 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 the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. 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, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31,
2003, and the results of their operations and their cash flows for each of the
two years in the period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, in 2003 the
Company adopted Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations."
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
March 25, 2004
44
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
December 31,
---------------------------------------
2004 2003
ASSETS
CURRENT ASSETS
Cash and cash equivalents $25,717,081 $ 3,081,109
Restricted investment 3,535,055 250,000
Short-term investments 27,000,000 -
Accounts receivable 1,045,044 499,363
Inventory 1,009,914 -
Prepaid expenses 458,555 555,786
----------- ---------
Total 58,765,649 4,386,258
----------- ---------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests 29,811,483 16,386,252
Unproved mineral interests 18,449,330 13,212,039
Gathering assets 2,469,580 -
Equipment 89,900 -
Furniture, fixtures and other 158,590 166,051
---------- ----------
Total 50,978,883 29,764,342
---------- ----------
Less accumulated depreciation, depletion and amortization (2,247,032) (1,232,634)
----------- -----------
Total 48,731,851 28,531,708
----------- ----------
NON-CURRENT ASSETS
Restricted investment 6,778,040 -
Deferred financing costs 3,092,628 141,213
--------- -------
9,870,668 141,213
------------- -----------
TOTAL ASSETS $ 117,368,168 $ 33,059,179
============= ============
The accompanying notes are an integral part of the
consolidated financial statements.
45
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
December 31,
---------------------------------------
2004 2003
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,447,149 $ 2,016,979
Revenue payable 334,765 243,513
Advances from joint interest owners 891,999 -
Accrued interest 695,139 -
Accrued expenses 2,677,352 933,520
---------- ---------
Total 6,046,404 3,194,012
---------- ---------
NONCURRENT LIABILITES
5.5% Convertible Senior Notes 65,000,000 -
8% Convertible Debentures, net of unamortized discount of $159,722 - 2,340,278
Asset retirement obligation 108,566 142,806
------- ---------
Total 65,108,566 2,483,084
---------- ---------
COMMITMENTS AND CONTINGENCIES (NOTES 5, 13, 16)
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock - $.001 par value; 20,000 shares
authorized; 2,255 shares issued and outstanding with a liquidation
preference of $992,200 in 2004 and 11,734 shares issued and
outstanding with a liquidation preference of $5,162,960 in 2003 2 12
Common stock - $.0001 par value; 100,000,000 shares authorized;
70,590,909 shares issued and 70,517,209 outstanding in 2004;
45,675,936 shares issued and 45,602,236 shares outstanding in 2003 7,059 4,568
Additional paid in capital 76,346,463 52,979,325
Deferred compensation (512,440) (179,766)
Accumulated deficit (29,497,591) (25,291,761)
Less cost of treasury stock of 73,700 common shares (130,295) (130,295)
------------ ------------
Total 46,213,198 27,382,083
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 117,368,168 $ 33,059,179
=============- ============
The accompanying notes are an integral part of the
consolidated financial statements.
46
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31,
-------------------------------------------------
2004 2003 2002
REVENUES
Gas $ 2,928,689 $ 1,206,741 $ 164,508
Oil 195,199 56,702
-
Gathering 143,326 - -
Interest income 325,001 11,987 76,140
--------- --------- --------
Total 3,592,215 1,275,430 240,648
--------- --------- --------
OPERATING EXPENSES
General and administrative 4,191,978 2,819,675 5,080,287
Lease operating 638,267 337,278 119,809
Gathering operations 267,450 - -
Depletion, depreciation, amortization and asset retirement
liability accretion 1,102,575 552,923 149,109
Impairment - - 541,125
Interest expense 1,597,775 82,392
--------- ---------- ---------
Total 7,798,045 3,792,268 5,890,330
--------- ---------- ---------
LOSS BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE (4,205,830) (2,516,838) (5,649,682)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE (9,687) -
---------- ---------- ----------
NET LOSS (4,205,830) (2,526,525) (5,649,682)
Preferred stock dividends (140,853) (304,172) -
----------- ----------- ------------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (4,346,683) $ (2,830,697) $(5,649,682)
============= ============= ============
PER COMMON SHARE DATA - BASIC AND DILUTED:
Loss before cumulative effect of change in accounting principle $ (0.07) $ (0.07) $ (0.16)
Cumulative effect of change in accounting principle - - -
----------- -------- -----
NET LOSS PER COMMON SHARE - BASIC AND DILUTED $ (0.07) $ (0.07) $ (0.16)
========= ========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED 63,194,223 41,262,778 36,439,074
============= ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
47
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Additional
Preferred Stock Common Stock Paid in Deferred Accumulated Treasury
Shares Value Shares Value Capital Compensation Deficit Stock Total
Balance, January 1, 2001 1,000 1 27,252,500 2,725 38,569,923 (261,375) (17,115,554) (130,295) 21,065,425
Conversion of preferred
shares to common shares 4,760,000 476 (476) -
Issuance of common shares
for acreage 9,500,000 950 18,524,050 18,525,000
Amortization of deferred
compensation expense 208,542 208,542
Redemption of preferred
and common stock (1,000) (1) (6,250,000) (625) (16,708,374) (16,709,000)
Issuance of common stock 6,500,000 650 5,973,330 5,973,980
Repurchase of common stock (1,400,000) (140) (1,399,860) (1,400,000)
Net loss - (5,649,682) - (5,649,682)
------ ----- ----------- ------ ---------- --------- ---------- ---------- -----------
Balance, December 31, 2002 40,362,500 4,036 44,958,593 (52,833)(22,765,236) (130,295) 22,014,265
Issuance of preferred stock 11,052 11 4,797,398 4,797,409
Issuance of common stock 4,888,436 490 2,808,719 2,809,209
Issuance of restricted stock 425,000 42 250,708 (221,250) 29,500
Amortization of deferred
compensation 94,317 94,317
Beneficial conversion feature 166,667 166,667
Dividends paid 682 1 (4,092) (4,091)
Net loss (2,526,525) (2,526,525)
Other - - 1,332 - - 1,332
---- -- ---------- ----- --------- ------- ------------ ---------- -----------
Balance December 31, 2003 11,734 12 45,675,936 4,568 $52,979,325 $(179,766)(25,291,761) $(130,295) $ 27,382,083
Conversion of preferred
shares to common shares (9,479) (10) 5,958,226 596 (586) -
Issuance of common stock 14,714,787 1,472 20,786,130 (748,157) 20,039,445
Conversion of Convertible
Debentures 4,166,665 416 2,503,376 2,503,792
Exercise of common stock
options 33,336 3 33,333 33,336
Amortization of deferred
compensation 415,483 415,483
Proceeds from 16b violation 106,858 106,858
Dividends paid 41,959 4 (61,973) (61,969)
Net loss - - - - - - (4,205,830) (4,205,830)
----- --- --------- ------ --------- --------- ----------- ---------- ----------
Balance December 31, 2004 2,255 $ 2 70,590,909 $ 7,059 $76,346,463 $(512,440)$(29,497,591) $(130,295) $ 46,213,198
===== === ========== ======= =========== ========== ============ ========== =========
The accompanying notes are an integral part of the
consolidated financial statements.
48
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
------------------------------------------------------
2004 2003 2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $(4,205,830) $(2,526,525) $(5,649,682)
Adjustment to reconcile net loss to net cash used in
operating activities
Depreciation, depletion and impairment expense 1,085,912 541,128 690,234
Accretion of asset retirement obligation 16,663 11,795 -
Amortization of deferred compensation 415,483 94,317 208,542
Amortization of beneficial conversion feature 161,514 6,945 -
Amortization of offering costs 294,993 7,758 -
Cumulative effect of change in accounting principle - 9,687 -
Changes in operating assets and liabilities:
Accounts receivable (545,681) (403,219) (63,397)
Inventory (1,009,914) - -
Prepaid expenses 59,992 (320,059) (74,139)
Accounts payable (600,723) 164,303 1,303,823
Revenue payable 91,252 185,215 58,298
Advances from joint interest owners 891,999 - -
Accrued interest 695,139 - -
Accrued expenses 1,743,832 36,741 2,136,015
--------- --------- -------------
Net cash used in operating activities (905,369) (2,191,914) (1,390,306)
--------- ----------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (64,053) (3,264) (103,342)
Cash paid for acquisitions, development and exploration (25,736,066) (5,283,426) (14,437,855)
Proceeds from property sales 4,463,161 - -
Investment in short-term investments (27,000,000) - -
------------ ---------- -----------
Net cash used in investing activities (48,336,958) (5,286,690) (14,541,197)
------------ --------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of convertible notes 65,000,000 - -
Cash designated as restricted (10,313,095) (250,000) (250,000)
Cash undesignated as restricted 250,000 250,000 -
Preferred dividends (61,973) (4,092) -
Exercise of options to purchase common stock 33,336 - -
Proceeds from sale of preferred stock - 4,862,840 -
Proceeds from sale of common stock 21,500,001 2,777,292 6,500,000
Proceeds from sale of convertible debentures - 2,500,000 -
Cash paid for offering costs (4,636,828) (266,721) (526,020)
Repayment of note payable - (1,400,000) -
Proceeds from 16b violation 106,858 1,332 -
------------ ---------- ---------
Net cash provided by financing activities 71,878,299 8,470,651 5,723,980
------------ --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 22,635,972 992,047 (10,207,523)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 3,081,109 2,089,062 12,296,585
---------- ---------- ----------
END OF PERIOD $25,717,081 $ 3,081,109 $ 2,089,062
=========== =========== ===========
The accompanying notes are an integral part of the consolidated financial
statements.
49
GASCO ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
NOTE 1 - ORGANIZATION
Gasco Energy, Inc. ("Gasco" or the "Company") is an independent energy company
engaged in the exploration, development, and acquisition and production of crude
oil and natural gas in the western United States.
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements include Gasco and its wholly
owned subsidiaries. All significant intercompany transactions have been
eliminated.
Cash and Cash Equivalents
All highly liquid investments purchased with an initial maturity of three months
or less are considered to be cash equivalents.
Restricted Investment
The restricted investment balance as of December 31, 2004 represents funds
invested in U.S. government securities in an amount sufficient to provide for
the payment of the first six semi-annual scheduled interest payments on the
Company's outstanding 5.5% Convertible Notes ("Notes"), as further described in
Note 7. The current portion of restricted cash represents the interest payments
that are due within the first year and the non-current portion represents the
interest payments that are due after one year. This investment will be held
until maturity and the cost of the investment approximates its market value. The
restricted cash balance at December 31, 2003 consisted of a $250,000 escrow
agreement in connection with one of its drilling projects. The funds held in
escrow were released during May 2004.
Short-term Investments
The Company's short-term investments consist primarily of preferred auction rate
securities, which are classified as available-for-sale. These securities are
stated at fair value based on quoted market prices.
Inventory
Inventory consists of pipe and tubular goods intended to be used in the
Company's oil and gas operations, and is stated at the lower of cost or market
using the average cost valuation method.
50
Property, Plant and Equipment
The Company follows the full cost method of accounting whereby all costs related
to the acquisition and development of oil and gas properties are capitalized
into a single cost center ("full cost pool"). Such costs include lease
acquisition costs, geological and geophysical expenses, overhead directly
related to exploration and development activities and costs of drilling both
productive and non-productive wells. Proceeds from property sales are generally
credited to the full cost pool without gain or loss recognition unless such a
sale would significantly alter the relationship between capitalized costs and
the proved reserves attributable to these costs. A significant alteration would
typically involve a sale of 25% or more of the proved reserves related to a
single full cost pool.
Depletion of exploration and development costs and depreciation of production
equipment is computed using the units of production method based upon estimated
proved oil and gas reserves. The costs of unproved properties are withheld from
the depletion base until such time as they are either developed or abandoned.
The properties are reviewed periodically for impairment. Total well costs are
transferred to the depletable pool even when multiple targeted zones have not
been fully evaluated. For depletion and depreciation purposes, relative volumes
of oil and gas production and reserves are converted at the energy equivalent
rate of six thousand cubic feet of natural gas to one barrel of crude oil.
Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes may not exceed an
amount equal to the present value, discounted at 10%, of estimated future net
revenues from proved oil and gas reserves plus the cost, or estimated fair
value, if lower of unproved properties. Should capitalized costs exceed this
ceiling, an impairment is recognized. The present value of estimated future net
revenues is computed by applying current prices of oil and gas to estimated
future production of proved oil and gas reserves as of period-end, less
estimated future expenditures to be incurred in developing and producing the
proved reserves assuming the continuation of existing economic conditions.
Gathering Assets
Gathering assets as of December 31, 2004 represent the costs associated with the
construction of the Company's pipeline and gathering system located in the
Riverbend area of Utah. These assets are being depreciated on a units of
production method based upon estimated proved oil and gas reserves of the wells
that are expected to flow through the gathering system.
Impairment of Long-lived Assets
The Company's unproved properties are evaluated periodically for the possibility
of potential impairment. During 2003, the Company recorded an impairment of its
Wyoming acreage of $1,725,000 by reclassifying these costs into the full cost
pool. The impairment represented the cost of certain of the Company's acreage
that expired in 2004 that it did not consider to be prospective. Other than oil
and gas properties, the Company has no other long-lived assets and to date has
not recognized any impairment losses.
51
Deferred Financing Costs
Deferred financing costs as of December 31, 2004 consist of the costs associated
with the Company's issuance of $65,000,000 of Notes during October 2004, as
further described in Note 7. These costs are being amortized over the seven-year
life of the Notes. The December 31, 2003 balance represents the offering costs
associated with the Company's issuance of $2,500,000 in 8% Convertible
Debentures ("Debentures"), further described in Note 7. These costs were being
amortized over the five-year life of the Debentures until they were converted
into common stock during October 2004. The Company recorded amortization expense
of $294,993 and $7,758 related to these costs during the years ended December
31, 2004 and 2003, respectively.
Asset Retirement Obligation
In June 2001 the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations, " which required that the fair value of a liability for
an asset retirement obligation be recognized in the period in which it was
incurred if a reasonable estimate of fair value could be made. The associated
asset retirement costs are capitalized as part of the carrying amount of the
long-lived asset. The asset retirement liability will be allocated to operating
expense by using a systematic and rational method. The Company adopted this
statement as of January 1, 2003 and recorded a net asset of $139,247, a related
liability of $148,934 (using a 9% discount rate and a 2% inflation rate) and a
cumulative effect of change in accounting principle on prior years of $9,687.
The information below reconciles the value of the asset retirement obligation
from the date the liability was recorded.
Year Ended December 31,
2004 2003
Balance beginning of period $142,806 $ 148,934
Liabilities incurred 29,394 -
Liabilities settled (25,188) -
Revisions in estimated cash flows (55,109) (17,923)
Accretion expense 16,663 11,795
-------- ------
Balance end of period $ 108,566 $ 142,806
========== =========
The revisions in estimated cash flows is primarily the result of the Company's
decision to revise the life of the producing wells from twenty years to thirty
years based upon the drilling and production results in the area.
The following schedules present, on a pro forma basis, the asset retirement
obligation, the net loss, net loss per share amounts as if the provisions of
SFAS No. 143 had been applied during all the periods presented. The pro forma
information for the year ended December 31, 2004 is the same as the actual
information reported.
52
As of December 31,
2002
Asset Retirement Obligation $ 148,934
For the Year Ended December 31,
-----------------------------------------------
2003 2002
---- ----
Net Loss
As reported $ (2,526,525) $ (5,649,682)
Pro forma (2,516,838) (5,652,438)
Net Loss per Common
Share
As reported $(0.07) $(0.16)
Pro forma (0.07) (0.16)
Revenue Recognition
Oil and gas revenue is recognized as income when the oil or gas is produced and
sold.
Computation of Net Loss per Share
Basic net loss per share is computed by dividing net loss attributable to the
common stockholders by the weighted average number of common shares outstanding
during the reporting period. The shares of restricted common stock granted to
certain officers, directors and employees of the Company are included in the
computation only after the shares become fully vested. Diluted net income per
common share includes the potential dilution that could occur upon exercise of
the options to acquire common stock computed using the treasury stock method
which assumes that the increase in the number of shares is reduced by the number
of shares which could have been repurchased by the Company with the proceeds
from the exercise of the options (which were assumed to have been made at the
average market price of the common shares during the reporting period). The
Series B Convertible Preferred Stock ("Preferred Stock") and the outstanding
common stock options have not been included in the computation of diluted net
loss per share during all periods because their inclusion would have been
anti-dilutive.
As of December 31, 2004, we had 70,517,209 shares of common stock issued and
outstanding. As of such date, there were 8,460,678 shares of common stock
issuable upon exercise of outstanding options and conversion of our Series B
Convertible Preferred Stock. Additional options may be granted to purchase
3,825,721 shares of common stock under our stock option plan and an additional
179,150 shares of common stock are issuable under our restricted stock plan. As
of December 31, 2004, and as of December 31 of each succeeding year, the number
of shares of common stock issuable under our stock option plan automatically
increases so that the total number of shares of common stock issuable under such
plan is equal to 10% of the total number of shares of common stock outstanding
on such date.
53
Assuming all of the notes are converted at the applicable conversion prices, the
number of shares of our common stock outstanding would increase by approximately
16,250,000 shares to approximately 86,767,209 shares (this number assumes no
exercise of the options or rights described above or conversion of the Series B
Convertible Preferred Stock).
In March 2004, the FASB issued consensus on EITF 03-6, "Participating Securities
and the Two-Class Method Under FASB Statement No. 128, Earnings Per Share,"
related to calculating earnings per share with respect to using the two-class
method for participating securities. This pronouncement is effective for all
periods after March 31, 2004, and requires prior periods to be restated. As the
Company has incurred net losses in the current and prior periods, and as the
Company's preferred stock does not have a contractual obligation to share in the
losses of the Company, the adoption of EITF 03-6 had no impact on the Company's
financial condition, or its results of operations.
Significant Customers
Although the Company sells the majority of its production to a few purchasers,
there are numerous other purchasers in the areas in which Gasco sells it
production; therefore, the loss of its significant customers would not adversely
affect the Company's operations. For the years ended December 31, 2004, 2003 and
2002, purchases by the following company exceeded 10% of the total oil and gas
revenues of the Company.
For the Year Ended December 31,
------------------------------------------------
2004 2003 2002
---- ---- ----
ConocoPhillips Company 93% 93% 98%
Use of Estimates
The preparation of the financial statements for the Company in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
The Company's financial statements are based on a number of significant
estimates, including oil and gas reserve quantities which are the basis for the
calculation of depreciation, depletion and impairment of oil and gas properties,
and timing and costs associated with its retirement obligations.
Other Comprehensive Income
The Company's short-term investments are classified as available for sale, and
are carried on the balance sheet at market value. Unrealized gains and losses,
net of deferred income taxes, are generally reported as other comprehensive
income and as an adjustment to stockholders equity. If a decline in market value
54
below cost is assessed as being other than temporary, such impairment is
included in the determination of net income. The Company's available-for-sale
securities are readily marketable and available for use in its operations should
the need arise. Therefore, the Company has classified such securities as current
assets. As of December 31, 2004, the market value of the Company's short-term
investments was equal to its cost basis and therefore, there were no unrealized
gains and losses included in other comprehensive income during 2004.
The Company does not have any other items of other comprehensive income for the
years ended December 31, 2004, 2003 and 2002. Therefore, total comprehensive
income (loss) is the same as net income (loss) for these periods.
Income Taxes
The Company uses the liability method of accounting for income taxes under which
deferred tax assets and liabilities are recognized for the future tax
consequences of temporary differences between the accounting bases and the tax
bases of the Company's assets and liabilities. The deferred tax assets and
liabilities are computed using enacted tax rates in effect for the year in which
the temporary differences are expected to reverse.
Stock Based Compensation
The Company accounts for its stock-based compensation using Accounting
Principles Board's Opinion No. 25 ("APB No. 25") and related interpretations.
Under APB 25, compensation expense is recognized for stock options with an
exercise price that is less than the market price on the grant date of the
option. The Company has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation
("SFAS 123") for the stock options granted to the employees and directors of the
Company. Accordingly, no compensation cost has been recognized for these
options. Had compensation expense for the options granted been determined based
on the fair value at the grant date for the options, consistent with the
provisions of SFAS 123, the Company's pro forma net loss and net loss per share
for the years ended December 31, 2004, 2003 and 2002 would have been increased
to the pro forma amounts indicated below:
For the Year Ended December 31,
2004 2003 2002
---- ---- ----
Net loss attributable to common shareholders:
As reported $ (4,205,830) $ (2,830,697) $ (5,649,682)
Add: Stock-base employee compensation
included in net loss (a) 312,243 41,484 -
Less: Stock based employee compensation
determined under the fair value based method 757,294 742,211 1,709,226
----------- ----------- ----------
Pro forma $(4,650,881) $(3,531,424) $(7,358,908)
============ ============ ============
Net loss per common share:
As reported $ (0.07) $ (0.07) $ (0.16)
======== ======== ========
Pro forma $ (0.07) $ (0.09) $ (0.20)
======== ======== ========
55
(a) Represents the compensation expense associated with the Company's
restricted stock awards, further described in Note 8.
The fair value of the common stock options granted during 2004, 2003 and 2002,
for disclosure purposes was estimated on the grant dates using the Black Scholes
Pricing Model and the following assumptions.
For the Year Ended December 31,
------------------------------------------
2004 2003 2002
---- ---- ----
Expected dividend yield -- -- --
Expected price volatility 79 - 87% 82% 90%
Risk-free interest rate 3.2 - 3.9% 2.9% 3.5% - 4.1%
Expected life of options 5 years 5 years 5 years
Concentration of Credit Risk
The Company's cash equivalents and short-term investments are exposed to
concentrations of credit risk. The Company manages and controls this risk by
investing these funds with major financial institutions.
The Company's receivables are comprised of oil and gas revenue receivables and
joint interest billings receivable. The amounts are due from a limited number of
entities. Therefore, the collectability is dependent upon the general economic
conditions of the few purchasers and joint interest owners. The receivables are
not collateralized. However, to date the Company has had minimal bad debts.
Fair Value
The Company's financial instruments including cash and cash equivalents,
restricted cash, short-term investments, accounts receivable and accounts
payable are carried at cost, which approximates fair value due to the short-term
maturity of these instruments. The Company's 5.5% Convertible Notes are recorded
at cost, and the fair value is disclosed in Note 7. Since considerable judgment
is required to develop estimates of fair value, the estimates provided are not
necessarily indicative of the amounts the Company could realize upon the
purchase or refinancing of such instruments.
Recent Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which
is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No.
123(R) is effective for public companies for interim or annual periods beginning
after June 15, 2005, supersedes APB Opinion No. 25, Accounting for Stock Issued
to Employees, and amends SFAS No. 95, Statement of Cash Flows.
56
SFAS No. 123(R) requires all share-based payments to employees, including grants
of employee stock options, to be recognized in the income statement based on
their fair values. Pro-forma disclosure is no longer an alternative. The new
standard will be effective for the Company, beginning August 1, 2005. SFAS No.
123R permits companies to adopt its requirements using either a "modified
prospective" method, or a "modified retrospective" method. Under the "modified
prospective" method, compensation cost is recognized in the financial statements
beginning with the effective date, based on the requirements of SFAS No. 123R
for all share-based payments granted after that date, and based on the
requirements of SFAS No. 123 for all unvested awards granted prior to the
effective date of SFAS No. 123R. Under the "modified retrospective" method, the
requirements are the same as under the "modified prospective" method, but also
permits entities to restate financial statements of previous periods, either for
all prior periods presented or to the beginning of the fiscal year in which the
statement is adopted, based on previous pro forma disclosures made in accordance
with SFAS No. 123. The Company has not yet determined which of the methods it
will use upon adoption. The Company has not yet completed their evaluation but
expects the adoption SFAS No. 123(R) to have an effect on the financial
statements similar to the pro-forma effects reported in the Stock Based
Compensation disclosure above. In March 2004, the FASB issued consensus on EITF
03-6, "Participating Securities and the Two-Class Method Under FASB Statement
No. 128, Earnings Per Share," related to calculating earnings per share with
respect to using the two-class method for participating securities. This
pronouncement is effective for all periods after March 31, 2004, and requires
prior periods to be restated. As, the Company has incurred net losses in the
current and prior periods, and as the Company's preferred stock does not have a
contractual obligation to share in the losses of the Company, the adoption of
EITF 03-6 had no impact on the Company's financial condition, or its results of
operations. The Securities and Exchange Commission issued Staff Accounting
Bulletin (SAB) No. 106 in September 2004 regarding the application of SFAS No.
143, "Accounting for Asset Retirement Obligations," for oil and gas producing
entities that follow the full cost accounting method. SAB No. 106, states that
after adoption of SFAS No. 143, the future cash outflows associated with
settling asset retirement obligations that have been accrued on the balance
sheet should be excluded from the present value of estimated future net cash
flows used for the full cost ceiling test calculation. The Company has
calculated its ceiling test computation in this manner since the adoption of
SFAS No. 143 and, therefore, SAB No. 106 had no effect on the Company's
financial statements, effective in the fourth quarter of 2004.
Reclassifications
Certain reclassifications have been made to prior years' amounts to conform to
the classifications used in the current year.
57
NOTE 3 - OIL AND GAS PROPERTY
The following table presents information regarding the Company's net costs
incurred in the purchase of proved and unproved properties and in exploration
and development activities:
For the Years Ended December 31,
----------------------------------------------------
2004 2003 2002
-------------------------------- -------------------
Property acquisition costs:
Unproved $ 5,021,126 $667,557 $22,324,547
Proved 723,901 -- --
Exploration costs (a) 216,165 396,967 3,319,124
Development costs 17,501,716 4,218,902 7,319,184
----------- --------- ----------
Total excluding asset retirement obligation 23,462,908 5,283,426 32,962,855
========== ========= ==========
Total including asset retirement obligation $23,398,559 $ 5,398,678 $ 32,962,855
=========== =========== ============
(a) Includes seismic data acquisitions of $850,000 during twelve months ended
December 31, 2002.
Depletion and impairment expense related to proved properties per equivalent Mcf
of production for the years ended December 31, 2004, 2003 and 2002 was $2.06,
$2.06 and $9.73, respectively.
During the first quarter of 2002, the Company drilled a well in the Southwest
Jonah field located in the Greater Green River Basin in Sublette County,
Wyoming. The well was drilled to a total depth of 11,000 feet. The well
encountered natural gas, however not of sufficient quantities to be deemed
economic. The well was plugged and abandoned during March of 2002. The costs
associated with this well of $541,125, were charged to impairment expense during
the year ended December 31, 2002 because the Company believed that the total
costs for this well exceeded the present value, discounted at 10%, of the future
net revenues from its total proved oil and gas reserves at the time the well was
plugged and abandoned.
At December 31, the Company's unproved properties consist of leasehold costs in
the following areas:
2004 2003
---- ----
Utah $ 5,950,861 $ 963,530
Wyoming 12,312,742 12,089,104
California 185,727 159,405
----------- -----------
$18,449,330 $13,212,039
=========== ===========
During 2003, the Company impaired certain of its unproved acreage in Wyoming by
reclassifying $1,725,000 of costs associated with this acreage into the full
cost pool. The impairment represents the cost of certain of the Company's
acreage that the Company no longer considerd prospective. These costs became
subject to amortization during the fourth quarter of 2003.
58
The following table represents the additions, net of impairments and transfers
to proved oil and gas properties, to unproved acreage from inception through
December 31, 2004:
Net Acquisition
Years Costs
2001 and earlier $ 9,152,740
2002 4,831,796
2003 (772,497)
2004 5,237,291
-----------
Unproved Mineral Interest as of
December 31, 2004 $ 18,449,330
============
The Company's drilling activities are located primarily in the Riverbend Area of
Utah, and the Company plans to drill approximately 20 wells in this area during
2005. The Company continues to consider several options for its Wyoming and
California acreage such as the farm-out of some of its acreage and other similar
type transactions.
NOTE 4 - PROPERTY ACQUISITIONS
On March 9, 2004 the Company completed the acquisition of additional working
interests in six producing wells, 13,062 net acres and gathering system assets
located in the Uinta Basin in Utah for approximately $3,175,000. During May 2004
an unrelated third party exercised its right to purchase 25% of the acquired
properties at the acquisition price,which had the effect of reducing the
purchase price to approximately $2,400,000 and reducing the Company's interest
in the acquisition to 75%. The effective date of the acquisition was January 1,
2004; however, the net revenue from the producing wells during the period from
January 1, 2004 through March 9, 2004 was recorded as a reduction to the
purchase price.
The following unaudited pro forma consolidated results of operations are
presented as if the acquisition occurred on January 1, 2002.
For the Year Ended December 31,
2004 2003 2002
---- ---- ----
Revenue $ 3,742,586 $2,363,046 $801,884
Loss before cumulative effect of
change in accounting principle (4,136,633) (1,918,451) (5,465,693)
Net Loss (4,136,633) (1,928,138) (5,465,693)
Net Loss Attributable to Common
Stockholders (4,277,486) (2,232,310) (5,545,693)
Net Loss per Common Share - Basic
and Diluted $(0.07) $ (0.05) $ (0.15)
During December 2004, the Company completed the acquisition of additional
acreage in the Riverbend Area for a purchase price of approximately $3,432,000.
Pursuant to an existing contract, an unrelated third party had the right to
59
purchase 25% of the acquired acreage at a price equal to 25% of the purchase
price. This right was exercised by the third party during January 2005 which had
the effect of reducing the Company's purchase price of the acquisition to
approximately $2,575,000.
NOTE 5 - SERVICE PARTIES' AGREEMENT
On January 20, 2004 the Company entered into agreements, which were subsequently
amended in July 2004, with a group of industry providers (together, the "Service
Parties") to accelerate the development of Gasco's oil and gas properties by
drilling up to 50 wells in Gasco's Riverbend Project in Utah's Uinta Basin.
Gasco has agreed that the Service Parties, which includes Schlumberger Oilfield
Services, will have the exclusive right to provide their services in the
development of the Riverbend acreage. The agreement initially provided for the
group to develop a bundle of 10 wells during 2004 using a single drilling rig.
Thereafter, drilling was accelerated using an additional rig. A third party
investor was subsequently added as a party to these agreements. Gasco's 2004
capital budget was approximately $13 million for the drilling, completion and
pipeline connection of wells in this area. During the fourth quarter of 2004,
the Service Parties and the investor agreed to proceed with the second bundle of
ten wells. The drilling of the second bundle commenced in December upon
completion of the first bundle.
General Terms of the Amended Agreement:
o Contract Area consists of Gasco's leasehold position in portions of
Carbon, Duchesne and Uintah Counties, Utah.
o Gasco is permitted to independently develop its acreage subject to
certain limitations and provisions of the agreement.
o Schlumberger will coordinate most operational activities under Gasco's
direction as operator of record.
o Gasco has elected to fund approximately 30% of each of the wells
drilled under this agreement. Gasco's interest in the production
stream from a bundle, net of royalties, taxes and lease operating
expenses, is estimated to equal the proportion of the total well costs
that it funds.
o The Service Parties and the investor have undertaken to provide
approximately 45% and 25%, respectively, of the costs of each project
bundle in return for a net profits interest in each bundle
proportionate to their costs contributed.
To secure its obligations under the agreement, described above, the Company has
pledged its interests in each of the wells in each bundle.
NOTE 6 - PROPERTY DIVESTITURES
In connection with the Service Parties agreements, described in Note 5, the
Company completed a disposition of net profits interests of between 18.75% and
25% in the 8 wells that have been drilled in the Riverbend area in Utah during
60
2004 for total cash consideration of $4,314,984, net of adjustments and
commissions. The purpose of this transaction was to allow third party investors
to become a party to the Company's service provider arrangements. The
consideration paid to the Company in this transaction represented the share of
such investor's development costs of the 8 wells completed as of such date.
These investors have the opportunity to continue to participate in the
development program under the service provider arrangement by funding 25% of
future development costs.
The cash received by the Company consisted of $4,314,984, which represented the
purchase price for the transaction of $4,790,387 less adjustments of $327,227
for net revenue minus lease operating expense for the properties from June 2004
and $148,176, representing a commission to the purchasers' financial advisor,
which the Company agreed to pay.
The following unaudited pro forma consolidated results of operations are
presented as if the disposition occurred on January 1, 2003. The results for the
year ended December 31, 2002 are the same as the actual results because the
wells were not drilled until 2003.
For the Year Ended December 31,
2004 2003
---- ----
Revenue $ 3,139,967 $1,222,848
Loss before cumulative effect of
change in accounting principle (4,688,491) (2,605,703)
Net Loss (4,688,491) (2,615,390)
Net Loss Attributable to Common
Stockholders (4,829,344) (2,919,562)
Net Loss per Common Share - Basic
and Diluted $(0.08) $ (0.07)
During October 2003, the Company completed a transaction whereby it settled an
outstanding amount owed of $1,606,982 to an oilservice provider arising from
drilling and completion expenditures on five Gasco-operated wells, by paying the
provider $400,000 in cash and conveying to the provider a portion of its
interests in two Riverbend wells. Subsequent to the transaction, the Company
retained a 30% working interest in the two subject wells and ownership in the
remaining three wells is unchanged.
NOTE 7 - CONVERTIBLE NOTES
On October 20, 2004 (the "Issue Date"), the Company closed the private placement
of $65,000,000 in aggregate principal amount of its 5.50% Convertible Senior
Notes due 2011 (the "Notes") pursuant to an Indenture dated as of October 20,
2004 (the "Indenture"), between the Company and Wells Fargo Bank, National
Association, as trustee. The amount sold consisted of $45,000,000 principal
amount originally offered plus the exercise by the initial purchasers of their
option to purchase an additional $20,000,000 principal amount. The Notes were
sold only to qualified institutional buyers in reliance on Rule 144A under the
Securities Act of 1933.
61
The Notes are convertible into Company Common Stock, $.0001 par value per share
("Common Stock"), at any time prior to maturity at a conversion rate of 250
shares of Common Stock per $1,000 principal amount of Notes (equivalent to a
conversion price of $4.00 per share), which is subject to certain anti-dilution
adjustments.
Interest on the Notes accrues from October 20, 2004 or the most recent interest
payment date, and is payable in cash semi-annually in arrears on April 5th and
October 5th of each year, commencing on April 5, 2005. Interest is payable to
holders of record on March 15th and September 15th immediately preceding the
related interest payment dates, and will be computed on the basis of a 360-day
year consisting of twelve 30-day months.
The Company, at its option, may at any time on or after October 10, 2009, in
whole, and from time to time in part, redeem the Notes on not less than 20 nor
more than 60 days' prior notice mailed to the holders of the Notes, at a
redemption price equal to 100% of the principal amount of Notes to be redeemed
plus any accrued and unpaid interest to but not including the redemption date,
if the closing price of the Common Stock has exceeded 130% of the conversion
price for at least 20 trading days in any consecutive 30 trading-day period.
Upon a "change of control" (as defined in the Indenture), each holder of Notes
can require the Company to repurchase all of that holder's notes 45 days after
the Company gives notice of the change of control, at a repurchase price equal
to 100% of the principal amount of Notes to be repurchased plus accrued and
unpaid interest to, but not including, the repurchase date, plus a make-whole
premium under certain circumstances described in the Indenture.
Pursuant to a Collateral Pledge and Security Agreement dated October 20, 2004,
between the Company and Wells Fargo Bank, National Association, as Trustee and
Collateral Agent (the "Pledge Agreement"), the Company has pledged U. S.
government securities in an amount sufficient upon receipt of scheduled
principal and interest payments with respect to such securities to provide for
the payment of the first six scheduled interest payments on the Notes.
$10,313,095 of the net proceeds from the offering of Notes was used to acquire
such U. S. government securities, which is recorded as restricted cash in the
accompanying financial statements.
The Notes are unsecured (except as described above) and unsubordinated
obligations of the Company and rank on a parity (except as described above) in
right of payment with all of the Company's existing and future unsecured and
unsubordinated indebtedness. The Notes effectively rank junior to any future
secured indebtedness and junior to the Company's subsidiaries' liabilities. The
Indenture does not contain any financial covenants or any restrictions on the
payment of dividends, the repurchase of the Company's securities or the
incurrence of indebtedness.
Upon a continuing event of default, the trustee or the holders of 25% principal
amount of a series of Notes may declare the Notes immediately due and payable,
except that a default resulting from the Company's entry into a bankruptcy,
insolvency or reorganization will automatically cause all Notes under the
Indenture to become due and payable.
62
Based on the market price of the Company's common stock as of December 31, 2004,
the fair value of the Notes is $69,225,000.
The Notes are due in 2011 and therefore do not have any maturities within the
next five years.
Immediately prior to and in connection with the closing of the offering of the
Notes, the holders of the Company's Debentures converted the entire $2,500,000
principal amount thereof into 4,166,665 shares of Common Stock. In connection
with the conversion, the Company paid the holders $270,247, representing 120% of
the future interest payments under the Debentures through November 15, 2005.
NOTE 8 - STOCKHOLDERS' EQUITY
The Company's capital stock as of December 31, 2004 and 2003 consists of
100,000,000 authorized shares of common stock, par value $0.0001 per share, and
20,000 authorized shares of Series B Convertible Preferred stock, par value
$0.001 per share.
Series B Convertible Preferred Stock - As of December 31, 2004, Gasco had 2,255
shares of Series B Preferred Stock ("Preferred Stock") issued and outstanding.
The Preferred Stock is entitled to receive dividends at the rate of 7% per annum
payable semi-annually in cash, additional shares of Preferred Stock or shares of
common stock at the Company's option. The conversion price of the Preferred
Stock is $0.70 per common share, which was greater than the market price on the
issuance date, making each share of Preferred Stock convertible into
approximately 629 shares of Gasco common stock. Shares of the Preferred Stock
are convertible into Gasco common shares at any time at the holder's election.
Gasco may redeem shares of the Preferred Stock at a price of 105% of the
purchase price at any time after February 10, 2006. The Preferred Stock votes as
a class on issues that affect the Preferred Stockholder's interests and votes
with shares of common stock on all other issues on an as-converted basis.
Additionally, the holders of the Preferred Stock exercised their right to elect
one member to Gasco's board of directors during March 2003.
During the year ended December 31, 2004, the Company paid dividends to the
holders of its Preferred Stock consisting of 41,959 shares of common stock and
$61,973 in cash.
Common Stock - Gasco has 70,590,909 shares of Common Stock issued and 70,517,209
shares outstanding as of December 31, 2004. The common shareholders are entitled
to one vote per share on all matters to be voted on by the shareholders;
however, there are no cumulative voting rights. Additionally, the holders of the
Preferred Stock are entitled to vote with shares of common stock on an
as-converted basis. The common shareholders are entitled to dividends and other
distributions as may be declared by the board of directors. Upon liquidation or
dissolution, the common shareholders will be entitled to share ratably in the
distribution of all assets remaining available for distribution after
satisfaction of all liabilities and payment of the liquidation preference of any
outstanding preferred stock.
The Company's common stock equity transactions during 2004 and 2003 are
described as follows:
63
On February 11, 2004 the Company completed the sale through a private placement
of 14,333,334 shares of its common stock to a group of accredited investors at a
price of $1.50 per share. Proceeds to the Company, net of fees and expenses were
approximately $20,070,000. The proceeds from this sale are being used for
general corporate purposes including the acquisition of oil and natural gas
assets and the development and exploitation of Gasco's Riverbend Project in the
Uinta Basin in Uintah County, Utah.
During 2004, certain holders of the Company's Preferred Stock converted 9,479
shares of Preferred Stock into 5,958,226 shares of common stock.
On June 14, 2004, the Company's Board of Directors approved the issuance of
395,850 shares of common stock, under the Gasco Energy, Inc. Amended and
Restated 2003 Restricted Stock Plan ("Restricted Stock Plan"), to certain of the
Company's officers and employees. The restricted shares vest 20% on the first
anniversary, 20% on the second anniversary and 60% on the third anniversary of
the awards. The shares fully vest upon certain events, such as a change in
control of the Company, expiration of the individual's employment agreement and
termination by the Company of the individual's employment without cause. Any
unvested shares are forfeited upon termination of employment for any other
reason.
The compensation expense related to the restricted stock was measured on June
14, 2004 using the trading price of the Company's common stock, the date the
restricted shares were issued and is amortized over the three-year vesting
period. The shares of restricted stock are considered issued and outstanding at
the date of grant and are included in shares outstanding for the purposes of
computing diluted earnings per share. The Company had 735,850 unvested shares of
restricted stock outstanding as of December 31, 2004 and the compensation
expense related to these shares during year ended December 31, 2004 was
$312,243.
During the third quarter of 2004, upon vesting of a previous restricted stock
grant, an officer of Gasco returned 14,397 of his shares to the Company in
satisfaction of his personal tax liability that resulted from the vesting of the
restricted stock. The Company canceled these shares during the fourth quarter of
2004.
On October 23, 2003 the Company completed the sale through a private placement
of 4,788,436 shares of its common stock to a group of accredited previous
investors. The selling price of $0.58 per common share was determined by taking
97 percent of the 20-day average closing price of the Company's common stock for
the period ending October 17, 2003, and resulted in total proceeds of
approximately $2,780,000. The expenses associated with this transaction were
approximately $15,000. The Company plans to use the proceeds from this
transaction to develop and exploit its core-area Riverbend Project in the Uinta
Basin in Utah and for its ongoing operations.
On August 12, 2003, the Company's Board of Directors approved the issuance of
425,000 shares of common stock, under the Gasco Energy, Inc. 2003 Restricted
Stock Plan ("Restricted Stock Plan"), to certain of the Company's officers and
directors. The restricted shares vest 20% on the first anniversary, 20% on the
64
second anniversary and 60% on the third anniversary of the awards. The shares
fully vest upon certain events, such as a change in control of the Company,
expiration of the individual's employment agreement and termination by the
Company of the individual's employment without cause. Any unvested shares are
forfeited upon termination of employment for any other reason.
The compensation expense related to the restricted stock was measured on
September 18, 2003, the date the Restricted Stock Plan was approved by the
Company's stockholders and is amortized over the three-year vesting period. The
shares of restricted stock are considered issued and outstanding at the date of
grant and are included in shares outstanding for the purposes of computing
diluted earnings per share. The Company had 425,000 unvested shares of
restricted stock outstanding as of December 31, 2003 and the compensation
expense related to these shares during the year ended December 31, 2003 was
$41,484.
NOTE 9 - STOCK OPTIONS
During 2004, the Company granted an additional 1,410,000 options to purchase
shares of common stock to employees, directors and consultants of the Company,
at exercise prices ranging from $1.61 to $2.15 per share. The options vest 16
2/3% at the end of each four-month period after the issuance date and expire
within ten years from the grant date.
During 2003, the Company granted an additional 1,658,000 options to purchase
shares of common stock to employees and directors of the Company, at an exercise
price of $1.00 per share. The options vest 16 2/3% at the end of each four-month
period after the issuance date. Additionally, the Company cancelled 2,346,664
options to purchase shares of common stock during the first quarter of 2003. The
exercise price of the cancelled options ranged from $1.95 to $3.15 per share.
None of the 1,658,000 options granted during 2003 were issued to the individuals
whose options were cancelled.
As of December 31, 2004 options to purchase an aggregate 7,043,250 shares of the
Company's common stock were outstanding. These options were granted during 2004,
2003, 2002 and 2001 to the Company's employees, directors and consultants at
exercise prices ranging from $1.00 to $3.70 per share. The options vest at
varying schedules within two years of their grant date and expire within ten
years from the grant date. The aggregate fair market value of options,
determined using the Black Scholes Pricing Model, granted to consultants and an
officer of the Company, of $73,705, $52,833, and $208,542 was charged to
operations during the years ended December 31, 2004, 2003 and 2002,
respectively.
A summary of the options granted to purchase common stock and the changes
therein during the years ended December 31, 2004, 2003 and 2002 is presented
below.
65
2004 2003 2002
---- ----- ----
Weighted Weighted Weighted
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Options Price Options Price Options Price
------- ----- ------- ----- ------- -----
Outstanding at beginning of year 5,666,586 $ 2.07 6,355,250 $ 2.17 6,392,750 $ 2.23
Granted 1,410,000 1.98 1,658,000 1.00 500,000 1.80
Exercised (33,336) 1.00 - -
Cancelled 2.18 (2,346,664) 2.18 (537,500) 2.56
--------- ---- ----------- ---- --------- ----
Outstanding at end of year 7,043,250 $ 1.85 5,666,586 $ 1.83 6,355,250 $ 2.17
========= ====== ========= ====== ========= ======
Exercisable at December 31, 5,624,417 $ 1.42 4,476,586 $ 2.07 6,027,085 $ 2.06
========= ====== ========= ====== ========= ======
Weighted average fair value of options granted $ 1.28 $ 0.45 $ 1.37
====== ====== ======
Weighted average remaining contractual life of options
outstanding as of December 31, 2004 7.1 years
===
The following table presents additional information related to the options
outstanding as of December 31, 2004.
Exercise Number of Weighted Average
Price per Number of Shares Shares Remaining Contractual
Share Outstanding Exercisable Life (years)
----- ----------- ---------- -------
$1.00 2,558,000 2,298,333 8.1
1.58 150,000 150,000 3.3
1.61 100,000 33,334 9.1
1.73 100,000 100,000 3.2
1.80 50,000 50,000 6.7
1.92 735,000 122,500 9.6
2.00 1,451,000 1,326,000 8.1
2.15 425,000 70,000 9.6
2.20 8,000 8,000 2.9
3.00 650,000 650,000 5.6
3.10 82,500 82,500 1.8
3.15 613,750 613,750 1.8
3.70 120,000 120,000 1.4
--------- -------- ----
Total 7,043,250 5,624,417 7.1
========= ========= ===
NOTE 10 - STATEMENT OF CASH FLOWS
During the year ended December 31, 2004, the Company's non-cash investing and
financing activities consisted of the following transactions:
66
Conversion of $2,500,000 of Debentures into 4,166,665 shares of common
stock.
Recognition of an asset retirement obligation for the plugging and
abandonment costs related to the Company's oil and gas properties valued at
$29,394.
Reduction in the asset retirement obligation of $25,188 representing the
sale of certain property interests discussed above and a reduction of
$55,109 representing a revision to the Company's asset retirement
obligation.
Conversion of 9,479 shares of Preferred Stock into 5,958,226 shares of
common stock.
Issuance of 41,959 shares of common stock in payment of the June 30, 2004
Preferred Stock dividend.
Issuance of 395,850 shares of restricted common stock to certain of the
Company's employees.
Write - off of fully depreciated furniture and fixtures of $71,514.
The following transactions represent the non-cash investing and financing
activities of the Company during the year ended December 31, 2003.
Recognition of an asset retirement obligation for the plugging and
abandonment costs related to the Company's oil and gas properties valued at
$148,934.
Issuance of 682 shares of Preferred Stock in payment of the June 30, and
December 31, 2003 Preferred Stock dividends.
Issuance of 425,000 shares of restricted common stock to certain of the
Company's officers and directors and the issuance of 100,000 shares of
common stock as compensation to a former employee.
Assignment of property interests in two wells in settlement of $1,206,982
in accounts payable and $17,923 in the asset retirement obligation.
During the year ended December 31, 2002, the Company's non-cash investing and
financing activities consisted of the following transactions:
Conversion of 500 shares of Series A Preferred stock into 4,750,000 shares
of common stock.
Issuance of 9,500,000 shares of common stock, valued at $18,525,000 in
exchange for oil and gas properties.
67
Repurchase of 500 shares of Series A Preferred stock and 6,250,000 shares
of common stock in exchange for an undivided 25% working interest in the
Company's undeveloped acreage valued at $16,709,000.
Repurchase of 1,400,000 shares of common stock in exchange for a promissory
note.
Noncash stock offering costs of $250,000 incurred in connection with
redeemable common stock.
Cash paid for interest was $ 463,769 and $82,392 for the years ended December
31, 2004 and 2003, respectively. There was no cash paid for interest during the
year ended December 21, 2002 and there was no cash paid for income taxes in any
of the years ended December 31, 2004, 2003 and 2002.
NOTE 11 - INCOME TAXES
A provision (benefit) for income taxes for the years ended December 31, 2004,
2003 and 2002 consists of the following:
2004 2003 2002
---- ---- ----
Current taxes:
Federal $ - $ - $ -
State - - -
Deferred taxes:
Federal (1,371,000) (2,556,837) (74,128)
State (157,580) (285,004) (68,422)
Less: valuation allowance 1,528,580 2,841,841 142,550
--------- --------- -------
Net income tax provision (benefit) $ - $ - $ -
======== ======== ======
A reconciliation of the provision (benefit) for income taxes computed at the
statutory rate to the provision for income taxes as shown in the financial
statements of operations for the years ended December 31, 2004, 2003 and 2002 is
summarized below:
2004 2002 2001
---- ---- ----
Tax provision (benefit) at federal statutory rate $ (1,429,982) $ (859,019) $ (1,920,892)
State taxes, net of federal tax effects (104,032) (188,102) (45,159)
Valuation adjustment on assets distributed in
stock redemption - - 1,798,941
Prior year tax return permanent true-up - (1,798,941) -
Other Permanent items 5,434 4,221 24,560
Valuation allowance 1,528,580 2,841,841 142,550
--------- ---------- -------
Net income tax provision (benefit) $ - $ - $ -
========== ========== ===========
68
The components of the deferred tax assets and liabilities as of December 31,
2004 and 2003 are as follows:
2004 2003
---- ----
Deferred tax assets:
Federal and state net operating loss carryovers $ 7,415,121 $4,576,075
Oil and gas property 133,530 1,272,043
Deferred compensation 362,029 284,805
------- ---------
Total deferred tax assets 7,910,680 6,132,923
Less: valuation allowance (6,935,384) (5,406,804)
----------- -----------
975,296 726,119
Deferred tax liabilities:
Other property, plant & equipment 758,796 318,777
Other 216,500 407,342
------- -------
Total deferred tax liabilities 975,296 726,119
------- -------
Net deferred tax asset $ - $ -
======= =======
The Company has a $19,622,107 net operating loss carryover for federal income
tax purposes and a $15,342,165 net operating loss carryover for state income tax
purposes as of December 31, 2004. The net operating losses may offset against
taxable income through the year ended December 31, 2024. A portion of the net
operating loss carryovers begins expiring in 2019. The Company provided a
valuation allowance against its deferred tax asset of $6,935,384 and $5,406,804
as of December 31, 2004 and 2003, respectively, since it believes that it is
more likely than not that the net deferred tax assets will not be fully utilized
on future income tax returns.
NOTE 12 - RELATED PARTY TRANSACTIONS
On October 11, 2004, the Board of Directors of Gasco, other than Mr. Erickson
and Mr. Bruner, approved a transaction pursuant to which Marc Bruner, the
chairman of Gasco's Board of Directors, and Mark Erickson, a director and
President and Chief Executive Officer of Gasco, will transfer to Gasco their
rights to receive certain overriding royalty interests in its properties in
exchange for the grant to each of them of options to purchase 100,000 shares of
Gasco common stock at the market price on the date of grant. Messrs. Bruner and
Erickson subsequently agreed to transfer such rights to Gasco for no options or
other consideration.
For each individual, these interests range between .06% and 0.6% of Gasco's
working interest in certain of its Utah and Wyoming properties. Gasco will also
agree to convey equivalent royalty interests to Mr. Bruner and Mr. Erickson, or
either of them, in the event that it sells any of the property subject to the
royalty interests, upon certain change of control events or upon the involuntary
termination of either individual. Mr. Bruner and Mr. Erickson acquired these
rights under a Trust Termination and Distribution Agreement, dated December 31,
2002, with respect to the Pannonian Employee Royalty Trust ("Royalty Trust").
69
The Royalty Trust had been established by Pannonian Energy, Inc. ("Pannonian")
prior to Pannonian becoming a wholly owned subsidiary of Gasco, to provide
additional compensation to the employees and founding directors of Pannonian,
which included Mr. Bruner and Mr. Erickson, in the form of oil and gas
interests. The terms of the Trust Termination and Distribution Agreement
("Termination Agreement") required Gasco to assign to the participants of the
Royalty Trust overriding royalty interests that arise out of the production of
oil and gas from certain properties as a result of future drilling. The
transaction was reviewed and approved by Gasco's Audit Committee and was signed
by Mr. Erickson and Mr. Bruner on December 23, 2004.
During May 2004, the Company's Board of Directors authorized the payment of
approximately $65,000 to the chairman of the Gasco Board of Directors as
reimbursement of legal fees paid by the chairman for legal services provided to
the Company.
During the year ended December 31, 2003 a clerical error was made in the payroll
process, which caused the president and chief executive officer of the Company,
Mark Erickson, to be overpaid by $55,000 during 2003, and $9,196 during the
first quarter of 2004. The error was discovered during February 2004, and Mr.
Erickson made restitution as soon as possible thereafter. Since the repayment
was made as soon as possible, no interest was charged and Mr. Erickson owes no
further amounts to the Company. The overpayment of $55,000 was included in the
accounts receivable balance of the accompanying financial statements as of
December 31, 2003.
During the each of years ended December 31, 2004, 2003 and 2002, the Company
paid $120,000 in consulting fees to a company owned by a director of Gasco. The
Company is committed to pay $120,000 per year in consulting fees to this company
through January 31, 2006. Another director of the Company earned consulting fees
of $16,000 from the Company during the year ended December 31, 2002.
During the year ended December 31, 2002, the Company paid $110,266 in consulting
fees to an unrelated third party. The obligation to pay these fees was a joint
and several liability of Gasco and a Company of which two of Gasco's directors
have a combined 66.67% ownership.
An officer of the Company, who retired effectively December 31, 2002, was an
employee of and owned a less than 1% interest in an entity from which Gasco
purchased acreage in Utah and Wyoming during 2001 and 2002. Additionally, the
Company recorded a payable to this officer of $213,000 as of December 31, 2002
representing a bonus of $150,000 and severance payments of $63,000. These
amounts were paid to this officer in full during the year ended December 31,
2003.
Certain of the Company's directors and officers have working and/or overriding
royalty interests in oil and gas properties in which the Company has an
interest. It is expected that the directors and officers may participate with
the Company in future projects. All participation by directors and officers will
continue to be approved by the disinterested members of the Company's Board of
Directors.
70
NOTE 13 - COMMITMENTS
The Company currently leases approximately 3,255 square feet of office space in
Englewood, Colorado for approximately $46,000 per year under a lease, which
terminates on August 30, 2005. Subsequent to December 31, 2004, as a result of
the Company's growth, the Company entered into a new lease for approximately
6,234 square feet of office space which commences April 1, 2005. The lease
terminates on March 31, 2010 and the average rent for this space over the life
of the lease is approximately $86,500 per year. The Company believes that this
new space will meet its needs for the next five years. The following table shows
the annual rentals per year for the life of the lease.
Year Ending December 31, Annual Rentals
2005 $ 85,796
2006 79,125
2007 85,047
2008 90,970
2009 96,892
Thereafter 24,594
------
$462,424
========
Rent expense for the years ending December 31, 2004, 2003 and 2002 was $52,822,
$56,970 and $42,055, respectively.
As is customary in the oil and gas industry, the Company may at times have
commitments in place to reserve or earn certain acreage positions or wells. If
the Company does not pay such commitments, the acreage positions or wells may be
lost.
The Company has entered into employment agreements with three key officers
through January 31, 2006. These agreements were revised during the first quarter
of 2003 to reduce the total compensation for the officers covered by the
employment agreements from $560,000 per annum to $470,000 per annum. The
agreements contain clauses regarding termination and demotion of the officer
that would require payment of an amount ranging from one times annual
compensation to up to approximately five times annual compensation plus a cash
payment from $250,000 to $500,000. Included in the employment agreements is a
bonus calculation for each of the covered officers totaling 2.125% of a defined
cash flow figure based on net after tax earnings adjusted for certain expenses.
NOTE 14 - EMPLOYEE BENEFIT PLANS
The Company adopted a 401(k) profit sharing plan (the "Plan") in October 2001,
available to employees who meet the Plan's eligibility requirements. The Plan is
a defined contribution plan. The Company may make discretionary contributions to
the Plan and is required to contribute 3% of the participating employee's
compensation to the Plan. The contributions made by the Company totaled $36,225,
71
$32,708 and $41,726 during the years ended December 31, 2004, 2003 and 2002,
respectively.
NOTE 15 - SELECTED QUARTERLY INFORMATION (Unaudited)
The following represents selected quarterly financial information for the years
ended December 31, 2004 and 2003.
2004 For the Quarter Ended
----------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
Gross revenue $751,518 $ 777,155 $ 817,325 $921,216
Net revenue from oil and
gas operations 590,450 521,411 638,084 611,552
Net loss (544,086) (720,981) (540,411) (2,400,352) a
Net loss per share
basic and diluted (0.01) (0.01) (0.01) (0.04)
a - The increase in the Company's net loss during the fourth quarter as compared
with the previous quarters is primarily due to the additional interest expense
related to the conversion of the Debentures of approximately $555,000, the
interest expense accrued on the Notes during the fourth quarter of approximately
$700,000 and the increased amortization expense related to the offering costs
related to the issuance of the Notes of approximately $115,000. The remaining
increase is due to higher general and administrative costs due to the increased
operational activity and increased depletion expense resulting from the increase
in the number of producing wells.
2003 For the Quarter Ended
---------------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
Gross revenue $158,850 $499,527 $ 277,101 $327,965
Net revenue from oil
and gas operations 92,402 389,091 173,017 271,655
Net loss (747,465) (508,492) (634,209) (636,359)
Net loss per share
basic and diluted (0.02) (0.02) (0.02) (0.01)
NOTE 16 - LITIGATION
On June 9, 2003, Pannonian Energy Inc. ("Pannonian"), a wholly-owned subsidiary
of the Company was named as a defendant in a lawsuit filed in the United States
District Court of Midland County, Texas. On July 15, 2003, Gasco was also named
as defendant in the same lawsuit. The plaintiffs, Burlington Resources Oil & Gas
Company LP by BROG GP Inc. its sole General Partner ("Burlington Resources")
claimed that Pannonian and Gasco owed them $1,007,894 in unpaid invoices. During
March 2004, the Company repaid $900,723 of this liability and during July the
Company made a final payment of $100,000 in settlement of this matter. Orders to
dismiss both cases with prejudice were filed on July 10, 2004.
72
NOTE 17 - SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
The following reserve quantity and future net cash flow information for the
Company represents proved reserves located in the United States. The reserves as
of December 31, 2004 and 2003 have been estimated by Netherland, Sewell and
Associates, Inc., independent petroleum engineers. The reserves as of December
31, 2002 were estimated by James R. Stell, independent petroleum engineer. The
determination of oil and gas reserves is based on estimates, which are highly
complex and interpretive. The estimates are subject to continuing change as
additional information becomes available.
The standardized measure of discounted future net cash flows is prepared under
the guidelines set forth by the Securities and Exchange Commission (SEC) that
require the calculation to be performed using year-end oil and gas prices. The
oil and gas prices used as of December 31, 2004 and 2003 were $42.25 per bbl of
oil and $5.56 per Mcf of gas and $29.69 per bbl of oil, and $5.89 per mcf of
gas, respectively. Future production costs are based on year-end costs and
include severance taxes. Each property that is operated by the Company is also
charged with field-level overhead in the reserve calculation. The present value
of future cash inflows is based on a 10% discount rate. No consideration has
been given to future income taxes as of December 31, 2004, 2003 and 2002,
because the tax basis of the Company's properties and net operating loss
carryforwards exceed future net cash flows in each of the years presented.
Reserve Quantities
Gas Oil
Mcf Bbls
Proved Reserves:
Balance, December 31, 2002 20,622,266 141,652
Extensions and discoveries 4,446,547 36,288
Revisions of previous estimates (a) (9,752,505) (66,455)
Sales of reserves in place (1,458,270) (8,500)
Purchases of reserves in place -- --
Production (257,035) (1,998)
----------- --------
Balance, December 31, 2003 13,601,003 100,987
Extensions and discoveries 26,788,308 168,451
Revisions of previous estimates (b) (4,940,340) (28,898)
Sales of reserves in place (2,879,772) (23,712)
Purchases of reserves in place 7,636,924 62,326
Production (505,967) (5,080)
--------- --------
Balance, December 31, 2004 39,700,156 274,074
========== ========
Proved Developed Reserves
Balance, December 31, 2004 3,916,089 39,103
=========== ==========
Balance, December 31, 2003 2,937,388 24,818
=========== ==========
Balance, December 31, 2002 5,889,981 34,493
=========== ==========
73
(a) The revisions of previous estimates during 2003 was due primarily to a
failed re-completion on one of the Company's wells, which resulted in a
reduction in the reserves associated with the producing wellbore
location and the loss of the surrounding proved undeveloped offset
locations.
(b) The revisions of previous estimates during 2004 relate to the write
down of the reserves related to two wells and their offset locations
resulting from scale deposits in the wellbores.
Standardized Measure of Discounted Future Net Cash Flows
December 31,
--------------------- --------------------
2004 2003 2002
---- ---- ----
Future cash flows $ 231,958,400 $ 83,099,200 $ 73,763,406
Future production and development costs (123,579,100) (32,804,600) (38,958,416)
------------- ------------- ---------------
Future net cash flows before discount 108,379,300 50,294,600 34,804,990
----------- ------------- ---------------
10% discount to present value (76,077,700) (34,099,500) (22,492,988)
------------ ------------- ---------------
Standardized measure of discounted
future net cash flows $ 32,301,600 $16,195,100 $ 12,312,002
============ =========== ===============
Changes in the Standardized Measure of Discounted Future Net Cash Flows
For the Years Ended December 31,
---------------------- --------------------
2004 2003 2002
---- ---- ----
Standardized measure of discounted future net
cash flows at the beginning of year $16,195,100 $ 12,312,002 $ -
Sales of oil and gas produced, net of production
Costs (2,485,621) (926,165) (44,699)
Net changes in prices and production costs (4,045,575) 13,209,650 -
Extensions and discoveries, net of future
production and development costs 34,439,255 7,250,499 21,007,459
Development costs incurred 17,499,346 4,218,902 7,319,184
Changes in estimated future development costs (62,687,146) 1,890,021 (31,717,307)
Revisions of previous quantity estimates (1,055,871) (2,629,973) -
Purchases of reserves in place 1,654,068 - -
Sales of reserves in place (623,985) (391,020) -
Accretion of discount 1,619,510 1,231,200 -
Changes in production rates and other
31,792,519 (19,970,016) 15,747,365
---------- ------------ ----------
Standardized measure of discounted future net cash flows at
the end of year $ 32,301,600 $16,195,100 $12,312,002
============= =========== ===========
74
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
During the third quarter of 2004, the Company's Audit Committee, certain members
of management and Deloitte & Touche LLP ("Deloitte"), the Company's prior
independent registered public accounting firm, engaged in several discussions
regarding whether Deloitte would continue to provide audit services to us. These
discussions focused partly on Deloitte's increased staffing requirements for us
and many of Deloitte's other clients, due in part to additional requirements of
Rule 404 under the Securities Exchange Act of 1934 and other rules promulgated
under the Sarbanes-Oxley Act. Deloitte indicated that it had to make a choice in
the deployment of its resources. On September 8, 2004, Deloitte resigned as the
Company's independent registered public accounting firm. On September 14, 2004,
our Audit Committee engaged Hein & Associates LLP to serve as the Company's
independent public accountants for the fiscal year 2004. The Audit Committee has
decided to continue to retain Deloitte to advise the Company with respect to tax
matters. During Gasco's two most recent fiscal years and the subsequent interim
period through September 8, 2004, there were no disagreements with Deloitte on
any matter of accounting principles or practices, financial statement
disclosure, or auditing scope or procedure, which disagreements, if not resolved
to Deloitte's satisfaction, would have caused it to make reference to the
subject matter of the disagreements in connection with its report on Gasco's
consolidated financial statements for such years; and during such period, there
were no "reportable events" of the kind listed in Item 304(a)(1)(v) of
Regulation S-K.
ITEM 9A - CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Company carried out an evaluation, under the supervision and with the
participation of the Company's management, including the Company's Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of the Company's disclosure controls and procedures as of
December 31, 2004 pursuant to Rule 13a-15 under the Exchange Act. Based upon
that evaluation, the Company's Chief Executive Officer and Chief Financial
Officer concluded that the Company's disclosure controls and procedures are
effective. Disclosure controls and procedures are controls and procedures that
are designed to ensure that information required to be disclosed in Company
reports filed or submitted under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the Securities and
Exchange Commission's rules and forms.
There have been no changes in the Company's internal control over financial
reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred
during the Company's last fiscal quarter that has materially affected or is
reasonably likely to materially affect the Company's internal control over
financial reporting.
Internal Control over Financial Reporting
We became an accelerated filer on June 30, 2004 as a result of our market
capitalization exceeding $75 million on that date. Because of our status as an
75
accelerated filer, we are required to include management's opinion on the
internal controls of the Company in our form 10-K for the year ending December
31, 2004. On November 30, 2004, the SEC issued an exemption order that allows
companies with less $700 million in market capitalization as of June 30, 2004,
an additional 45 days to file management's annual report on internal control
over financial reporting and the related attestation report of the Company's
registered public accounting firm.
Many companies had 18 months advance notice from the time that the rules were
announced until the date of required compliance. Because of the increase in our
market capitalization during the first half of 2004, we did not become an
accelerated filer until nine months prior to the compliance date. Further, we
were forced to find a new accounting firm during this period when our registered
public accounting firm informed us in September 2004 that they would not perform
the 2004 audit. As a result our evaluation and our auditor's testing of the
internal controls are not complete.
The management of the Company is responsible for establishing and maintaining
adequate internal control over financial reporting for the Company. We are in
the process of evaluating the effectiveness of the Company's internal control
over financial reporting, however for the reasons set forth above we have not
completed our assessment as of the date of this annual report. As of the date
hereof, we have not identified any errors or irregularities in our financial
reporting.
Through our evaluation to date, we have identified the following material
weaknesses in our internal control systems:
1. Insufficient segregation of duties with respect to the review of the
bank reconciliation of an account used for general and administrative
expenses and the review of certain other general corporate accounts,
such as prepaid and other assets.
2. Insufficient documentation with respect to the review of non-standard
journal entries.
3. Insufficient documentation of our quarterly closing procedures.
4. Insufficient documentation of the controls with respect to the output
of transactions recorded by our outsourced accounting function with
respect to the revenue and joint interest billing processes.
Additional material weaknesses may be uncovered as we complete our evaluation.
We have already initiated changes to our control systems to mitigate these
weaknesses for 2005.
We anticipate no difficulty in completing our evaluation of the internal
controls within the 45 day period following March 16, 2005 and will file an
amended 10-K that will include management's report on internal control over
financial reporting required by Item 308(a) of Regulation S-K, and the related
attestation report of the registered public accounting firm required by Item
308(b) of Regulation S-K.
ITEM 9B - OTHER INFORMATION
76
None.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2005 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 11 - EXECUTIVE COMPENSATION
The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2005 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2005 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2005 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2005 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. See "Index to Financial Statements" under Item 8 on page 42.
2. Financial Statement Schedules - none.
3. Exhibits
INDEX TO EXHIBITS
2.1 Agreement and Plan of Reorganization dated January 31, 2001 among San
Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian Energy, Inc.
(incorporated by reference to Exhibit 2.1 to the Company's Form 8-K dated
January 31, 2001, filed on February 2, 2001).
77
2.2 Agreement and Plan of Reorganization dated December 15, 1999 by and between
LEK International, Inc. and San Joaquin Oil & Gas Ltd. (incorporated by
reference to Exhibit 2.1 to the Company's Form 8-K dated December 31, 1999,
filed on January 21, 2000).
2.3 Property Purchase Agreement dated as of April 23, 2002, between the Company
and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1
to the Company's Form 8-K dated May 1, 2002, filed on May 9, 2002).
2.4 Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy
Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum
(California), Inc. and certain stockholders of Gasco. (incorporated by
reference to Exhibit 2.1 to the Company's Form 8-K dated July 16, 2002,
filed on July 31, 2002).
2.5 Purchase and Sale Agreement between ConocoPhillips and the Company relating
to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective
January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company's
Form 8-K dated March 9, 2004, filed on March 15, 2004).
2.6 Net Profits Purchase Agreement between Gasco Production Company, Red Oak
Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6,
2004 (incorporated by reference to Exhibit 2.1 of the Company's Current
Report on Form 8-K filed September 7, 2004).
2.7 Purchase Supplement to Net Profits Purchase Agreement between Gasco
Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV
Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit
2.2 of the Company's Current Report on Form 8-K filed September 7, 2004.
3.1 Amended and Restated Articles of Incorporation (incorporated by reference
to Exhibit 3.1 to the Company's Form 8-K dated December 31, 1999, filed on
January 21, 2000).
3.2 Certificate of Amendment to Articles of Incorporation (incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K/A dated January 31,
2001, filed on February 16, 2001).
3.3 Amended and Restated Bylaws (incorporated by reference to Exhibit 3.4 to
the Company's Form 10-Q for the quarter ended March 31, 2002, filed on May
15, 2002).
3.4 Certificate of Designation for Series B Convertible Preferred Stock
(incorporated by reference to Exhibit 3.5 to the Company's Form S-1
Registration Statement, File No. 333-104592).
4.1 Form of Subscription and Registration Rights Agreement, dated as of August
14, 2002 between the Company and certain investors Purchasing Common Stock
in August, 2002. (Filed as Exhibit 10.21 to the Company's Form S-1
Registration Statement dated November 15, 2002, filed on November 15,
2002).
4.2 Form of Gasco Energy, Inc. 8.00% Convertible Debenture, dated October 15,
2003 between each of The Frost National Bank, Custodian FBO Renaissance US
Growth & Investment Trust PLC Trust No. W00740100, HSBC Global Custody
Nominee (U.K.) Limited Designation No. 896414 and The Frost National Bank,
Custodian FBO Renaissance Capital Growth & Income Fund III, Inc. Trust No.
W00740000 (incorporated by reference to Exhibit 4.6 to the Company's Form
10-Q for the quarter ended September 30, 2003, filed on November 10, 2003).
4.3 Deed of Trust and Security Agreement, dated October 15, 2003 between
Pannonian and BFSUS Special Opportunities Trust PLC, Renaissance Capital
Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC
(incorporated by reference to Exhibit 4.7 to the Company's Form 10-Q for
the quarter ended September 30, 2003, filed on November 10, 2003).
78
4.4 Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and
Renn Capital Group, Inc (incorporated by reference to Exhibit 4.8 to the
Company's Form 10-Q for the quarter ended September 30, 2003, filed on
November 10, 2003).
4.5 Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin
Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to
Exhibit 4.9 to the Company's Form 10-Q for the quarter ended September 30,
2003, filed on November 10, 2003).
4.6 Form of Subscription and Registration Rights Agreement between the Company
and investors purchasing Common Stock in October 2003 (incorporated by
reference to Exhibit 4.10 to the Company's Form 10-Q for the quarter ended
September 30, 2003, filed on November 10, 2003).
4.7 Form of Subscription and Registration Rights Agreement between the Company
and investors purchasing Common Stock in February, 2004 (incorporated by
reference to Exhibit 4.7 to the Company's Form 10-K for the year ended
December 31, 2003, filed on March 26, 2004).
4.8 Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and
Wells Fargo Bank, National Association, as Trustee (incorporated by
reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed
on October 20, 2004).
4.9 Form of Global Note representing $65 million principal amount of 5.5%
Convertible Senior Notes due 2011 (incorporated by reference to Exhibit A
to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October
20, 2004).
4.10 Registration Rights Agreement dated October 20, 2004, among Gasco Energy,
Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate
by reference to Exhibit 4.10 to the Company's Form 10-Q for the quarter
ended September 30, 2004 filed on November 12, 2004).
#10.11999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the
Company's Form 10-KSB for the fiscal year ended December 31, 1999, filed on
April 14, 2000).
#10.2Form of Stock Option Agreement under the 1999 Stock Option Plan
(incorporated by reference to Exhibit 10.8 to the Company's Form 10-K for
the fiscal year ended December 31, 2001, filed on March 29, 2002).
#10.3Stock Option Agreement dated January 2, 2001 between Gasco and Mark A.
Erickson (Filed as Exhibit 10.9 to the Company's Form 10-K for the fiscal
year ended December 31, 2001, filed on March 29, 2002).
#10.4Form of Stock Option Agreement between Gasco and each of the individuals
named therein (incorporated by reference to Exhibit 4.6 to the Company's
Form S-8 Registration Statement (Reg. No. 333-122716), filed on February
10, 2005).
#10.5W. King Grant Amended and Restated Employment Contract dated February 14,
2003 (Filed as Exhibit 10.10 to the Company's Form 10-K for the fiscal year
ended December 31, 2002, filed on March 29, 2003).
#10.6Michael Decker Amended and Restated Employment Contract dated February 14,
2003 (Filed as Exhibit 10.11 to the Company's Form 10-K for the fiscal year
ended December 31, 2002, filed on March 29, 2003).
#10.7Mark A. Erickson Amended and Restated Employment Contract dated February
14, 2003 (Filed as Exhibit 10.12 to the Company's Form 10-K for the fiscal
year ended December 31, 2002, filed on March 29, 2003).
#10.8Amended and Restated Consulting Agreement dated February 14, 2003, between
Gasco and Marc Bruner (Filed as Exhibit 10.13 to the Company's Form 10-K
for the fiscal year ended December 31, 2002, filed on March 29, 2003).
79
#10.92003 Restricted Stock Plan (Filed as Appendix B to the Company's Proxy
Statement dated August 25, 2003 for its 2003 Annual Meeting of
Stockholders, filed on August 25, 2003).
10.10Muddy Creek Exploration Agreement dated August 15, 2001, between Gasco,
Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as
Exhibit 10.15 to the Company's Form 10-K for the fiscal year ended December
31, 2001, filed on March 29, 2002).
10.11CD Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe
Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit
10.16 to the Company's Form 10-K for the fiscal year ended December 31,
2001, filed on March 29, 2002).
10.12Gamma Ray Exploration Agreement dated August 15, 2001, between Gasco,
Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as
Exhibit 10.17 to the Company's Form 10-K for the fiscal year ended December
31, 2001, filed on March 29, 2002).
10.13Sublette County, WY AMI Agreement dated August 22, 2001 between Gasco,
Alpine Gas Company and Burlington Oil and Gas Company (Filed as Exhibit
10.18 to the Company's Form 10-K for the fiscal year ended December 31,
2001, filed on March 29, 2002).
10.14Lead Contractor Agreement dated January 24, 2002, between Gasco and
Halliburton Energy Services, Inc. (Filed as Exhibit 10.19 to the Company's
Form 10-K for the fiscal year ended December 31, 2001, filed on March 29,
2002).
10.15Property Purchase Agreement, dated as of April 23, 2002, between the
Company and Shama Zoe Limited Partnership (Filed as Exhibit 2.1 to the
Company's Form 8-K dated May 1, 2002, filed on May 9, 2002).
10.16Purchase Agreement, dated as of July 16, 2002, among the Company,
Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation,
Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain
stockholders (Filed as Exhibit 2.1 to the Company's Form 8-K dated July 16,
2002, filed on July 31, 2002).
10.17Amendment No. 1 to Property Purchase Agreement dated as of August 9, 2002
between the Company and Shama Zoe Limited Partnership. (Filed as Exhibit
10.21 to the Company's Form S-1 dated November 15, 2002, filed on November
15, 2002).
10.18Financial Advisory Services Agreement dated August 22, 2002, between the
Company and Energy Capital Solutions LLC. (Filed as Exhibit 10.21 to the
Company's Form S-1 Registration Statement, filed on November 15, 2002).
10.19Termination and Settlement Agreement, dated as of December 23, 2004, among
Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit
10.1 to the Company's Current Report on Form 8-K filed on October 20,
2004).
21 List of Subsidiaries (Filed as Exhibit 21 to the Company's Form 10-K for
the year ended December 31, 2003, filed on March 26, 2004).
*23.1 Consent of Deloitte & Touche, LLP
*23.2 Consent of Netherland, Sewell & Associates, Inc.
*23.3 Consent of Hein & Associates LLP
*31 Rule 13a-14(a)/15d-14(a) Certifications
*32 Section 1350 Certifications
* Filed herewith.
# Identifies management contracts and compensatory plans or arrangements.
80
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
GASCO ENERGY, INC. Dated: March 15, 2005
By: /s/ Mark A. Erickson
------------------------------------
Mark A. Erickson, President and CEO
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Title Date
/s/ Mark A. Erickson Director and President and Chief Executive Officer March 15, 2005
- --------------------
Mark A. Erickson
/s/ Marc A. Bruner Director March 15, 2005
- ---------------------
Marc A. Bruner
/s/ Carl Stadelhofer Director March 15, 2005
- --------------------
Carl Stadelhofer
/s/ W. King Grant Executive Vice President and Chief Financial Officer March 15, 2005
- -----------------
W. King Grant (Principal Financial Officer and Principal Accounting
Officer)
/s/ Carmen Lotito Director March 15, 2005
- -----------------
Carmen ("Tony") Lotito
/s/ Charles B. Crowell Director March 15, 2005
- ----------------------
Charles B. Crowell
/s/ Richard S. Langdon Director March 15, 2005
- ----------------------
Richard S. Langdon
/s/ R. J. Burgess Director March 15, 2005
- ---------------------
R.J. Burgess
/s/ John A. Schmit Director March 15, 2005
- ------------------
John A. Schmit
81