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, 2005
[ ] 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.)
8 Inverness Drive East, Suite 100, 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 if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.
Yes __No X
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.
Yes __ No X
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 a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one):
Large accelerated filer __ Accelerated filer X Non-accelerated filer __
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes __ No X -
As of June 30, 2005, approximately 64,587,470 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 $238,973,639. As of February 27, 2006, 84,967,792 shares of 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 2006 annual meeting of stockholders to be filed within
120 days after December 31, 2005.
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..........................4
Governmental Regulations and Environmental Laws.................4
Number of Total Employees and Number of Full-Time Employees.....6
Available Information...........................................6
Cautionary Statement Regarding Forward-Looking Statements.......6
Item 1 A. Risk Factors.........................................................8
Item 1 B. Unresolved Staff Comments...........................................19
Item 2. Description of Property.............................................20
Petroleum and Natural Gas Properties...........................20
Company Reserve Estimates......................................23
Volumes, Prices and Operating Expenses.........................23
Development, Exploration and Acquisition Capital Expenditures..23
Productive Gas Wells...........................................24
Oil and Gas Acreage............................................24
Drilling Activity..............................................26
Office Space...................................................26
Item 3. Legal Proceedings...................................................26
Item 4. Submission of Matters to a Vote of Security Holders.................26
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer........................................................27
Purchases of Equity Securities...................................27
Equity Compensation Plans......................................27
Securities Transactions........................................29
Item 6. Selected Financial Data.............................................29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................29
Forward Looking Statements.....................................29
Overview.......................................................30
Recent Developments............................................30
Liquidity and Capital Resources................................32
Capital Budget.................................................34
Schedule of Contractual Obligations............................34
Critical Accounting Policies and Estimates.....................35
Results of Operations..........................................37
Recent Accounting Pronouncements...............................39
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..........41
Item 8. Financial Statements and Supplementary Data.........................42
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..............................................82
Item 9A. Controls and Procedures.............................................82
Item 9 B. Other Information...................................................85
Part III
Item 10. Directors and Executive Officers of the Registrant..................85
Item 11. Executive Compensation..............................................85
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.......................................86
Item 13. Certain Relationships and Related Transactions......................86
Item 14. Principal Accountant Fees and Services..............................86
Item 15. Exhibits and Financial Statement Schedules..........................86
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 resources, primarily in the Rocky Mountain region. Our
principal business strategy is to enhance stockholder value by using
technologies new to a specific area to generate and develop high-potential
exploitation resources in this area. Our 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. We are currently focusing our drilling efforts in the Riverbend Project
located in the Uinta Basin of northeastern Utah, targeting the Wasatch,
Mesaverde and Blackhawk formations. As of December 31, 2005, we held interests
in 264,329 gross acres (165,577 net acres) located in Utah, Wyoming, California
and Nevada. As of December 31, 2005, we held an interest in 42 gross producing
wells (27.2 wells, net to our interest) located on these properties.
During 2005 we spudded 21 gross wells (14.9 net) and reached total depth on 20
gross wells (13.7 net) in the Riverbend Project. Initial completion operations
were conducted on 21 wells and 12 well bores were re-entered to complete
behind-pipe pay. As of December 31, 2005, in the Riverbend Project we had 42
gross wells on production. Currently, we are operating three drilling rigs in
the Riverbend Project.
Our initial capital budget for 2005 of $38 million was increased to $50 million
to allow for increased activity during the fourth quarter. Our increased budget
included the incremental expenditures for spudding two additional wells, initial
completion operations on two wells, and increased costs associated with the
Company's drilling program.
Our capital budget for 2006 is approximately $80 million for the drilling and
completion of wells, pipeline infrastructure, distribution facilities and
geophysical operations. In connection with our 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.
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 known 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
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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.
Acquisition, Exploration and Development Expenses
During the years ended December 31, 2005 and 2004 the Company spent $50,069,968
and $23,462,908, respectively for development and exploration activities. During
2004, the Company completed a property acquisition of additional working
interests in six producing wells and certain acreage and gathering system assets
in the Riverbend area of Utah for a net purchase price of approximately
$2,400,000 and acquired approximately 16,000 net acres in Uinta and Duchesne
Counties, Utah for approximately $3,432,000. 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, 2005, the Company held working interests in 264,329
gross acres (165,577 net acres) located in Utah, Wyoming, California and Nevada.
As of December 31, 2005, the Company held an interest in 42 gross (27.2 net to
the Company's interest) producing gas wells and 3 gross (1.3 net) shut-in gas
wells located on these properties. As of February 27, 2006 the Company operates
46 wells, all of which 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, 2005, 2004 and 2003, purchases by the following
company exceeded 10% of the total oil and gas revenues of the Company.
3
Percent of Production Purchased
For the Years Ended December 31,
------------------------------------------------
2005 2004 2003
---- ---- ----
ConocoPhillips Company 96% 93% 93%
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
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 hiring field and technical
personnel and obtaining drilling rigs and services. 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
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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
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,
the EPA has promulgated more stringent regulations governing emissions of toxic
air pollutants from sources in the oil and gas industry, and these regulations
may increase the costs of compliance for some facilities.
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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. To add further
assurance that we will not experience a significant curtailment, we signed a
Memorandum of Understanding with the Bureau of Land Management during the first
half of 2005 that allows us to continue drilling while the EIS is being
completed. 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.
Number of Total Employees and Number of Full-Time Employees
As of February 27, 2006, Gasco had 17 full-time employees.
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.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the information in this annual report, contains forward-looking
statements within the meaning 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;
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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 delays in obtaining drilling permits
o uncertainties in the availability of distribution facilities for our
natural gas;
o general economic conditions;
o natural gas and oil price volatility;
o the fluctuation in the demand for natural gas and oil;
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 climatic conditions;
o the risks associated with exploration;
o our ability to generate sufficient cash flow to operate;
o availability of capital;
o the strength and financial resources of our competitors;
o downhole drilling and completion risks that are generally not
recoverable from third parties or insurance;
o actions or inactions of third-party operators of our properties;
o environmental risks;
7
o regulatory developments;
o potential mechanical failure or under-performance of significant
wells;
o availability and cost of material and equipment;
o our ability to find and retain skilled personnel;
o the lack of liquidity of our common stock; and
o our ability to eliminate material weaknesses in our internal controls
over financial reporting.
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 1A. 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, 2005 and 2004, we incurred a net loss of
$37,635 and $4,205,830, respectively. As of December 31, 2005, we had an
accumulated deficit of $29,535,226. 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
8
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;
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 natural gas production is currently located in, and all of our future
natural gas 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
9
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.
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, 2005, 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
five years as of December 31, 2005, 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
10
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.
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.
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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
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 business.
Delays in obtaining drilling permits could have a materially adverse effect on
our ability to develop our properties in a timely manner.
The average processing time at the Bureau of Land Management in Vernal, Utah for
an application to drill on federal leases has been increasing and currently is
approximately 270 days. Approximately 77% of our gross acreage in Utah is
located on federal leases. If we are delayed in procuring sufficient drilling
permits for our federal properties, we will shift more of our drilling in Utah
to our state leases, the permits for which require an average processing time of
approximately 30 days. While such a shift in resources would not necessarily
affect the rate of growth of our cash flow, it would result in a slower growth
rate of our total proved reserves, because a higher percentage of the wells
drilled on the state leases will be drilled on leases to which proved
undeveloped reserves my already have been attributed.
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.
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
12
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.
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
13
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. In addition, although we currently
have access to firm transportation for the majority of our current gas
production, there is no assurance that we will be able to procure additional
transportation on terms satisfactory to us, or at all, as we increase our
production through our drilling program.
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.
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
14
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.
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. 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.
15
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.
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, Mr. Decker is an Executive Vice President and Chief
Operating Officer and Mr. Grant is an Executive Vice President and Chief
Financial Officer. 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 of Galaxy Energy Corporation
("Galaxy"). Mr. Bruner is involved in identifying and acquiring large land
packages for exploitation and development by Galaxy. Mr. Bruner also serves as
the Chairman and Chief Operating Officer of Falcon Oil and Gas, Ltd. ("Falcon").
Falcon's current drilling activities include projects in Romania and Hungary. In
addition, another of our directors, C. Tony Lotito, is a Director of Galaxy, and
currently serves as the Executive Vice President, Chief Financial Officer,
Secretary-Treasurer and a member of the Board of Directors of GSL Energy
Corporation, which is majority owned by Mr. Bruner.
16
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 our 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,
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 Capital 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;
17
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, 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, 2005, we had 84,967,792 shares
of common stock issued and outstanding. As of such date, there were 9,292,266
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 3,237,612 shares of common stock
under our stock option plan and an additional 155,450 shares of common stock are
issuable under our restricted stock plan. 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 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 101,217,792 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.
18
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.
ITEM 1 B. UNRESOLVED STAFF COMMENTS
None.
19
ITEM 2 - DESCRIPTION OF PROPERTY
Petroleum and Natural Gas Properties
Gasco is a natural gas and petroleum exploitation, development and production
company engaged in locating and developing hydrocarbon resources primarily in
the Rocky Mountain Region. Gasco'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. Our principal
business is the acquisition of leasehold interests in petroleum and natural gas
rights, either directly or indirectly, and the exploitation and development of
the properties subject to these leases.
The Company's corporate strategy is to grow through drilling projects. We have
been focusing our drilling efforts in the Riverbend Project located in the Uinta
Basin of northeastern Utah. The higher realized oil and gas prices during 2004
and 2005 due to factors such as inventory levels of gas in storage, extreme
weather 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 our drilling projects in this area. The increased drilling
activity in the Company's areas of operations resulting from the higher oil and
gas prices has also decreased the availability of drilling rigs and experienced
personnel in this area and may continue to do so. The Company also continues to
incur higher drilling and operating costs resulting from the increased fuel and
steel costs and from the increased drilling activity in this area.
Riverbend Project
The Riverbend Project comprises approximately 124,281 gross acres in the Uinta
Basin of northeastern Utah, of which we hold interests in approximately 74,471
net acres as of December 31, 2005. Our engineering and geologic focus is
concentrated on three tight-sand formations in the Uinta basin: the Wasatch,
Mesaverde and Blackhawk formations. A typical well may encounter multiple
distinct natural gas sands located between approximately 6,000 and 13,000 feet
in depth that are completed using up to ten staged fracs.
During 2005 we spudded 21 gross wells (14.9 net) and reached total depth on 20
gross wells (13.7 net). Initial completion operations were conducted on 21 wells
and 12 well bores were re-entered to complete behind-pipe pay. As of December
31, 2005, Gasco had 42 gross wells on production.
During 2005 the Company had three rigs operating in its Riverbend Project. We
converted two of the three rigs currently drilling for us from well-to-well
contracts to two-year term contracts. The third rig will continue to operate on
a well-to-well basis. During December 2005, Gasco purchased a rig for
approximately $5,000,000. Gasco entered into a one-year drilling contract with
an unrelated third party who will operate the rig. The operator may buy the rig
from Gasco at the fair market value of the rig within three years of when the
rig is delivered. This rig is scheduled to be moved on location in our Riverbend
Project to begin drilling early in the second quarter of 2006. With the addition
of this rig, Gasco will have four rigs drilling in the Riverbend Project during
20
most of 2006. Also, during December 2005, we entered into a three-year contract
for a new-build rig to be delivered in December 2006. In connection with this
contract we provided the rig owner a letter of credit from our bank for
$6,564,000. The cash collateral for this letter of credit is reflected as a
restricted investment in the accompanying financial statements.
In January 2004 we 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. The
development of this project is contemplated to proceed in increments of 10-well
bundles to be approved by the parties on an ongoing basis. Under these
agreements, the Service Parties have the exclusive right, as long as they are
able, to provide their services in the development of the Riverbend acreage.
Under these agreements, we have 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. The remaining development costs are funded by third party
investors that are also parties to the agreements. To secure our obligations
under the agreements, we have pledged our interests in each of the wells that we
drill. Our 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.
During the fourth quarter 2005, the third 10-well bundle was approved by Gasco
and the Service Parties and is incorporated in our 2006 drilling program. Under
these arrangements, we drilled 12 wells during 2004 and 10 wells during 2005
(included in the drilling results described above), all of which are currently
producing.
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 had 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.
In November 2004, we completed construction on a ten mile pipeline in the
Riverbend Project area to create additional pipeline capacity in this area. We
currently own gas gathering and distribution facility assets that include
approximately 45 miles of pipeline. This pipeline gathers approximately 97% of
our natural gas production from the Riverbend Project. We continue to evaluate
additional gathering, compression and processing needs in each of the Riverbend,
West Desert, Wilkin Ridge and Gate Canyon areas from our Riverbend Project in
addition to evaluating alternative proprosals for distribution facilities of
natural gas from the region.
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
21
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.
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.
Greater Green River Basin Project
As of December 31, 2005, the Company has a leasehold interest in approximately
90,272 gross acres and 42,783 net acres in the Greater Green River Basin area of
Wyoming. The acreage covers two prospects identified by Gasco. The Company
re-entered two of its wells in the Muddy Creek Project in the Greater Green
River Basin Area in Wyoming during 2004 and these wells are currently producing
intermittently. The Company is currently seeking a drilling rig to drill three
wells in its two Wyoming prospects during 2006. The Company is also considering
additional options for this area such as the farm-out of some of our acreage and
other similar type transactions. Leases covering approximately 8,000 gross acres
(4,055 net acres) will expire during the first six months of 2006, and will not
be renewed, since management has decided not to drill on these leases.
During 2005, the Company reclassified approximately $5,300,000 of expiring
acreage primarily located in Wyoming into proved property. This acreage is
located outside of the prospects that the Company intends to develop.
Southern California Project
The Company has a leasehold interest in approximately 4,461 gross acres (3,008
net acres) in Kern and San Luis Obispo Counties of Southern California. During
2005, the Company entered into a farm-out agreement under which an unrelated
entity has committed to drill one well on our acreage in San Luis Obispo and
Kern Counties, California. Under this agreement, Gasco will contribute the
acreage and the unrelated entity will pay the drilling and completion costs.
Gasco will retain a 25% interest if the well is successful. The Company is also
continuing to pay leasehold rentals and geological expenses to preserve its
acreage positions and develop its remaining California prospects.
Nevada Project
The Company has a leasehold interest in approximately 45,315 gross and net acres
in six prospects within White Pine County Nevada. We have signed a letter of
intent with an industry partner to develop these prospects and are in
discussions for a definitive agreement covering all six prospects.
22
Company Reserve Estimates
The following table summarizes the Company's estimated reserve data as of
December 31, 2005, 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, 2005 of $8.01 per Mcf of gas and $59.87 per bbl
of oil. The present value of future net cash flows has been adjusted to include
the estimated future income tax expense of $3,225,000. All of the Company's
proved reserves are located within the state of Utah.
Proved Reserve Quantities Present Value of Future Net Cash Flows
Proved Proved
Mcf of Gas Bbls of Oil Undeveloped Developed Total
Total 74,455,128 377,288 $ 40,256,500 $ 64,364,500 $104,621,000
=========== ======== ============= ============= ============
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, 2005 present value of future net cash flows of
approximately $3,792,200.
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 and oil for the periods indicated.
For the Years Ended December 31,
--------------------------------------------
2005 2004 2003
------------ ------------ -----------
Natural gas production (Mcf) 1,648,870 505,967 257,035
Average sales price per Mcf $8.16 $5.79 $4.69
Oil production (Bbl) 10,636 5,080 1,988
Average sales price per Bbl $56.91 $38.43 $28.52
Expenses per Mcfe:
Lease operating $0.51 $1.19 $1.25
General and administrative $3.50 $7.81 $10.48
Depreciation, depletion and amortization $2.83 $2.06 $2.06
Development, Exploration and Acquisition Capital Expenditures
During the years ended December 31, 2005 and 2004, we spent $50,069,968 and
$23,462,908 in development and exploration activities, respectively.
Additionally during 2005 we purchased a drilling rig for approximately
$5,000,000. The expenditures during 2004 included a property acquisition for a
net purchase price of approximately $2,400,000 and an acreage acquisition in the
23
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. As of December
31, 2005, the Company held working interests in 264,329 gross acres (165,577 net
acres) located in Utah, Wyoming, California and Nevada. As of December 31, 2005,
the Company held an interest in 42 gross (27.2 net to Gasco's interest)
producing gas wells and 3 gross (1.3 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,
--------------------------------------------------
2005 2004 2003
-------------- ---------------- ------------------
Property acquisition costs:
Unproved $ 410,062 $ 5,021,126 $ 667,557
Proved - 723,9012 --
Exploration costs 1,064,874 216,165 396,967
Development costs 48,595,032 17,501,716 4,218,902
---------- ---------- ----------
Total including asset retirement obligation 50,069,968 23,462,908 5,283,426
========== ========== =========
Total excluding asset retirement obligation $49,968,623 $23,398,559 $ 5,168,174
=========== =========== =========
Productive Gas Wells
The following summarizes the Company's productive and shut-in gas wells as of
December 31, 2005. 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 42 27.2
Shut-in gas wells 3 1.3
- ---
45 28.5
== ====
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, 2005. 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
24
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
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 122,641 73,413 1,640 1,058
Wyoming 90,112 42,702 160 81
Nevada 45,315 45,315 - -
California 4,461 3,008 - -
----------- ------------ --------- --------
Total acres 262,529 164,438 1,800 1,139
=========== ============ ========= ========
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 2006 Expiring in 2007 Expiring in 2008
Gross Net Gross Net Gross Net
Utah 1,424 978 1,574 886 640 120
Wyoming 8,993 4,836 4,644 3,628 1,876 399
California - - 357 268 160 120
------- ----- ----- ----- ----- ---
Total 10,417 5,814 6,575 4,782 2,676 639
====== ===== ===== ===== ===== ===
As of December 31, 2005, 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.
25
Drilling Activity
The following table sets forth the Company's drilling activity during the years
ended December 31, 2005, 2004 and 2003. 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,
-------------------------------------------------------------------------------
2005 2004 2003
------------------ ------------------------ ----------------------------
Gross Net Gross Net Gross Net
Exploratory Wells:
Productive - - - - - -
Dry - - - - - -
--- --- --- --- --- ---
Total wells - - - - - -
=== === === === === ===
Development Wells:
Productive 21 14.9 11 3.0 - -
Dry - - - - - -
-- ----- -- --- --- ---
Total wells 21 14.9 11 3.0 - -
== ===== == === === ===
Office Space
The Company leases approximately 8,776 square feet of office space in Englewood,
Colorado, under a lease, which terminates on May 31, 2010. The average rent for
this space over the life of the lease is approximately $120,500 per year. The
Company believes that this space will meet its needs for at least the next two
years.
ITEM 3 - LEGAL PROCEEDINGS
None.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
26
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 February 27, 2006, the Company had 103 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, 2005.
High Low
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
2005
First Quarter 4.25 2.95
Second Quarter 3.88 2.85
Third Quarter 6.91 3.57
Fourth Quarter 7.95 5.60
Equity Compensation Plans
The table below provides information relating to the Company's equity
compensation plans as of December 31, 2005.
27
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 5,259,167 $ 2.42 3,237,612(a)
Restricted stock plan 844,550 N/A (b) 155,450
Equity compensation plans
not approved by security holders 3,553,500 $ 2.10 (c)
--------- -----------
Total 9,657,217 $ 2.29(d) 3,393,062
========= ==== =========
(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 during the period from 2006 through 2008. 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 2,076,000 $1.00 - $3.15 2001 - 2003 2006 - 2008
Consultants 302,500 $1.80 - $3.70 2001 - 2003 2006 - 2008
Directors 1,175,000 $2.00 - $3.15 2001 - 2003 2006 - 2008
---------
Total Issued 3,553,500
=========
(d) Weighted average exercise price of options to purchase a total of
8,812,667 shares of common stock.
28
Securities Transactions
The Company's securities transactions during the year ended December 31, 2005
that were not registered under the Securities Act of 1933 are described as
follows:
During 2005, certain holders of the Company's Series B Convertible Preferred
Stock ("Preferred Stock") converted 1,492 shares of Preferred Stock into 937,827
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.
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,
2005 2004 2003 2002 2001
---- ---- ---- ---- ----
Summary of Operations
Oil, gas and gathering revenue $15,479,566 $3,267,214 $1,263,443 $ 164,508 $ 36,850
General & administrative expense 5,987,019 4,191,978 2,819,675 5,080,287 4,326,065
Net loss (37,635) (4,205,830) (2,526,525) (5,649,682) (4,129,459)
Net loss per share (0.00) (0.07) (0.07) (0.16) (0.63)
As of and for the Year Ended December 31,
2005 2004 2003 2002 2001
---- ---- ---- ---- ----
Balance Sheet
Working capital (deficit) $86,078,958 $52,719,245 $1,192,246 $(2,857,539) $11,860,584
Cash and cash equivalents 62,661,368 25,717,081 3,081,109 2,089,062 12,296,585
Oil and gas properties, net 100,334,852 50,820,383 28,470,917 24,760,149 9,152,740
Total assets 201,199,972 117,368,168 33,059,179 27,505,501 21,658,525
Long-term obligations 65,302,674 65,108,566 2,483,084 - -
Stockholders' equity 127,440,160 46,213,198 27,382,083 22,014,265 21,065,425
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
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.
29
Overview
Gasco is a natural gas and petroleum exploitation, development and production
company engaged in locating and developing hydrocarbon prospects, primarily in
the Rocky Mountain region. The Company's business strategy is to enhance
shareholder value by using technologies new to a specific area to generate and
develop high-potential exploitation resources 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.
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
2004 and 2005 due to factors such as inventory levels of gas in storage, extreme
weather in parts of the country and increasing 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 also continues to incur higher
drilling and operating costs resulting from the increased fuel and steel costs
and from the increased drilling activity in this area.
Recent Developments
Gasco increased its 2005 capital budget to $50 million from $38 million for
drilling and completion operations and pipeline connections in the Riverbend
project area. The increased budget included spudding two additional wells,
initial completion operations on two wells, and increased costs associated with
the Company's drilling program. During 2005 we spudded 21 gross wells (14.9 net)
and reached total depth on 20 gross wells (13.7 net). Initial completion
operations were conducted on 21 wells and 12 well bores were re-entered to
complete behind-pipe pay. The Company anticipates an overall increase in its
compensation expense because it continues to hire additional personnel to manage
the workload associated with its operational plans for 2006.
During 2005 the Company had three rigs operating in its Riverbend Project. We
converted two of the three rigs currently drilling for us from well-to-well
contracts to two-year term contracts. The third rig will continue to operate on
a well-to-well basis. During December 2005, Gasco purchased a rig for
approximately $5,000,000. Gasco entered into a one-year drilling contract with
an unrelated third party who will operate the rig. The operator may buy the rig
from Gasco at the fair market value of the rig within three years of when the
rig is delivered. This rig is scheduled to be moved on location in our Riverbend
Project to begin drilling early in the second quarter of 2006. With the addition
of this rig, Gasco will have four rigs drilling in the Riverbend Project during
most of 2006. Also, during December 2005, we entered into a three-year contract
for a new-build rig to be delivered in December 2006. In connection with this
contract we provided the rig owner a letter of credit from our bank for
30
$6,564,000. The cash collateral for this letter of credit is reflected as a
restricted investment in the accompanying financial statements.
On November 23, 2005, we closed a public offering of 12,500,000 shares of common
stock at a price to the public of $6.50 per share. We also granted the
underwriters a 30-day option to purchase up to 1,875,000 additional shares of
our common stock solely to cover over-allotments. Pursuant to this option, the
underwriters purchased an additional 439,400 shares of common stock on December
6, 2005. The net proceeds from this offering, after underwriting discount and
offering costs were $79,418,386. We expect to use these proceeds to fund capital
expenditures for the development and exploration of our oil and natural gas
properties and the development ofassociated infrastructure, working capital and
general corporate purposes.
The Board of Directors of Gasco approved a budget of $80 million for our 2006
capital expenditure program. The program will primarily cover the drilling and
completion of approximately 32 gross wells (15 net wells) on our Riverbend
Project and the drilling and completion of up to three wells in Wyoming. The
budget also includes expenditures for the installation of associated pipeline
infrastructure, distribution facilities and geophysical operations. In
implementing our planned increase in drilling activity we have encountered
difficulties in obtaining additional drilling supplies and services as well as
experienced personnel, which may reduce the number of wells the Company is able
to drill during 2006. 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 2006. Management believes it has
sufficient capital for its 2006 operational budget, but will need to raise
additional capital for its capital budget in 2007. 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.
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, 2005. The Mcfe calculations assume a conversion of 6
Mcf's for each Bbl of oil.
For the Years Ended December 31,
----------------------------------------------------
2005 2004 2003
------------- --------------- ---------------
Natural gas production (Mcf) 1,648,870 505,967 257,035
Average sales price per Mcf $8.16 $5.79 $4.69
Year-end proved gas reserves (Mcf) 74,455,128 39,700,156 13,601,003
Oil production (Bbl) 10,636 5,080 1,988
Average sales price per Bbl $56.91 $38.43 $28.52
Year-end proved oil reserves (Bbl) 377,288 274,074 100,987
Production (Mcfe) 1,712,686 536,447 268,963
Year-end proved reserves (Mcfe) 76,718,856 41,344,600 14,206,925
31
The Company's oil and gas production increased by approximately 219% during 2005
as compared with 2004 primarily due to the Company's drilling of 21 gross (14.9
net) wells during 2005. During 2005, on a combined basis, the oil and gas
reserve quantities increased by approximately 86% primarily due to reserve
additions of 122% which were partially offset by annual production of 4% and
revisions of previous estimates of 32%. The majority of the revisions of
previous estimates were a result of the following:
- Four locations previously classified as proved undeveloped were
omitted from the 2005 reserve report because these locations required
a higher capital investment than originally estimated due to drilling
and completion problems and due to the lack of historical data related
to recent completions and recompletions in this area.
- Six locations previously classified as proved undeveloped were omitted
from the 2005 reserve report because recent drilling activity
indicates that these locations may be outside of or on the edge of a
previously identified zone.
- Two proved developed non-producing completions significantly
underperformed previous forecasts.
During 2004, the Company's oil and gas production increased by approximately 99%
as compared with 2003 primarily due to our 2004 drilling projects and working
interest acquisitions. During 2004, on a combined basis, the oil and gas reserve
quantities increased by approximately 191% primarily due to reserve 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.
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, 2005, 2004 and 2003.
For the Year Ended December 31,
----------------------------------------------
2005 2004 2003
---- ---- ----
Net cash provided by (used in) operations $ 2,135,032 $ (905,369) $ (2,191,914)
Net cash used in investing activities (45,851,527) (58,400,053) (5,286,690)
Net cash provided by financing activities 80,660,782 81,941,394 8,470,651
Net cash flow 36,944,287 22,635,972 992,047
The increase in cash provided by operations from 2004 to 2005 is primarily due
to a 219% increase in oil and gas production, a 41% increase in gas prices and a
48% increase in oil prices. The production increase is due to the drilling
activity during 2005 as described above. The decrease in cash used in operations
from 2003 to 2004 was primarily due to the increase in revenue resulting from a
99% increase in oil and gas production due to the Company's drilling activity
and the acquisition of additional working interests in six wells during 2004,
partially offset by a decrease in the changes in operating assets and
liabilities primarily due to the timing of the Company's operational activity.
32
The Company's investing activities during the three years ended December 31,
2005 related primarily to the Company's development and exploration activities
and the purchase of a drilling rig. During 2004, we also completed acquisitions
of acreage and additional working interests in producing wells for approximately
$5,800,000. We had sales proceeds of $828,102 during 2005 which represented the
sale of acreage to an unrelated entity. Our sales proceeds during 2004
represented a disposition of net profits interests in 8 wells in the Riverbend
area for $4,463,161. We also invested $27,000,000 in short-term investments
during 2004 and sold $12,000,000 of these investments during 2005. The remaining
investing activity during 2005, 2004 and 2003 consisted of changes in our
restricted investments.
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 primarily comprised of the net
proceeds from the sale of equity in the Company, as further described below.
On November 23, 2005, we closed a public offering of 12,500,000 shares of common
stock at a price to the public of $6.50 per share. We also granted the
underwriters a 30-day option to purchase up to 1,875,000 additional shares of
our common stock solely to cover over-allotments. Pursuant to this option, the
underwriters purchased an additional 439,400 shares of common stock on December
6, 2005. The net proceeds from this offering, after underwriting discount and
offering costs were $79,418,386. We expect to use these proceeds to fund capital
expenditures for the development and exploration of our oil and natural gas
properties and the development of associated infrastructure, working capital and
general corporate purposes.
During 2005, 643,083 options to purchase Gasco common stock were exercised for
proceeds of $1,275,743.
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 2004, 33,336 options to purchase Gasco common stock were exercised for
proceeds of $33,336.
During 2003 the Company closed the sale of $2,500,000 of 8% Convertible
Debentures in a private placement, sold 11,052 shares of Series B Convertible
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.
33
Capital Budget
The Board of Directors of Gasco approved a budget of $80 million for our 2006
capital expenditure program. The program will primarily cover the drilling and
completion of approximately 32 gross wells (15 net wells) on our Riverbend
Project and the drilling and completion of up to three wells in Wyoming. The
budget also includes expenditures for the installation of associated pipeline
infrastructure, distribution facilities and geophysical operations.
This budget will be funded primarily from cash on hand and the proceeds from our
November stock offering described above.
Management believes it has sufficient capital for its 2006 operational budget,
but may need to raise additional capital for its capital budget in 2007. The
Company may 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,
consulting agreement and service contracts for the periods specified as of
December 31, 2005.
Payments due by Period
Contractual Obligations Total 1 year 2-3 years 4-5 years After 5 years
- ----------------------- ----- ------ --------- --------- -------------
Convertible Notes
Principal $65,000,000 $ - $ - $ - $ 65,000,000
Interest 20,605,903 3,575,000 7,150,000 7,150,000 2,730,903
Drilling Rig Contracts * 54,514,375 17,542,625 29,306,750 7,665,000 -
Operating Lease - office space 564,579 105,844 251,858 206,877 -
Employment Contracts 509,167 470,000 39,167 - -
Consulting Agreements 253,000 243,000 10,000 - -
----------- ---------- ---------- ----------- ----------
Total Contractual Cash
Obligations $141,447,024 $21,936,469 $36,757,775 $15,021,877 $67,730,903
============ =========== =========== =========== ===========
* The three year drilling contract for the new-build rig contains a
provision for the Company to terminate the contract for $12,000 per
day for the number days remaining in the original contract.
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 five 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
non-producing and undeveloped. As the Company's wells are produced over time and
35
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. For example 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, 2005 present value of future net cash flows of approximately
$3,792,200. 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. As a result, $1,725,000 of costs associated with this acreage was
reclassified into the full cost pool during the year ended December 31, 2003.
During the year ended December 31, 2005, approximately $5,300,000 of unproved
lease costs related primarily to expiring acreage in Wyoming was reclassified to
proved property. 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.
36
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
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 different 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,
--------------------------------------------
2005 2004 2003
---- ---- ----
Natural gas production (Mcf) 1,648,870 505,967 257,035
Average sales price per Mcf $ 8.16 $ 5.79 $ 4.69
Oil production (Bbl) 10,636 5,080 1,988
Average sales price per Bbl $56.91 $38.43 $28.52
2005 Compared to 2004
Oil and gas revenue increased $10,944,419 during 2005 compared with 2004 due to
an increase in oil and gas production of 5,556 bbls and 1,142,903 Mcf combined
with an increase in the average oil and gas prices of $18.48 per bbl and $2.37
per Mcf during 2005. The $10,944,419 increase in oil and gas revenue during 2005
is comprised of $9,650,353 related to the production increase and $1,294,066
related to the price increase. The production increase is due to the Company's
drilling, completion and recompletion activity during 2004 and 2005 and is
partially offset by the production decrease resulting from the Company's
disposition of approximately 50% of its revenue interest in two wells during the
first quarter of 2004 in accordance with its service party arrangements as
discussed above and by normal production declines on all wells.
The Company recognized gathering income of $1,411,259 and gathering expense of
$1,166,841 during 2005 which represents the income earned from third party gas
gathering and compression and expenses incurred from the Riverbend area pipeline
that was constructed by the Company during 2004. The increase in this revenue
and expense from 2004 is due to the full year of activity during 2005 as well as
the increased production as described above.
Interest income increased $1,058,858 during 2005 compared 2004 primarily due to
higher average cash and cash equivalent and short-term investment balances
during 2005 relating primarily to proceeds from the Company's $65,000,000
Convertible Note issuance during October 2004 and the proceeds from the common
stock offering during November 2005.
37
Lease operating expense increased $232,326 during 2005 compared with 2004
primarily due to the increased number of producing wells during 2005.
Depletion, depreciation and amortization expense during 2005 is comprised of
$4,772,000 of depletion expense related to the Company's proved oil and gas
properties, $57,403 of depreciation expense related to the Company's equipment,
furniture, fixtures and other assets and $14,036 of accretion expense related
the Company's asset retirement obligation. The corresponding expense during 2004
consists of $1,025,100 of depletion expense, $60,812 of depreciation expense and
$16,663 of accretion expense. The increase in depletion expense during 2005 as
compared with 2004 is due primarily to the increase in production and related
costs resulting from the Company's increased drilling and completion activity
discussed above.
General and administrative expense increased by $1,795,041 during 2005 as
compared with 2004, primarily due to the Company's increased operational
activity. The increase in these expenses is comprised of approximately $855,000
in salary expense and consulting fees associated with our increased operational
activity, $355,000 in fees associated with the Company's audit of internal
controls as required under the Sarbanes Oxley Act of 2002 and $525,000 in stock
based compensation primarily related to the Company's restricted stock issuance
and the issuance of stock options to consultants. The remaining increase in
general and administrative expenses is due to the fluctuation in numerous other
expenses, none of which are individually significant.
Interest expense during 2005 consists of interest expense related to the
Company's outstanding Convertible Notes which were issued on October 20, 2004.
Interest expense during 2004 consists of the interest on the Company's
outstanding Convertible Debentures that were converted into common stock during
October 2004 and interest on the Convertible Notes for approximately two months.
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 $1,860,445 increase
in oil and gas revenue during 2004 is comprised of $1,558,355 related to the
production increase and $302,090 related to the price increase. 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.
38
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
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 consisted 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
consisted 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.
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 the first fiscal year 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.
39
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 January 1, 2006. 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 is currently evaluating the impact of this new
standard and estimates that the adoption SFAS No. 123(R) will have an effect on
the financial statements similar to the pro-forma effects reported in Note 2 of
the accompanying financial statements.
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.
In March 2005, the FASB issued Interpretation (FIN)
No. 47, "Accounting for Conditional Asset Retirement Obligations -- An
Interpretation of SFAS No. 143", which clarifies the term "conditional asset
retirement obligation" used in SFAS No. 143, "Accounting for Asset Retirement
Obligations", and specifically when an entity would have sufficient information
to reasonably estimate the fair value of an asset retirement obligation. The
adoption did not have an impact on the company's financial statements.
In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets,
which changes the guidance in APB 29, Accounting for Nonmonetary Transactions.
This Statement amends APB 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. We do not
believe the adoption of SFAS 153 will have a material impact on our financial
statements.
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections", which replaces Accounting Principles Board Opinion No. 20,
Accounting Changes and SFAS No. 3. SFAS 154 provides guidance on the accounting
for and reporting of accounting changes and error corrections. It establishes
retrospective application, or the latest practicable date, as the required
method for reporting a change in accounting principle and the reporting of a
40
correction of an error. SFAS 154 is effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
The Company does not expect that the adoption of SFAS No. 154 will have an
impact on the Company's financial statements.
Off Balance Sheet Arrangements
The Company has no off balance sheet arrangements.
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 AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firms 43-44
Consolidated Balance Sheets at December 31, 2005 and 2004 45-46
Consolidated Statements of Operations for the Years Ended
December 31, 2005, 2004 and 2003 47
Consolidated Statements of Stockholders' Equity for the Years
Ended December 31, 2005, 2004 and 2003 48
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2005, 2004 and 2003 49
Notes to Consolidated Financial Statements 50-81
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 sheets of Gasco Energy, Inc. and
subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related
consolidated statements of operations, stockholders' equity and cash flows for
the years ended December 31, 2005 and 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 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. 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 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, 2005 and 2004, and the results of their operations and their cash
flows for the years ended December 31, 2005 and 2004, in conformity with U.S.
generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
and subsidiaries' internal control over financial reporting as of December 31,
2005, based on criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO) and our report dated March 1, 2006 expressed an unqualified opinion
on management's assessment of the effectiveness of the Company's internal
control over financial reporting and an unqualified opinion on the effectiveness
of the Company's internal control over financial reporting.
/s/ Hein & Associates LLP
Denver, Colorado
March 1, 2006
43
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Gasco Energy, Inc.:
We have audited the accompanying consolidated statements of operations,
stockholders' equity, and cash flows of Gasco Energy, Inc. (the "Company") and
its subsidiaries for the year 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 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. 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 audit provides a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the results of operations and cash flows of the Company for
the year 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,
------------------------------------
2005 2004
ASSETS
CURRENT ASSETS
Cash and cash equivalents $62,661,368 $25,717,081
Restricted investment 10,139,000 3,535,055
Short-term investments 15,000,000 27,000,000
Accounts receivable
Joint interest billings 1,792,038 429,779
Revenue 3,115,154 615,265
Inventory 1,182,982 1,009,914
Prepaid expenses 645,554 458,555
----------- -----------
Total 94,536,096 58,765,649
----------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests 83,972,300 29,811,483
Unproved mineral interests 13,323,712 18,449,330
Gathering assets 4,831,050 2,469,580
Equipment 5,148,388 89,900
Furniture, fixtures and other 175,607 158,590
----------- ----------
Total 107,451,057 50,978,883
----------- ----------
Less accumulated depreciation, depletion and amortization (6,986,662) (2,247,032)
----------- -----------
Total 100,464,395 48,731,851
------------ ----------
NON-CURRENT ASSETS
Restricted investment 3,565,020 6,778,040
Deferred financing costs 2,634,461 3,092,628
--------- ---------
6,199,481 9,870,668
--------- ---------
TOTAL ASSETS $ 201,199,972 $ 117,368,168
============= =============
The accompanying notes are an integral part of the
consolidated financial statements.
45
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
December 31,
-------------------------------------
2005 2004
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 907,772 $ 1,447,149
Revenue payable 1,658,141 334,765
Advances from joint interest owners 2,476,080 891,999
Accrued interest 844,098 695,139
Accrued expenses 2,571,047 2,677,352
---------- ----------
Total 8,457,138 6,046,404
---------- ---------
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes 65,000,000 65,000,000
Asset retirement obligation 223,947 108,566
Deferred rent expense 78,727 -
---------- ----------
Total 65,302,674 65,108,566
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTES 5, 13, 14)
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock - $.001 par value; 20,000 shares
authorized; 763 shares issued and outstanding with a liquidation preference
of $335,720 in 2005 and 2,255 shares issued and
outstanding with a liquidation preference of $992,200 in 2004 1 2
Common stock - $.0001 par value; 300,000,000 shares authorized;
85,041,492 shares issued and 84,967,792 outstanding in 2005;
70,590,909 shares issued and 70,517,209 shares outstanding in 2004 8,504 7,059
Additional paid in capital 157,540,755 76,346,463
Deferred compensation (443,579) (512,440)
Accumulated deficit (29,535,226) (29,497,591)
Less cost of treasury stock of 73,700 common shares (130,295) (130,295)
------------ -----------
Total 127,440,160 46,213,198
------------ ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 201,199,972 $ 117,368,168
=============- =============
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,
-------------------------------------------------
2005 2004 2003
REVENUES
Gas $ 13,462,977 $ 2,928,689 $ 1,206,741
Oil 605,330 195,199 56,702
Gathering 1,411,259 143,326 -
Interest income 1,383,859 325,001 11,987
---------- --------- ---------
Total 16,863,425 3,592,215 1,275,430
---------- --------- ---------
OPERATING EXPENSES
Lease operating 870,593 638,267 337,278
Gathering operations 1,166,841 267,450 -
Depletion, depreciation, amortization and asset retirement
liability accretion 4,843,439 1,102,575 552,923
General and administrative 5,987,019 4,191,978 2,819,675
Interest expense 4,033,168 1,597,775 82,392
---------- --------- ---------
Total 16,901,060 7,798,045 3,792,268
---------- --------- ---------
LOSS BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE (37,635) (4,205,830) (2,516,838)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE - - (9,687)
----------- ---------- ---------
NET LOSS (37,635) (4,205,830) (2,526,525)
Preferred stock dividends (33,347) (140,853) (304,172)
---------- ----------- -----------
NET LOSS ATTRIBUTABLE TO COMMON
STOCKHOLDERS $ (70,982) $ (4,346,683) $ (2,830,697)
=========== ============= =============
PER COMMON SHARE DATA - BASIC AND DILUTED:
Loss before cumulative effect of change in accounting principle $ (0.00) $ (0.07) $ (0.07)
Cumulative effect of change in accounting principle - - -
--------- -------- ------
NET LOSS PER COMMON SHARE - BASIC AND DILUTED $ (0.00) $ (0.07) $ (0.07)
========= ========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED 72,152,977 63,194,223 41,262,778
============= ============= ===========
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, 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
Issuance of common stock 12,929,516 1,293 79,449,446 (172,773) 79,277,966
Conversion of preferred
shares to common shares (1,492) (1) 937,827 94 (93) -
Exercise of common stock
options 583,240 58 1,275,685 1,275,743
Amortization of deferred
compensation 502,601 241,634 744,235
Dividends paid (33,347) (33,347)
Net loss (37,635) (37,635)
----- ------ ---------- ------ --------- -------- ----------- ------- ----------
Balance December 31, 2005 763 $ 1 85,041,492 $ 8,504 $157,540,755 $(443,579) $ (29,535,226) $ (130,295) $ 127,440,160
=== ==== ========== ======= ============ ========== ============== =========== =============
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,
-------------------------------------------------
2005 2004 2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $ (37,635) $(4,205,830) $(2,526,525)
Adjustment to reconcile net loss to net cash used in operating activities
Depreciation, depletion and impairment expense 4,829,403 1,085,912 541,128
Accretion of asset retirement obligation 14,036 16,663 11,795
Stock compensation 744,235 415,483 94,317
Non-cash rent expense 48,727
Landlord incentive payment 30,000
Amortization of beneficial conversion feature - 161,514 6,945
Amortization of deferred financing costs 458,167 294,993 7,758
Cumulative effect of change in accounting principle - - 9,687
Changes in operating assets and liabilities:
Accounts receivable (3,862,148) (545,681) (403,219)
Inventory (173,068) (1,009,914) -
Prepaid expenses (186,999) 59,992 (320,059)
Accounts payable (679,797) (600,723) 164,303
Revenue payable 1,323,376 91,252 185,215
Advances from joint interest owners 1,584,081 891,999 -
Accrued interest 148,959 695,139 -
Accrued expenses (2,106,305) 1,743,832 36,741
----------- ---------- ---------
Net cash provided by (used in) operating activities 2,135,032 (905,369) (2,191,914)
--------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisitions, development and exploration 55,181,914) (25,736,066) (5,283,426)
Cash paid for furniture, fixtures and other (106,790) (64,053) (3,264)
Proceeds from property sales 828,102 4,463,161 -
Investment in short-term investments - (27,000,000) -
Proceeds from the sale of short term investments 12,000,000 - -
Cash designated as restricted (6,816,967) (10,313,095) (250,000)
Cash undesignated as restricted 3,426,042 250,000 250,000
----------- ----------- -----------
Net cash used in investing activities (45,851,527) (58,400,053) (5,286,690)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of common stock 79,693,764 21,500,001 2,777,292
Issuance of convertible notes - 65,000,000 -
Exercise of options to purchase common stock 1,275,743 33,336 -
Cash paid for offering costs (275,378) (4,636,828) (266,721)
Preferred dividends (33,347) (61,973) (4,092)
Proceeds from sale of preferred stock - - 4,862,840
Proceeds from sale of convertible debentures - - 2,500,000
Repayment of note payable - - (1,400,000)
Proceeds from 16b violation - 106,858 1,332
---------- ---------- ---------
Net cash provided by financing activities 80,660,782 81,941,394 8,470,651
---------- ---------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS 36,944,287 22,635,972 992,047
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 25,717,081 3,081,109 2,089,062
---------- ----------- ---------
END OF PERIOD $62,661,368 $25,717,081 $ 3,081,109
=========== =========== ===========
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, 2005, 2004 AND 2003
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. "Our", "we", and "us" as used
herein also refer to Gasco Energy, Inc.
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, 2005 is comprised of
$7,140,020 invested in U.S. government securities in an amount sufficient to
provide for the payment of four semi-annual scheduled interest payments on the
Company's outstanding 5.5% Convertible Notes ("Notes"), as further described in
Note 8, and $6,564,000 of cash invested in cash equivalents as collateral for a
one year letter of credit. The letter of credit was obtained in connection with
one of the Company's long-term rig contracts. The current portion of restricted
investment represents the interest payments that are due within one year and the
collateral for the letter of credit. 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, 2004 consisted of funds invested in U.S.
government securities that provided for payment of six interest payments on the
Company's outstanding Notes.
Short-term Investments
The Company's short-term investments consist primarily of preferred auction rate
securities, which are classified as available-for-sale. Preferred auction rate
securities represent preferred shares issued by closed end funds and are
typically traded at auctions that are held periodically where the dividend rate
for the next period is set. The Company invests in AAA/Aaa rated preferred
auctions that have a dividend rate period of 28 days or less. These securities
50
are stated at fair value based on quoted market prices. The income earned on
these investments is included in interest income in the accompanying financial
statements.
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.
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.
During December 2005, Gasco purchased a drilling rig for approximately
$5,000,000. The rig and the other oil and gas equipment owned by the Company is
depreciated using the straight-line method over the useful life of the
equipment.
51
Gathering Assets
Gathering assets are comprised of 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 the year ended December 31, 2005 approximately
$5,300,000 of unproved lease costs related primarily to expiring acreage in
Wyoming was reclassified to proved property. Other than oil and gas properties
and a drilling rig, the Company has no other long-lived assets and to date has
not recognized any impairment losses.
Deferred Financing Costs
Deferred financing costs consist of the costs associated with the Company's
issuance of $65,000,000 of Notes during October 2004, as further described in
Note 8. These costs are being amortized over the seven-year life of the Notes.
The Company recorded amortization expense of $458,167 and $294,993 related to
these costs during the years ended December 31, 2005 and 2004, respectively.
Asset Retirement Obligation
The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations,
" which requires 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 increase
in carrying value of a property associated with the capitalization of an asset
retirement cost is included in proved oil and gas properties in the consolidated
balance sheets. The Company depletes the amount added to proved oil and gas
property costs. The future cash outflows associated with settling the asset
retirement obligations that have been accrued in the accompanying balance sheets
are excluded from the ceiling test calculations. The Company also depletes the
estimated dismantlement and abandonment costs, net of salvage values, associated
with future development activities that have not yet been capitalized as asset
retirement obligations. These costs are also included in the ceiling test
calculation. 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
for the periods presented.
52
Year Ended December 31,
2005 2004
Balance beginning of period $108,566 $142,806
Liabilities incurred 123,190 29,394
Liabilities settled (21,845) (25,188)
Revisions in estimated cash flows - (55,109)
Accretion expense 14,036 16,663
--------- ---------
Balance end of period $ 223,947 $ 108,566
========== =========
The revisions in estimated cash flows during 2004 was 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.
Revenue Recognition
The Company records revenues from the sales of natural gas and crude oil
recognized as income when the production is produced and sold. The Company may
have an interest with other producers in certain properties, in which case the
Company uses the sales method to account for gas imbalances. Under this method,
revenue is recorded on the basis of gas actually sold by the Company. In
addition, the Company records revenue for its share of gas sold by other owners
that cannot be volumetrically balanced in the future due to insufficient
remaining reserves. The Company also reduces revenue for other owners' gas sold
by the Company that cannot be volumetrically balanced in the future due to
insufficient remaining reserves. The Company's remaining over- and
under-produced gas balancing positions are considered in the Company's proved
oil and gas reserves. Gas imbalances at December 31, 2004 and 2005 were not
significant.
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"), the 5.5% Convertible
Senior Notes due 2001 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.
53
As of December 31, 2005, we had 84,967,792 shares of common stock outstanding.
As of such date, there were 9,292,267 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 3,237,612 shares
of common stock under our stock option plan and an additional 155,450 shares of
common stock are issuable under our restricted stock plan. As of December 31,
2005, 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.
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 101,217,792 shares (this number assumes no
exercise of the options or rights described above or conversion of the Series B
Convertible Preferred Stock).
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 its
production; therefore, the loss of its significant customer would not adversely
affect the Company's operations. For the years ended December 31, 2005, 2004 and
2003, purchases by the following company exceeded 10% of the total oil and gas
revenues of the Company.
For the Year Ended December 31,
--------------------------------------
2005 2004 2003
---- ---- ----
ConocoPhillips Company 96% 93% 93%
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, 2005 and 2004, the market value of the Company's
short-term investments approximates its cost basis and therefore, there were no
unrealized gains and losses included in other comprehensive income during 2005
or 2004.
The Company does not have any other items of other comprehensive income for the
years ended December 31, 2005, 2004 and 2003. 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, 2005, 2004 and 2003 would have been increased
to the pro forma amounts indicated below:
For the Year Ended December 31,
2005 2004 2003
---- ---- ----
Net loss attributable to common shareholders:
As reported $ (70,982) $ (4,346,683) $ (2,830,697)
Add: Stock-base employee compensation
included in net loss (a) 344,873 312,243 41,484
Less: Stock based employee compensation
determined under the fair value based method 2,920,997 757,294 742,211
----------- ----------- ------------
Pro forma $(2,647,106) $(4,791,734) $(3,531,424)
============ ============ ============
Net loss per common share:
As reported $ (0.00) $ (0.07) $ (0.07)
======== ======== ========
Pro forma $ (0.04) $ (0.08) $ (0.09)
======== ======== ========
55
(a) Represents the compensation expense associated with the Company's
restricted stock awards, further described in Note 9.
The fair value of the common stock options granted during 2005, 2004 and 2003,
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,
-----------------------------------------
2005 2004 2003
---- ---- ----
Expected dividend yield -- -- --
Expected price volatility 75 - 79% 79 - 87% 82%
Risk-free interest rate 3.7 - 3.9% 3.2 - 3.9% 2.9%
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 8. 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 the first fiscal year 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 January 1, 2006. 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 is currently evaluating the impact of this new
standard and estimates that the adoption SFAS No. 123(R) will have an effect on
the financial statements similar to the pro-forma effects reported in the Stock
Based Compensation disclosure above.
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.
In March 2005, the FASB issued Interpretation (FIN) No. 47, "Accounting for
Conditional Asset Retirement Obligations -- An Interpretation of SFAS No. 143",
which clarifies the term "conditional asset retirement obligation" used in SFAS
No. 143, "Accounting for Asset Retirement Obligations", and specifically when an
entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation. The adoption did not have an impact on the
company's financial statements.
In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets,
which changes the guidance in APB 29, Accounting for Nonmonetary Transactions.
This Statement amends APB 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. We do not
believe the adoption of SFAS 153 will have a material impact on our financial
statements.
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections", which replaces Accounting Principles Board Opinion No. 20,
Accounting Changes and SFAS No. 3. SFAS 154 provides guidance on the accounting
for and reporting of accounting changes and error corrections. It establishes
57
retrospective application, or the latest practicable date, as the required
method for reporting a change in accounting principle and the reporting of a
correction of an error. SFAS 154 is effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
The Company does not expect that the adoption of SFAS No. 154 will have an
impact on the Company's financial statements.
Off Balance Sheet Arrangements
The Company has no off balance sheet arrangements.
Reclassifications
Certain reclassifications have been made to prior years' amounts to conform to
the classifications used in the current year. Such reclassifications had no
effect on the Company's net loss in any of the periods presented.
NOTE 3 - CONSOLIDATING FINANCIAL STATEMENTS
On September 23, 2005, Gasco filed a Form S-3 shelf registration statement with
the Securities Exchange Commission which was subsequently amended in a Form
S-3/A that was filed on October 27, 2005. Under this registration statement,
which was declared effective on November 1, 2005, we may from time to time offer
and sell common stock, preferred stock, depositary shares and debt securities
that may be fully, irrevocably and unconditionally guaranteed by all of our
subsidiaries: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend
Gas Gathering, LLC and Myton Oilfield Rentals, LLC ("Guarantor Subsidiaries").
Set forth below are the condensed consolidating financial statements of Gasco,
the parent, and the Guarantor Subsidiaries.
58
Condensed Consolidating Balance Sheet
As of December 31, 2005
(Unaudited)
Guarantor
Parent Subsidiaries Eliminations Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 59,314,343 $3,347,025 $ - $ 62,661,368
Restricted investment 10,139,000 - - 10,139,000
Short-term investments 15,000,000 - - 15,000,000
Accounts receivable - 4,907,192 - 4,907,192
Inventory - 1,182,982 - 1,182,982
Prepaid expenses 645,229 325 - 645,554
---------- --------- ----------- ----------
Total 85,098,572 9,437,524 94,536,096
---------- --------- ------------ ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests - 83,972,300 - 83,972,300
Unproved mineral interests 274,540 13,049,172 - 13,323,712
Gathering assets - 4,831,050 - 4,831,050
Equipment - 5,148,388 - 5,148,388
Furniture, fixtures and other 175,607 - - 175,607
--------- ------------ ------------ -----------
Total 450,147 107,000,910 - 107,451,057
--------- ----------- ------------ -----------
Less accumulated depreciation, depletion and amortization (46,064) (6,940,598) - (6,986,662)
--------- ----------- ------------ -----------
Total 404,083 100,060,312 - 100,464,395
--------- ----------- ------------ -----------
OTHER ASSETS
Restricted investment 3,565,020 - - 3,565,020
Deferred financing costs 2,634,461 2,634,461
Intercompany 103,081,444 (103,081,444) - -
----------- ------------- ----------- -----------
Total 109,280,925 (103,081,444) 6,199,481
----------- ------------- ----------- ---------
TOTAL ASSETS $ 194,783,580 $ 6,416,392 - $201,199,972
============= ================ ===========- ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 661,307 $ 246,465 $ - $ 907,772
Revenue payable - 1,658,141 - 1,658,141
Advances from joint interest owners - 2,476,080 - 2,476,080
Accrued interest 844,098 - - 844,098
Accrued expenses 507,066 2,063,981 - 2,571,047
---------- --------- ------ ---------
Total 2,012,471 6,444,667 - 8,457,138
---------- --------- ------ ---------
NONCURRENT LIABILITES
5.5% Convertible Senior Notes 65,000,000 - - 65,000,000
Asset retirement obligation - 223,947 - 223,947
Deferred rent expense 78,727 - - 78,727
---------- -------- ------ ----------
Total 65,078,727 223,947 65,302,674
---------- -------- ------ ----------
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock 1 - - 1
Common stock 8,504 - - 8,504
Other 127,683,877 (252,222) - 127,431,655
----------- --------- ------ -----------
Total 127,692,382 (252,222) - 127,440,160
----------- --------- ------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $194,783,580 $ 6,416,392 $ - $ 201,199,972
============ ============= ====== =============
59
Condensed Consolidating Balance Sheet
As of December 31, 2004
(Unaudited)
Guarantor
Parent Subsidiaries Eliminations Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 23,357,073 $2,360,008 - $ 25,717,081
Restricted investment 3,535,055 - 3,535,055
Short-term investments 27,000,000 - - 27,000,000
Accounts receivable - 1,045,044 - 1,045,044
Inventory - 1,009,914 - 1,009,914
Prepaid expenses 458,555 458,555
----------- ----------- ------------ -----------
Total 53,892,128 4,873,521 58,765,649
---------- ---------- ------------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests - 29,811,483 - 29,811,483
Unproved mineral interests 274,540 18,174,790 - 18,449,330
Gathering assets - 2,469,580 - 2,469,580
Equipment - 89,900 - 89,900
Furniture, fixtures and other 158,590 158,590
--------- ----------- ----------- -----------
Total 433,130 50,545,753 50,978,883
--------- ---------- ---------- ----------
Less accumulated depreciation, depletion and amortization (90,189) (2,156,843) (2,247,032)
--------- ----------- ---------- -----------
Total 342,941 48,388,910 48,731,851
--------- ---------- -----------
OTHER ASSETS
Restricted investment 6,778,040 - - 6,778,040
Deferred financing costs 3,092,628 3,092,628
Intercompany 57,098,600 (57,098,600) - -
---------- ------------ ----------- ----------
Total 66,969,268 (57,098,600) 9,870,668
------------- ------------ ----------- ---------
TOTAL ASSETS $ 121,204,337 $ (3,836,169) $ - $ 117,368,168
============== ============= ========= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $274,269 $ 1,172,880 $ - $ 1,447,149
Revenue payable - 334,765 - 334,765
Advances from joint interest owners - 891,999 - 891,999
Accrued interest 695,139 - - 695,139
Accrued expenses 755,139 1,922,213 - 2,677,352
--------- --------- -------- ---------
Total 1,724,547 4,321,857 - 6,046,404
---------- --------- -------- ---------
NONCURRENT LIABILITES
5.5% Convertible Senior Notes 65,000,000 - - 65,000,000
Asset retirement obligation - 108,566 - 108,566
----------- ------- ------- ----------
Total 65,000,000 108,566 - 65,108,566
---------- ------- ------- ----------
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock 2 - - 2
Common stock 7,059 - - 7,059
Other 54,472,729 (8,266,592) - 46,206,137
---------- ----------- ---------- ----------
Total 54,479,790 (8,266,592) - 46,213,198
---------- ----------- ----------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $ 121,204,337 $(3,836,169) $ - $ 117,368,168
============= ============ ======= =============
60
Consolidating Statements of Operations
For the Year Ended December 31, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 14,068,307 $ - $ 14,068,307
Gathering - 2,258,206 (846,947) 1,411,259
Interest income 1,383,740 119 - 1,383,859
--------- ---------- ---------- ----------
Total 1,383,740 16,326,632 (846,947) 16,863,425
--------- ---------- --------- ----------
OPERATING EXPENSES
Lease operating - 1,717,540 (846,947) 870,593
Gathering operations - 1,166,841 - 1,166,841
Depletion, depreciation and amortization 45,648 4,797,791 - 4,843,439
General and administrative 5,987,019 - - 5,987,019
Interest expense 4,033,168 - - 4,033,168
--------- --------- -------- ---------
Total 10,065,835 7,682,172 (846,947) 16,901,060
---------- --------- --------- ----------
NET INCOME (LOSS) (8,682,095) 8,644,460 - (37,635)
Preferred stock dividends (33,347) (33,347)
----------- --------- -------- ---------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (8,715,442) $8,644,460 $ - $ (70,982)
============= ========== ====== ==========
For the Year Ended December 31, 2004 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 3,123,888 $ - $ 3,123,888
Gathering - 143,326 - 143,326
Interest income 324,897 104 325,001
------- --------- ---------- ---------
Total 324,897 3,267,318 - 3,592,215
------- --------- ---------- ---------
OPERATING EXPENSES
Lease operating - 638,267 - 638,267
Gathering operations 267,450 267,450
Depletion, depreciation and amortization 12,132 1,090,443 1,102,575
General and administrative 2,714,031 1,477,947 - 4,191,978
Interest expense 1,597,775 1,597,775
--------- --------- ---------- ---------
Total 4,323,938 3,474,107 7,798,045
--------- --------- ---------- ---------
NET LOSS (3,999,041) (206,789) - (4,205,830)
Preferred stock dividends (140,853) - - (140,853)
---------- -------- ----------- ---------
NET LOSS ATTRIBUTABLE TO
COMMON STOCKHOLDERS $(4,139,894) $ (206,789) $ - $(4,346,683)
============ =============== ======= ============
61
Consolidating Statements of Operations
For the Year Ended December 31, 2003 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 1,263,443 $ - $ 1,263,443
Interest income 11,836 151 - 11,987
-------- --------- ------ ---------
Total 11,836 1,263,594 - 1,275,430
-------- --------- ------ ---------
OPERATING EXPENSES
Lease operating - 337,278 - 337,278
Depletion, depreciation and amortization - 552,923 - 552,923
General and administrative 1,357,126 1,462,549 - 2,819,675
Interest expense 1,750 80,642 - 82,392
--------- --------- ------ ---------
Total 1,358,876 2,433,392 - 3,792,268
--------- --------- ------ ---------
NET LOSS BEFORE CHANGE IN ACCOUNTING
PRINCIPLE (1,347,040) (1,169,798) - (2,516,838)
Cumulative effect of change in accounting principle - (9,687) - (9,687)
----------- ----------- -------- ----------
NET LOSS (1,347,040) (1,179,485) - (2,526,525)
Preferred stock dividends (304,172) - (304,172)
----------- ---------- ----- ------------
NET LOSS ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (1,651,212) $ (1,179,485) $ - $ (2,830,697)
============= ============= ========= ===========
62
Consolidating Statements of Cash Flows
For the Year Ended December 31, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES (7,222,953) $9,357,985 $ - $2,135,032
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (106,790) - - (106,790)
Cash paid for acquisitions, development and exploration - (55,181,914) - (55,181,914)
Proceeds from property sales - 828,102 - 828,102
Proceeds from sale of short-term investments 12,000,000 - - 12,000,000
Cash designated as restricted (6,816,967) - - (6,816,967)
Cash undesignated as restricted 3,426,042 3,426,042
---------- ------------- ----------- ----------
Net cash provided by (used) in investing activities 8,502,285 (54,353,812) (45,851,527)
--------- ------------ ----------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the sale of common stock 79,693,764 79,693,764
Preferred dividends (33,347) - - (33,347)
Cash paid for offering costs (275,378) - - (275,378)
Exercise of options to purchase common stock 1,275,743 - - 1,275,743
Intercompany (45,982,844) 45,982,844 - -
------------ ------------ --------- ---------
Net cash provided by financing activities 34,677,938 45,982,844 - 80,660,782
------------ ---------- --------- ----------
NET INCREASE IN CASH AND CASH
EQUIVALENTS 35,957,270 987,017 36,944,287
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 23,357,073 2,360,008 - 25,717,081
---------- --------- --------- ----------
END OF PERIOD $ 59,314,343 $ 3,347,025 $ $62,661,368
============ =========== ======== ===========
For the Year Ended December 31, 2004 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES $(456,645) $ (448,724) $ $ (905,369)
-
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (64,053) - - (64,053)
Cash paid for acquisitions, development and exploration - (25,736,066) - (25,736,066)
Proceeds from property sales - 4,463,161 - 4,463,161
Investment in short-term investments (27,000,000) - - (27,000,000)
Cash designated as restricted (10,313,095) - - (10,313,095)
Cash undesignated as restricted 250,000 - - 250,000
----------- ------------ ------ -----------
Net cash used in investing activities (37,127,148) (21,272,905) - (58,400,053)
------------ ----------------- ------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of convertible notes 65,000,000 - - 65,000,000
Preferred dividends (61,973) - - (61,973)
Exercise of options to purchase common stock 33,336 - - 33,336
Proceeds from sale of common stock 21,500,001 - - 21,500,001
Cash paid for offering costs (4,636,828) - - (4,636,828)
Proceeds from 16b violation 106,858 - - 106,858
Intercompany (23,700,657) 23,700,657 - -
------------ ---------- -------- ---------
Net cash provided by financing activities 58,240,737 23,700,657 81,941,394
------------ ---------- ------- ----------
NET INCREASE IN CASH AND CASH
EQUIVALENTS 20,656,944 1,979,028 - 22,635,972
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 2,700,129 380,980 - 3,081,109
--------- --------- --------- ---------
END OF PERIOD $23,357,073 $ 2,360,008 $ - $ 25,717,081
=========== =========== ======== ============
63
Consolidating Statements of Cash Flows
For the Year Ended December 31, 2003 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES $ (3,698,768) $1,506,854 $ - $(2,191,914)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (3,264) - - (3,264)
Cash paid for acquisitions, development and exploration - (5,283,426) - (5,283,426)
Cash designated as restricted (250,000) - - (250,000)
Cash undesignated as restricted 250,000 250,000
--------- -------------- ---------- ----------
Net cash used in investing activities (3,264) (5,283,426) - (5,286,690)
---------- ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the sale of common stock 2,777,292 2,777,292
Preferred dividends (4,092) - - (4,092)
Cash paid for offering costs (266,721) - - (266,721)
Proceeds from the sale of preferred stock 4,862,840 - - 4,862,840
Proceeds from the sale of convertible debentures 2,500,000 - - 2,500,000
Repayment of note payable (1,400,000) - - (1,400,000)
Proceeds from 16b violation 1,332 - - 1,332
Intercompany (3,891,515) 3,891,515 - -
----------- --------- --------- -----------
Net cash provided by financing activities 4,579,136 3,891,515 - 8,470,651
----------- --------- ----------- -----------
NET INCREASE IN CASH AND CASH
EQUIVALENTS 877,104 114,943 992,047
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 1,823,025 266,037 - 2,089,062
--------- --------- --------- ---------
END OF PERIOD $2,700,129 $ 380,980 $ - $ 3,081,109
========== ========= ========= ===========
NOTE 4 - 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,
----------------------------------------------------
2005 2004 2003
-------------------------------- -------------------
Property acquisition costs:
Unproved $ 410,062 $ 5,021,126 $667,557
Proved -- 723,9012 --
Exploration costs (a) 1,064,874 216,165 396,967
Development costs 48,595,032 17,501,716 4,218,9024
---------- --------- ----------
Total including asset retirement obligation 50,069,968 23,462,908 5,283,426
========== ============ ===========
Total excluding asset retirement obligation $49,968,623 $ 23,398,559 $ 5,168,174
=========== ============ ===========
Depletion and impairment expense related to proved properties per equivalent Mcf
of production for the years ended December 31, 2005, 2004 and 2003 was $2.83,
$2.06 and $2.06, respectively.
64
At December 31, the Company's unproved properties consist of leasehold costs in
the following areas:
2005 2004
---- ----
Utah $ 3,040,717 $ 5,950,861
Wyoming 9,779,223 12,312,742
California 313,586 185,727
Nevada 190,186 -
----------- -----------
$13,323,712 $18,449,330
=========== ===========
During 2005, approximately $5,300,000 of unproved lease costs related primarily
to expiring acreage in Wyoming was reclassified to proved property. These costs
became subject to amortization during the fourth quarter of 2005.
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
2005 (5,125,618)
-----------
Unproved Mineral Interest as of
December 31, 2005 $ 13,323,712
============
The Company's drilling activities are located primarily in the Riverbend Area of
Utah, and the Company plans to drill approximately 32 gross (15 net) wells in
this area during 2006. The Company also plans to drill up to three wells in
Wyoming during 2006 and continues to consider several additional options for its
Wyoming acreage such as the farm-out of some of its acreage and other similar
type arrangements. The Company entered into a farm-out agreement under which an
unrelated entity has committed to drill one well on its acreage in California.
Under this agreement, Gasco will contribute the acreage and the unrelated entity
will pay the drilling and completion costs. Gasco will retain a 25% interest if
the well is successful.
NOTE 5 - PROPERTY ACQUISITIONS
During December 2005, Gasco purchased a rig for approximately $5,000,000. Gasco
entered into a one-year drilling contract with an unrelated third party who will
operate the rig. The operator may buy the rig from Gasco at the fair market
value of the rig within three years of when the rig is delivered. This rig is
scheduled to be moved on location in our Riverbend Project to begin drilling
early in the second quarter of 2006. With the addition of this rig, Gasco will
have four rigs drilling in the Riverbend Project during most of 2006. Also,
65
during December 2005, we entered into a three-year contract for a new-build rig
to be delivered in December 2006. In connection with this contract we provided
the rig owner a letter of credit from our bank for $6,564,000. The cash
collateral for this letter of credit is reflected as a restricted investment in
the accompanying financial statements.
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, 2003. The results for the
year ended December 31, 2005 are the same as the actual results.
For the Years Ended December 31,
2004 2003
---- ----
Revenue $ 3,742,586 $2,363,046
Loss before cumulative effect of
Change in accounting principle (4,136,633) (1,918,451)
Net Loss (4,136,633) (1,928,138)
Net Loss Attributable to Common
Stockholders (4,277,486) (2,232,310)
Net Loss per Common Share - Basic
and Diluted $(0.07) $ (0.05)
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
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 6 - 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. The
development of this project is contemplated to proceed in increments of 10-well
bundles to be approved by the parties on an ongoing basis. To secure its
obligations under the agreement, described above, the Company has pledged its
interests in each of the wells in each bundle.
66
Under these agreements, the service providers have the exclusive right to
provide their services, as long as they are able, in the development of the
Riverbend acreage. Under these agreements, we have 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. The remaining development costs are funded by third
party investors that are also parties to the agreements. Our 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. The drilling of the second bundle commenced late in 2004.
During the fourth quarter of 2005, the Service Parties agreed to proceed with
the third bundle of ten wells.
NOTE 7 - PROPERTY DIVESTITURES
In connection with the Service Parties agreements, described in Note 6, 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 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, 2005 are the same as the actual results.
For the Years 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)
67
NOTE 8 - 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.
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 the most recent interest payment date, and is
payable in cash semi-annually in arrears on April 5th and October 5th of each
year, and commenced 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 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 investment 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
68
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.
Based on the market price of the Company's common stock as of December 31, 2005,
the fair value of the Notes is $106,112,500.
The Notes are due in 2011 and therefore do not have any maturities within the
next five years.
NOTE 9 - STOCKHOLDERS' EQUITY
The Company's capital stock as of December 31, 2005 and 2004 consists of
300,000,000 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, 2005, Gasco had 763
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. All of the preferred
shares were converted by the holders into 479,599 shares of common stock during
January 2006.
During the year ended December 31, 2005, the Company paid $33,347 of cash
dividends to the holders of its Preferred Stock.
Common Stock - Gasco has 85,041,492 shares of Common Stock issued and 84,967,792
shares outstanding as of December 31, 2005. 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 were 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
69
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 2005 and 2004 are
described as follows:
On December 15, 2005, the Company's Board of Directors approved the issuance of
23,700 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
December 15, 2005 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 595,379
unvested shares of restricted stock outstanding as of December 31, 2005. The
compensation expense related to the restricted stock outstanding during year
ended December 31, 2005 was $344,873.
On November 23, 2005, we closed a public offering of 12,500,000 shares of common
stock at a price to the public of $6.50 per share. We also granted the
underwriters a 30-day option to purchase up to 1,875,000 additional shares of
our common stock solely to cover over-allotments. The underwriters exercised
this option for an additional 439,400 shares of common stock and this
transaction was closed on December 6, 2005. The net proceeds from this offering,
after underwriting discount and offering costs were $79,418,386. These proceeds
will be used to fund capital expenditures for the development and exploration of
Gasco's oil and natural gas properties and the development associated
infrastructure, working capital and general corporate purposes.
During 2005, certain holders of the Company's Series B Convertible Preferred
Stock ("Preferred Stock") converted 1,492 shares of Preferred Stock into 937,827
shares of common stock in accordance with the terms of such Preferred Stock.
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.
70
On June 14, 2004, the Company issued of 395,850 shares of common stock, under
the 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.
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.
NOTE 10 - STOCK OPTIONS
During 2005, the Company granted 2,450,000 options to purchase shares of common
stock to its employees, directors and outside consultants at exercise prices
ranging from $3.39 to $7.39 per share. The options issued to the Company's
directors vest 25% at the end of each calendar quarter beginning September 30,
2005 and the remaining options vest 16 2/3% at the end of each four-month period
after the issuance date. All of the options issued expire within ten years from
the grant date.
During 2005 the Company issued 643,083 shares of common stock in connection with
the exercise of options to purchase shares of common stock at strike prices
ranging from $1.00 per common share to $3.91 per common share for total proceeds
of $1,274,743.
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, 2005 options to purchase an aggregate 8,812,667 shares of the
Company's common stock were outstanding. These options were granted during 2005,
2004, 2003, 2002 and 2001 to the Company's employees, directors and consultants
at exercise prices ranging from $1.00 to $7.39 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
71
officer of the Company, of $399,364, $73,705 and $52,833 was charged to
operations during the years ended December 31, 2005, 2004 and 2003,
respectively.
A summary of the options granted to purchase common stock and the changes
therein during the years ended December 31, 2005, 2004 and 2003 is presented
below.
2005 2004 2003
---- ----- ----
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 7,043,250 $ 1.85 5,666,586 $ 2.07 6,355,250 $ 2.17
Granted 2,450,000 3.53 1,410,000 1.98 1,658,000 1.00
Exercised (643,083) 2.16 (33,336) 1.00 - -
Cancelled (37,500) 3.39 - (2,346,664) 2.18
--------- ---- ---------- ----- ----------- ----
Outstanding at end of year 8,812,667 $ 2.29 7,043,250 $ 1.85 5,666,586 $ 1.83
========= ====== ========= ====== ========= ======
Exercisable at December 31, 6,574,281 $ 1.97 5,624,417 $ 1.42 4,476,586 $ 2.07
========= ====== ========= ====== ========= ======
Weighted average fair value of options granted $ 2.25 $ 1.28 $ 0.45
====== ====== ======
Weighted average remaining contractual life of options
Outstanding as of December 31, 2005 6.9 years
====
The following table presents additional information related to the options
outstanding as of December 31, 2005.
Exercise Number of Weighted Average
Price per Number of Shares Shares Remaining Contractual
Share Outstanding Exercisable Life (years)
----- ----------- ---------- --------------
$1.00 2,445,000 2,445,000 6.1
1.61 33,332 16,666 8.1
1.73 100,000 100,000 6.0
1.80 50,000 50,000 5.7
1.92 710,001 464,972 8.6
2.00 1,451,000 1,400,996 6.3
2.15 425,000 283,324 8.6
3.00 450,000 450,000 4.4
3.10 82,500 82,500 0.9
3.15 550,000 550,000 1.4
3.39 2,192,500 579,991 9.4
3.70 120,000 120,000 1.3
3.91 83,334 16,666 9.1
5.18 85,000 14,166 9.6
7.39 35,000 - 10.0
---- --------- --------- ----
Total 8,812,667 6,574,281 6.9
========= ========= ===
72
NOTE 11 - STATEMENT OF CASH FLOWS
During the year ended December 31, 2005, the Company's non-cash investing and
financing activities consisted of the following transactions:
Recognition of an asset retirement obligation for the plugging and
abandonment costs related to the Company's oil and gas properties valued at
$123,190.
Additions to oil and gas properties included in accounts payable and
accrued expenses of $2,007,522.
Reduction in the asset retirement obligation of $21,845 representing the
plugging and abandonment activity during 2005.
Conversion of 1,492 shares of Preferred Stock into 937,827 shares of common
stock.
Write-off of fully depreciated furniture and fixtures of $89,773.
During the year ended December 31, 2004, the Company's non-cash investing and
financing activities consisted of the following transactions:
Conversion of $2,500,000 of Debentures into 4,166,665 shares of common
stock.
Additions to oil and gas properties included in accounts payable and
accrued expenses of $2,556,624.
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.
73
Additions to oil and gas properties included in accounts payable and
accrued expenses of $845,067.
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.
Cash paid for interest was $3,575,000, $463,769 and $82,392 for the years ended
December 31, 2005, 2004 and 2003, respectively. There was no cash paid for
income taxes in any of the years ended December 31, 2005, 2004 and 2003.
NOTE 12 - INCOME TAXES
A provision (benefit) for income taxes for the years ended December 31, 2005,
2004 and 2003 consists of the following:
2005 2004 2003
---- ---- ----
Current taxes:
Federal $ - $ - $ -
State - - -
Deferred taxes:
Federal (189,075) (1,371,000) (2,556,837)
State (783) (157,580) (285,004)
Less: valuation allowance 189,858 1,528,580 2,841,841
------- --------- ---------
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, 2005, 2004 and 2003 is
summarized below:
74
2005 2004 2002
---- ---- ----
Tax provision (benefit) at federal statutory rate $ (13,172) $ (1,429,982) $ (859,019)
State taxes, net of federal tax effects (509) (104,032) (188,102)
Valuation adjustment on assets distributed in
stock redemption - - -
Prior year tax return permanent true-up - - (1,798,941)
Change in Tax Rate from Prior Year (182,551) - -
Other Permanent items 6,374 5,434 4,221
Valuation allowance 189,858 1,528,580 2,841,841
------- --------- --- ---------
Net income tax provision (benefit) $ - $ - $ -
======= ======= =======
The components of the deferred tax assets and liabilities as of December 31,
2005 and 2004 are as follows:
2005 2004
---- ----
Deferred tax assets:
Federal and state net operating loss carryovers $ 12,232,737 $ 7,415,121
Oil and gas property - 133,530
Deferred rent 30,727 -
Deferred compensation 589,306 362,029
---------- ---------
Total deferred tax assets 12,852,770 7,910,680
Less: valuation allowance (8,134,543) (6,935,384)
----------- -----------
4,718,227 975,296
Deferred tax liabilities:
Oil and gas property 2,177,627 -
Other property, plant & equipment 2,327,118 758,796
Other 213,482 216,500
--------- -------
Total deferred tax liabilities 4,718,227 975,296
--------- -------
Net deferred tax asset $ - $ -
========= =======
The Company has a $31,451,525 net operating loss carryover for federal income
tax purposes and a $25,233,976 net operating loss carryover for state income tax
purposes as of December 31, 2005. The net operating losses may offset against
taxable income through the year ended December 31, 2025. A portion of the net
operating loss carryovers begins expiring in 2019. The Company provided a
valuation allowance against its net deferred tax asset of $8,134,543 and
$6,935,384 as of December 31, 2005and 2004 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 13 - 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
75
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").
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.
During the each of years ended December 31, 2005, 2004 and 2003, 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, 2007.
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.
76
NOTE 14 - COMMITMENTS
The Company leases approximately 8,776 square feet of office space in Englewood,
Colorado, under a lease, which terminates on May 31, 2010. The average rent for
this space over the life of the lease is approximately $120,500 per year. The
Company believes that this space will meet its needs for at least the next two
years.
The following table shows the annual rentals per year for the life of the lease.
Year Ending December 31, Annual Rentals
2006 $ 105,844
2007 122,332
2008 129,526
2009 136,719
2010 70,158
Thereafter -
---------
$564,579
========
Rent expense for the years ending December 31, 2005, 2004 and 2003 was $121,648,
$52,822 and $56,970, 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 entered into employment agreements with three key officers through
January 31, 2007. 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.
During 2005 the Company converted two of the three rigs drilling for us from
well-to-well contracts to two-year term contracts. The drilling rate in each of
the contracts is approximately $18,500 per day and both contracts expire in
December 2007. During December 2005, Gasco purchased a rig for approximately
$5,000,000. Gasco entered into a one-year drilling contract with an unrelated
third party who will operate the rig. The operator may buy the rig from Gasco at
the fair market value of the rig within three years of when the rig is
delivered. This rig is scheduled to be moved on location in our Riverbend
Project to begin drilling early in the second quarter of 2006. Gasco entered
into a one-year drilling contract that has a drilling rate of approximately
$18,500 per day with an unrelated third party who will operate the rig. This rig
77
is scheduled to be moved on location in our Riverbend Project to begin drilling
early in the second quarter of 2006. Also, during December 2005, we entered into
a three-year contract with a drilling rate of $21,000 per day for a new-build
rig to be delivered in December 2006. The three year drilling contract for the
new-build rig contains a provision for the Company to terminate the contract for
$12,000 per day for the number days remaining in the original contract. In
connection with this contract we provided the rig owner a letter of credit from
our bank for $6,564,000. The cash collateral for this letter of credit is
reflected as a restricted investment in the accompanying financial statements.
The future contractual obligations under the rig contracts are summarized below:
Annual Drilling Obligations
Year Ending December 31,
2006 $17,542,625
2007 21,641,750
2008 7,665,000
2009 7,665,000
-----------
Total $54,514,375
===========
NOTE 15 - 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 $58,110,
$36,225 and $32,708 during the years ended December 31, 2005, 2004 and 2003,
respectively.
NOTE 16 - SELECTED QUARTERLY INFORMATION (Unaudited)
The following represents selected quarterly financial information for the years
ended December 31, 2005 and 2004.
2005 For the Quarter Ended
----------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
Gross revenue $1,285,347 $2,548,900 $ 4,696,727 $8,458,948
Net revenue from oil
and gas operations 544,115 1,796,945 3,927,771 7,173,301
Net income (loss) (1,700,128) (998,867) 649,303 2,012,057
Net income (loss) per share
basic and diluted (0.02) (0.01) 0.01 0.03
The increase in gross revenue, net revenue from oil and gas operations and net
income is due to the Company's drilling activity during the year as described
above and the increase in average oil and gas prices during 2005. The Company's
78
number of gross producing wells increased from 21 gross producing wells at
December 31, 2004 to 42 gross producing wells at December 31, 2005.
Additionally, the average oil and gas prices increased from $5.79 per mcf and
$38.43 per bbl during 2004 to $8.16 per mcf and $56.91 per bbl during 2005.
2004 For the Quarter Ended
------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
Gross revenue $766,775 $ 810,303 $ 860,390 $1,154,747
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) (0.03)
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.
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, 2005, 2004 and 2003 have been estimated by Netherland, Sewell
and Associates, Inc., independent petroleum engineers. 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, 2005, 2004 and 2003 were $59.87 per
bbl of oil and $8.01 per mcf of gas, $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.
79
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
Extensions and discoveries 49,217,928 222,943
Revisions of previous estimates (c) (12,814,086) (109,093)
Sales of reserves in place - -
Purchases of reserves in place - -
Production (1,648,870) (10,636)
----------- --------
Balance, December 31, 2005 74,455,128 377,288
========== =======
Proved Developed Reserves
Balance, December 31, 2005 18,974,697 111,655
========== =========
Balance, December 31, 2004 8,163,127 69,752
=========== =========
Balance, December 31, 2003 2,937,388 24,818
=========== =========
(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.
(c) The majority of the revisions of previous estimates during 2005 are
comprised of the following:
o Four proved undeveloped locations were omitted from the 2005
reserve report because these locations required a higher capital
investment than originally estimated due to drilling and
completion problems and due to the lack of historical data
related to recent completions and recompletions in this area.
o Six proved undeveloped locations were omitted from the 2005
reserve report because recent drilling activity indicates that
these locations may be outside of or on the edge of a previously
identified zone.
80
o Two proved developed non-producing completions significantly
underperformed previous forecasts.
Standardized Measure of Discounted Future Net Cash Flows
December 31,
-------------------------------------------
2005 2004 2003
---- ---- ----
Future cash flows $ 618,843,800 $ 231,958,400 $ 83,099,200
Future production and development costs (300,991,100) (123,579,100) (32,804,600)
Future income taxes (23,006,800) - -
------------ ------------- -----------
Future net cash flows before discount 294,845,900 108,379,300 50,294,600
----------- ----------- -------------
10% discount to present value (190,224,900) (76,077,700) (34,099,500)
------------- ------------ -------------
Standardized measure of discounted
future net cash flows $ 104,621,000 $ 32,301,600 $16,195,100
============= ============ ===========
Changes in the Standardized Measure of Discounted Future Net Cash Flows
For the Years Ended December 31,
---------------------- --------------------
2005 2004 2003
---- ---- ----
Standardized measure of discounted future net
cash flows at the beginning of year $ 32,301,600 $16,195,100 $12,312,002
Sales of oil and gas produced, net of production
Costs (13,197,714) (2,485,621) (926,165)
Net changes in prices and production costs 28,283,823 (4,045,575) 13,209,650
Extensions and discoveries, net of future
production and development costs 107,380,301 34,439,255 7,250,499
Previously estimated development costs incurred (1,681,163) 17,499,346 4,218,902
Changes in estimated future development costs (34,138,277) (62,687,146) 1,890,021
Revisions of previous quantity estimates (28,607,463) (1,055,871) (2,629,973)
Purchases of reserves in place - 1,654,068 -
Sales of reserves in place - (623,985) (391,020)
Net change in income taxes (3,225,000) - -
Accretion of discount 3,214,885 1,619,510 1,231,200
Changes in production rates and other 14,290,008 31,792,519 (19,970,016)
----------- ------------ ------------
Standardized measure of discounted future net cash flows at
the end of year $ 104,621,000 $ 32,301,600 $16,195,100
============= ============= ===========
81
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A - CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management has evaluated the effectiveness of our disclosure
controls and procedures as of December 31, 2005. Our disclosure controls and
procedures are designed to provide us with a reasonable assurance that the
information required to be disclosed in reports filed with the SEC is recorded,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms. The disclosure controls and procedures are also designed
to provide reasonable assurance that such information is accumulated and
communicated to our management as appropriate to allow such persons to make
timely decisions regarding required disclosures.
Our management does not expect that our disclosure controls and
procedures will prevent all errors and all fraud. The design of a control system
must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Based on the inherent
limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any,
within the Company have been detected. These inherent limitations include the
realities that judgments in decision-making can be faulty and that breakdowns
can occur because of simple errors or mistakes. Additionally, controls can be
circumvented by the individual acts of some persons, by collusion of two or more
people, or by management override of the controls. The design of any system of
controls also is based in part upon certain assumptions about the likelihood of
future events. Therefore, a control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Our disclosure controls and procedures
are designed to provide such reasonable assurances of achieving our desired
control objectives, and our CEO and CFO have concluded, as of December 31, 2005,
that our disclosure controls and procedures are effective in achieving that
level of reasonable assurance.
Changes in internal control over financial reporting during the fourth quarter
of 2005. There have been no changes in our internal controls over financial
reporting (as defined in Rule 13a-15(f) under the Exchange Act) or in other
factors that occurred during the fiscal quarter ended December 31, 2005, that
have materially affected or are reasonably likely to materially affect our
internal controls over financial reporting.
Internal control over financial reporting
Our internal controls over financial reporting are designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of our financial statements in accordance with GAAP. These internal
controls over financial reporting were designed under the supervision of our
management and include policies and procedures that: (i) pertain to the
maintenance of records that in reasonable detail accurately and fairly reflect
the transactions and dispositions of our assets, (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of
82
financial statements in accordance with GAAP, and that our receipts and
expenditures are being made only in accordance with authorizations of our
management and directors and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use or disposition
of our assets that could have a material effect on our financial statements.
In accordance with Item 308 of SEC Regulation S-K, management is
required to provide an annual report regarding internal controls over our
financial reporting. This report, which includes management's assessment of the
effectiveness of our internal controls over financial reporting, is found below.
Management's Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining
adequate internal control over financial reporting as defined in Rules 13a-15(f)
and 15d-15(f) under the Exchange Act. The Company's internal control over
financial reporting is designed, under the supervision of the Company's chief
executive and chief financial officers, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America (GAAP). The
Company's internal control over financial reporting includes those policies and
procedures that: (i) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the
assets of the Company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with GAAP, and that receipts and expenditures of the Company are
being made only in accordance with authorizations of management and directors of
the Company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition of the
Company's assets that could have a material effect on the financial statements.
Because of the inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures my deteriorate.
Management assessed the effectiveness of the Company's internal control
over financial reporting as of December 31, 2005. In making this assessment,
management used the criteria set for by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control-Integrated
Framework.
Based on our assessment and those criteria, management believes that the
Company maintained effective internal control over financial reporting as of
December 31, 2005.
The Company's assessment of the effectiveness of the Company's internal
control over financial reporting as of December 31, 2005 has been audited by
Hein & Associates LLP, an independent registered public accounting firm, as
stated in their report which appears elsewhere in this report.
83
Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities
Exchange Act of 1934, as amended, this Annual Report on Internal Control Over
Financial Reporting has been signed below by the following persons on behalf of
the registrant and in the capacities indicated below on March 1, 2006.
Mark A. Erickson
President & Chief Executive Officer
W. King Grant
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Gasco Energy, Inc.
Englewood, Colorado
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting that Gasco
Energy, Inc. ("Gasco") maintained effective internal control over financial
reporting as of December 31, 2005, based on criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Gasco's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the company's internal control
over financial reporting 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
84
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, management's assessment that Gasco Energy, Inc. maintained
effective internal control over financial reporting as of December 31, 2005, is
fairly stated, in all material respects, based on criteria established in
Internal Control--Integrated Framework issued by COSO. Also in our opinion,
Gasco maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2005, based on criteria established in
Internal Control--Integrated Framework issued by COSO.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements of Gasco Energy, Inc. and our report dated March 1, 2006 expressed an
unqualified opinion.
/s/ Hein & Associates LLP
Denver, Colorado
March 1, 2006
ITEM 9B - OTHER INFORMATION
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 2006 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 2006 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
85
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2006 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 2006 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 2006 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1. See "Index to Financial Statements" under Item 8 on page 42.
2. Financial Statement Schedules - none.
3. Exhibits - See Index to Exhibits, below.
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).
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).
86
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 Certificate of Amendment to Articles of Incorporation dated June
21, 2005 (incorporated by reference to Exhibit 3.3 to the
Company's Form 10-Q/A for the quarter ended June 30, 2005, filed
on August 9, 2005).
3.4 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).
3.5 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).
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).
87
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).
#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).
88
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).
10.20Joint Value Enhancement Agreement by and among Pannonian Energy
Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co.,
Red Oak Capital Management LLC and Schlumberger Technology
Corporation dated January 16, 2004 (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K filed on
January 21, 2004).
*21 List of Subsidiaries
*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.
89
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: February 27, 2006
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 February 27, 2006
- --------------------
Mark A. Erickson
/s/ Marc A. Bruner Director February 27, 2006
- ---------------------
Marc A. Bruner
/s/ Carl Stadelhofer Director February 27, 2006
- --------------------
Carl Stadelhofer
/s/ W. King Grant Executive Vice President and Chief Financial Officer February 27, 2006
- -----------------
W. King Grant (Principal Financial Officer and Principal Accounting
Officer)
/s/ Carmen Lotito Director February 27, 2006
- -----------------
Carmen ("Tony") Lotito
/s/ Charles B. Crowell Director February 27, 2006
- ----------------------
Charles B. Crowell
/s/ Richard S. Langdon Director February 27, 2006
- ----------------------
Richard S. Langdon
/s/ R. J. Burgess Director February 27, 2006
- ---------------------
R.J. Burgess
/s/ John A. Schmit Director February 27, 2006
- ------------------
John A. Schmit
90
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).
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 Certificate of Amendment to Articles of Incorporation dated June
21, 2005 (incorporated by reference to Exhibit 3.3 to the
Company's Form 10-Q/A for the quarter ended June 30, 2005, filed
on August 9, 2005).
3.4 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).
3.5 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).
91
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).
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). #10.5 W. 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).
92
#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).
#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).
10.20Joint Value Enhancement Agreement by and among Pannonian Energy
Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co.,
Red Oak Capital Management LLC and Schlumberger Technology
Corporation dated January 16, 2004 (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K filed on
January 21, 2004).
*21 List of Subsidiaries
93
*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.
94