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
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number: 000-21644
CRIMSON EXPLORATION INC.
(Exact name of registrant as specified in its charter)
Delaware 20-3037840
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
480 N. Sam Houston Parkway East, Suite 300
Houston, Texas 77060
(Address of principal executive offices) (Zip Code)
(281) 820-1919
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: Common Stock,
$0.001 par value per share
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 Exchange 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 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. Large
accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
As of March 29, 2006, the aggregate market value of the registrant's common
stock held by non-affiliates of the registrant was $17,269,535 based on the
closing sales price of $.75 For purposes of this computation, all executive
officers, directors and 10% beneficial owners of the registrant are deemed to be
affiliates. Such a determination should not be deemed an admission that such
executive officers, directors and 10% beneficial owners are affiliates.
On March 29, 2006, there were 33,041,332 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of our Definitive Proxy Statement for the 2006 Annual Meeting, expected
to be filed within 120 days of our fiscal year end, are incorporated by
reference into Part III.
PART I
This summary highlights selected information contained elsewhere in
this Annual Report. The following summary does not contain all of the
information that may be important. You should read the detailed information
appearing elsewhere in this Annual Report before making an investment decision.
Certain terms that we use in our industry are italicized and defined in the
"Glossary of Industry Terms and Abbreviations". Unless otherwise indicated, all
references to "GulfWest", the "Company", "we", "us" and "our" refer to Crimson
Exploration Inc. and our subsidiaries.
We make forward-looking statements throughout this Annual Report.
Whenever you read a statement that is not simply a statement of historical fact
(such as when we describe what we "believe," "expect" or "anticipate" will
occur, and other similar statements), you must remember that our expectations
may not be correct, even though we believe they are reasonable. We do not
guarantee that the transactions and events described in this Annual Report will
happen as described (or that they will happen at all). The forward-looking
information contained in this Annual Report is generally located in the material
set forth under the headings "Summary," "Risk Factors," "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and "Business"
but may be found in other locations as well. These forward-looking statements
generally relate to our plans and objectives for future operations and are based
upon our management's reasonable estimates of future results and trends.
ITEM 1. Business
Our Business.
We are primarily engaged in the acquisition, development, exploitation
and production of crude oil and natural gas, primarily in the onshore producing
regions of the United States. Our focus is on increasing production from our
existing properties through further exploitation, development and exploration,
and on acquiring additional interests in undeveloped and underdeveloped crude
oil and natural gas properties.
Since we made our first significant acquisition in 1993, we have
substantially increased our ownership in producing properties and our crude oil
and natural gas reserves through a combination of acquisitions and the further
exploitation and development of our properties. At December 31, 2005, our part
of the estimated proved reserves these properties contained was approximately
2.7 million barrels (MBbl) of oil and 24.7 billion cubic feet (Bcf) of natural
gas with an estimated Net Present Value discounted at 10% (PV-10) of $171.6
million. At present, all of our properties are located on land in Texas,
Colorado, Louisiana and Mississippi, except for the property in the shallow
inland boundaries of Grand Lake, Louisiana. In the future, we plan to expand by
acquiring additional properties in those areas, and in similar properties
located in other producing regions of the United States, including the shallow
waters of the Gulf of Mexico.
Our gross revenues are derived from the following sources:
1. Oil and gas sales that are proceeds from the sale of crude oil
and natural gas production to midstream purchasers.
2. Operating overhead and other income that consists of
administrative fees received for operating crude oil and
natural gas properties for other working interest owners, and
for marketing and transporting natural gas for those owners.
This also includes earnings from other miscellaneous
activities.
Our operations are considered to fall within a single industry segment,
which is the acquisition, development, production and servicing of crude oil and
natural gas properties. See Item 7. " Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Our Common Stock is traded over-the-counter (OTC) under the symbol
"CXPI.OB".
1
Our Company.
We were formed as a corporation under the laws of the State of Utah in
1987 as Gallup Acquisitions, Inc., and subsequently changed our name to First
Preference Fund, Inc in 1992. We became a Texas corporation by a merger effected
in July 1992, through which our name became GulfWest Oil Company. On May 21,
2001, we changed our name to GulfWest Energy Inc.
On June 29, 2005 we merged with and into Crimson Exploration Inc., a
Delaware corporation ("Crimson"), for the purpose of changing our state of
incorporation from Texas to Delaware (the "Reincorporation"). The
Reincorporation was accomplished pursuant to an Agreement and Plan of Merger,
dated June 28, 2005, which was approved by GulfWest's shareholders at the 2005
Annual Shareholders' Meeting held June 1, 2005.
Our principal office is located at 480 North Sam Houston Parkway East,
Suite 300, Houston, Texas 77060 and our telephone number is (281) 820-1919.
Prior to March 2, 2006 Crimson Exploration Inc. had six active and
three inactive, direct or indirect, wholly owned subsidiaries. The active
subsidiaries were:
1. GulfWest Oil and Gas Company, a Texas corporation, was
organized February 18, 1999 and was the owner of record of
interests in certain crude oil and natural gas properties
located in Colorado and Texas. It had one wholly owned
subsidiary, GulfWest Oil and Gas Company (Louisiana) LLC.
2. GulfWest Oil and Gas Company (Louisiana) LLC, a Louisiana
company, was formed July 31, 2001 and was the owner of record
of interests in certain crude oil and natural gas properties
in Louisiana.
3. SETEX Oil and Gas Company, a Texas corporation, was organized
August 11, 1998 and was the operator of crude oil and natural
gas properties in which we own a majority working interest.
4. RigWest Well Service, Inc., a Texas corporation, was organized
September 5, 1996 and operates well servicing equipment for
our own account and for others when not being utilized for our
own account.
5. DutchWest Oil Company, a Texas corporation, was organized July
28, 1997 and was the owner of record of interests in certain
crude oil and natural gas properties located along the Gulf
Coast of Texas.
6. GulfWest Development Company, a Texas corporation, was
organized November 9, 2000 and was the owner of record of
interests in certain crude oil and natural gas properties
located in Texas and Mississippi.
On January 5, 2006 we formed Crimson Exploration Operating, Inc., a
Delaware corporation, as our wholly owned subsidiary through which all oil and
gas operations will be conducted. Effective March 2, 2006 we merged all our
subsidiaries referred to above, into this newly formed corporation. LTW Pipeline
Co. remains an inactive subsidiary of Crimson Exploration Inc.
Balance. At December 31, 2005, our proved reserves were comprised of
40% crude oil and 60% natural gas. We will continue to expand our role in the
domestic natural energy industry by (i) acquiring additional interests in crude
oil and natural gas properties, (ii) increasing the production and reserve base
of our existing producing properties, and (iii) developing an internal prospect
generation capability for exploratory prospects. Our goal is to have greater
control of our natural gas transportation and marketing, and an expanded role in
the transportation of natural gas produced by other parties in our area of
operations. We are presently focusing our workover and development efforts on
both crude oil and natural gas reserves to take advantage of the higher prices
of both commodities.
2
Financial Recapitalization
On February 28, 2005, we sold in a private placement,
81,000 shares of our Series G Preferred Stock to OCM GW Holdings, LLC
("OCMGW") for an aggregate offering price of $40.5 million. GulfWest
Oil and Gas Company ("GWOG"), a subsidiary of the Company, issued, in a
private placement, 2,000 shares of our Series A Preferred Stock, having
a liquidation preference of $1.0 million, to OCMGW for $1.5 million.
Net proceeds of the offerings of approximately $38.2 million after
expenses were used for the repayment of substantially all of our
outstanding debt and other past due liabilities and for general
corporate purposes.
The Series G Preferred Stock bears a coupon of 8% per year,
has an aggregate liquidation preference of $40.5 million (excluding
accumulated undeclared dividends), is convertible into common stock at
$0.90 per share and is senior to all of our capital stock. For the
first four years after issuance, we may defer the payment of dividends
on the Series G Preferred Stock and these deferred dividends will also
be convertible into our common stock at $0.90 per share. In addition,
the Series G Preferred Stock is entitled to nominate and elect a
majority of the members of our Board of Directors.
In connection with these recapitalization transactions, the
terms of the Series A Preferred Stock were amended such that by March
15, 2005, all such stock would either convert into a newly created
Series H Preferred Stock on a one for one basis or into common stock at
a conversion price of $0.35 per share. The Series H Preferred Stock is
required to be paid a dividend of 40 shares of common stock per share
of Series H Preferred Stock per year. At March 15, 2005, holders of
6,700 shares of Series A Preferred Stock converted to Series H
Preferred Stock and holders of 3,250 shares of Series A Preferred Stock
converted to an aggregate 4,642,859 shares of common stock. One Series
H Preferred Stock holder converted its shares of Series H Preferred
Stock into 285,715 shares of common stock. In April, 2005, an
additional 1,250 shares converted into 1,785,714 of common stock. The
outstanding Series H Preferred Stock has an aggregate liquidation
preference of $2.625 million. The Series H Preferred Stock is senior to
all of our capital stock other than Series G Preferred Stock.
In addition, we amended the terms of our 9,000 shares of
Series E Preferred Stock such that the coupon of 6% per year may be
deferred for the next four years and these deferred dividends will be
convertible into common stock at conversion price of $0.90 per share.
The original liquidation preference of the Series E Preferred Stock of
$500 per share remains convertible into common stock at $2.00 per
share. The Series E Preferred Stock has an aggregate liquidation
preference of $4.5 million (excluding accumulated undeclared
dividends), and is senior to all of our common stock, of equal
preference with our Series D Preferred Stock as to liquidation and
junior to our Series G and Series H Preferred Stock.
On May 17, 2005, we executed a promissory note for the benefit
of OCM GW Holdings, in the principal amount of $1 million, payable on
the earlier of July 17, 2005 or the day on which we are able to make
draws under a credit facility under which greater than $1 million may
be borrowed. Interest on the unpaid principal accrued at 4.59% per
annum. We repaid the note in full on July 19, 2005 from borrowings
under our new $100 million senior secured revolving credit facility.
On July 15, 2005, we entered into a $100 million senior
secured revolving credit facility with Wells Fargo Bank, National
Association. Borrowings under the new credit facility are subject to a
borrowing base limitation based on our current proved oil and gas
reserves. The current borrowing base is set at $20 million and will be
subject to semi-annual redeterminations. The facility is secured by a
lien on all our assets, and the assets of our subsidiaries, as well as
a security interest in the stock of all our subsidiaries. The credit
facility has a term of three years, and all principal amounts, together
with all accrued and unpaid interest, will be due and payable in full
on June 30, 2008. Proceeds from extensions of credit under the facility
will be for acquisitions of oil and gas properties and for general
corporate purposes. The facility also provides for the issuance of
letters-of-credit up to a $3 million sub-limit. We incurred $323,662 in
issuance costs associated with the credit facility which are being
amortized over its life.
3
Advances under the facility will be in the form of either base rate
loans or Eurodollar loans. The interest rate on the base rate loans fluctuates
based upon the higher of (1) the lender's "prime rate" and (2) the Federal Funds
rate, plus a margin of 0.50%, plus a margin of between 0.0% and 0.5% depending
on the percent of the borrowing base utilized at the time of the credit
extension. The interest rate on the Eurodollar loans fluctuates based upon the
rate at which Eurodollar deposits in the London Interbank market ("Libor") are
quoted for the maturity selected, plus a margin of 1.25% to 2.00% depending on
the percent of the borrowing base utilized at the time of the credit extension.
Eurodollar loans of one, three and nine months may be selected by us. A
commitment fee of 0.375% on the unused portion of the borrowing base will
accrue, and be payable quarterly in arrears.
The credit agreement includes usual and customary affirmative covenants
for credit facilities of this type and size, as well as customary negative
covenants, including, among others, limitation on liens, hedging, mergers, asset
sales or dispositions, payments of dividends, incurrence of additional
indebtedness, certain leases and investments outside of the ordinary course of
business. The credit agreement also requires us to maintain a ratio of current
assets to current liabilities, except that any availability under the borrowing
base will be considered as an addition to current assets, and any current assets
or liabilities resulting from hedging agreements will be excluded, of at least
1.0 to 1.0, an interest coverage ratio of EBITDAX (earnings before interest,
taxes, depreciation and amortization and exploration expense) to cash interest
expense of 3.0 to 1.0 and a tangible net worth of at least $45 million, subject
to adjustment based on future results of operations and any sales of equity
securities. EBITDAX and tangible net worth are calculated without consideration
of unrealized gains and losses related to stock derivatives accounted for under
variable accounting rules for commodity hedges. At December 31, 2005 we were in
compliance with the aforementioned financial covenants.
Recent Developments
On March 22, 2006 we purchased a 100% working interest (75% net revenue
interest) in leases on approximately 22,000 undeveloped acres in Culberson
County Texas. The acreage, believed to contain producible reserves in the
Barnett Shale and Atoka formations, is being acquired through our acquisition,
by merger, of Core Natural Resources, Inc. ("Core"), a privately-held entity
that was incorporated solely to hold the leases being acquired by us. Pursuant
to the merger agreement, each issued and outstanding share of common stock of
Core was converted into the right to receive (i) 5.39270725 shares of the common
stock, par value $.001 per share, of the Company (the "Stock Consideration") and
(ii) cash in an amount determined by dividing $706,123.25 by 600,000 (the "Cash
Consideration," and, together with the Stock Consideration, the "Merger
Consideration"). Pursuant to the merger agreement, we assumed $2,045,258 of Core
indebtedness that was paid off at the closing of the merger. The cash paid at
closing was funded from cash on hand and temporary borrowings under our credit
facility. As of the date of the merger agreement, 600,000 shares of Core Common
Stock were issued and outstanding. We issued 3,235,624 shares of our common
stock as the Stock Consideration. In a separate transaction, the Company will
also issue an additional 462,231 shares of common stock of the Company to a Core
stockholder as consideration for the assignment of a 2% overriding royalty
interest owned by that stockholder in the oil and gas leases of Core (giving us
a total 77% net revenue interest). All stock issued in conjunction with these
transactions is restricted stock subject to resale limitations under Rule 144(a)
of the Securities Act of 1933. Core stockholders were also granted certain
limited piggyback registration rights.
Our Business Strategy
We have pursued a business strategy of acquiring interests in crude oil
and natural gas producing properties where production and reserves can be
increased through exploitation activities. Such activities include workovers,
development drilling, recompletions, replacement or addition of equipment and
waterflood or other secondary recovery techniques. Key elements of our business
strategy include:
Development and Exploitation of Existing Properties. Our strategy is to
increase crude oil and natural gas production and reserves of our existing
assets through relatively low-risk development activities, such as performing
workovers, recompletions and horizontal drilling from existing wellbores,
infield drilling and more efficiently using production facilities.
Continued Acquisition Program. We acquired properties in four crude oil
and natural gas fields in Texas and Louisiana in the year 2001. We were capital
constrained during the years 2002 through February 2005, and therefore made no
acquisitions during that period. To the extent financial resources are
available, we intend to continue to pursue the acquisition of interests in crude
oil and natural gas properties (i) held by small, under-capitalized operators
and (ii) being divested by larger independent and major oil and gas companies.
4
Significant Operating Control. Currently, we are the operator of all
but three of the wells in which we own working interests. This operating control
enables us to better manage the nature, timing and costs of developing and
servicing such wells, and the timing and marketing of the resulting production.
Ownership of Workover Rigs. We currently own two workover service rigs
that we operate for our own account. By owning and operating this equipment, we
are better able to control costs, quality of operations and availability of
equipment and services.
Expanded Exploration and Exploitation Role. Historically, we have not
drilled exploratory wells due to the cost and risk associated with drilling
prospective locations. However, since the end of 1998, we have acquired
producing properties that have included significant acreage for prospective oil
and gas exploration. These include producing wells and acreage in Grimes,
Hardin, Jim Wells, Madison, Palo Pinto, Refugio, Victoria, Wharton and Zavala,
Counties, Texas; Adams, Arapaho, Elbert and Weld Counties, Colorado; Cameron
Parish, Louisiana; and Jones County, Mississippi. These acquisitions have added
existing natural gas and crude oil production to our asset base and, as
importantly, have provided us with immediate geological databases for
development drilling opportunities as well as the potential for generating
exploratory opportunities on the acquired acreage. We have expanded our
evaluation efforts in these fields and intend to increase our development of
reserves through workovers of existing wells and by drilling additional wells.
As we develop exploration opportunities on these properties or see high-quality
prospects generated by others, as capital resources are available, we will
complement our development activities with capital for exploratory or
exploitation projects.
Our Employees.
At December 31, 2005, we had 30 full time employees, of whom 14 were
field personnel. None of our employees are covered by collective bargaining
agreements.
Government Regulation
Federal and State Regulatory Requirements
We are a public company subject to the rules and regulations of the
SEC. Recently enacted and proposed changes in the laws and regulations affecting
public companies, including the provisions of the Sarbanes-Oxley Act of 2002 and
rules adopted by the SEC, could result in increased costs to us as we evaluate
the implications of these new rules and respond to their requirements. The new
rules could make it more difficult for us to obtain certain types of insurance,
including director and officer liability insurance, and we may be forced to
accept reduced policy limits and coverage or incur substantially higher costs to
obtain the same or similar coverage. The impact of these events could also make
it more difficult for us to attract and retain qualified persons to serve on our
board of directors, our board committees, or as executive officers. We are
currently evaluating and monitoring developments with respect to new and
proposed rules and cannot predict or estimate the amount of the additional costs
we may incur or the timing of such costs.
Our operations are subject to numerous laws and regulations governing
the operation and maintenance of our facilities and the discharge of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations may require that we acquire permits before commencing
drilling; restrict the substances that can be released into the environment in
connection with drilling and production activities; limit or prohibit drilling
activities on protected areas such as wetlands or wilderness areas; or require
remedial measures to mitigate pollution from former operations. Under these laws
and regulations, we could be liable for personal injury and clean-up costs and
other environmental and property damages, as well as administrative, civil and
criminal penalties. These laws and regulations have been changed frequently in
the past. In general, these changes have imposed more stringent requirements
that increase operating costs or require capital expenditures in order to remain
in compliance. It is also possible that unanticipated developments could cause
us to make environmental expenditures that are significantly different from
those we currently expect. Existing laws and regulations could be changed, and
any changes could have an adverse effect on our business.
5
Environmental Regulations
The oil and gas business is subject to environmental hazards, such as
oil spills, gas leaks and ruptures and discharges of petroleum products and
hazardous substances, and historic disposal activities. These environmental
hazards could expose us to material liabilities for property damages, personal
injuries or other environmental harm, including costs of investigating and
remediating contaminated properties. In addition, we also may be liable for
environmental damages caused by the previous owners or operators of properties
that we have purchased or are currently operating. A variety of stringent
federal, state and local laws and regulations govern the environmental aspects
of our business and impose strict requirements for, among other things, well
drilling or workover, operation and abandonment, waste management; land
reclamation; and controlling air, water and waste emissions.
Any noncompliance with these laws and regulations could subject us to
material administrative, civil or criminal penalties or other liabilities.
Additionally, our compliance with these laws may, from time to time, result in
increased costs to our operations or decreased production, and may affect our
costs of acquisitions. Environmental laws may, in the future, cause a decrease
in our production or an increase in the costs of production, development or
exploration. Pollution and similar environmental risks generally are not fully
insurable.
We have not incurred any material costs relating to our compliance with
federal, state or local laws during the year ended December 31, 2005, or during
the subsequent interim period.
Our Executive Officers.
See Item 10 of this report, which information is incorporated herein by
reference.
ITEM 1. A Risk Factors
Our success depends heavily upon our ability to market our crude oil
and natural gas production at favorable prices.
In recent decades, there have been both periods of worldwide
overproduction and underproduction of crude oil and natural gas, and periods of
increased and relaxed energy conservation efforts. Such conditions have resulted
in excess supply of, and reduced demand for, crude oil on a worldwide basis and
for natural gas on a domestic basis. At other times, there has been short supply
of, and increased demand for, crude oil and, to a lesser extent, natural gas.
These changes have resulted in dramatic price fluctuations.
We may borrow funds to finance capital expenditures and for other
purposes which could possibly have important consequences to our shareholders,
including the following:
(i) Our indebtedness, acquisitions, working capital, capital
expenditures or other purposes may be impaired;
(ii) Funds available for our operations and general corporate
purposes or for capital expenditures will be reduced as a
result of the dedication of a portion of our consolidated cash
flow from operations to the payment of the principal and
interest on our indebtedness;
(iii) We may be more highly leveraged than certain of our
competitors, which may place us at a competitive disadvantage;
(iv) The agreements governing our long-term indebtedness and bank
loans may contain restrictive financial and operating
covenants;
(v) An event of default (not cured or waived) under financial and
operating covenants contained in our debt instruments could
occur and have a material adverse effect;
(vi) Certain of the borrowings under our debt agreements could have
floating rates of interest, which would cause us to be
vulnerable to increases in interest rates; and
6
(vii) Our degree of leverage could make us more vulnerable to a
downturn in general economic conditions.
(viii) Our revolving credit facility contains a number of significant
negative covenants that place limits on our activities and
operations, including those relating to: o creation of liens,
o hedging,
o mergers, acquisitions, asset sales or dispositions,
o payments of dividends,
o incurrence of additional indebtedness, and
o certain leases and investments outside of the
ordinary course of business.
In addition, our revolving credit facility requires us to
maintain compliance with specified financial ratios and satisfy
certain financial condition tests. Our ability to comply with
these ratios and financial condition tests may be affected by
events beyond our control, and we cannot assure you that we will
meet these ratios and financial condition tests. These financial
ratio restrictions and financial condition tests could limit our
ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the
economy in general or otherwise conduct necessary or desirable
corporate activities.
A breach of any of these covenants or our inability to comply
with the required financial ratios or financial condition tests
could result in a default under our revolving credit facility. A
default, if not cured or waived, could result in all of our
indebtedness becoming immediately due and payable. If that should
occur, we may not be able to pay all such debt or to borrow
sufficient funds to refinance it. Even if new financing were then
available, it may not be on terms that are acceptable to us.
We have outstanding debt of $1,036,282 on our credit facility and
shareholders equity of $52,805,262 at December 31, 2005. We may
borrow up to an additional $18,963,718 under our revolving credit
facility to fund acquisitions or for general corporate purposes.
Our debt obligations could increase substancially.
We have incurred net losses in the past and there can be no assurance
that we will be profitable in the future.
We have incurred net losses in three of the last five fiscal years. We
cannot assure you that our current level of operating results will continue or
improve. Our activities could require additional debt or equity financing on our
part. Since the terms and availability of this financing depend to a large
degree upon general economic conditions and third parties over which we have no
control, we can give no assurance that we will obtain the needed financing or
that we will obtain such financing on attractive terms. In addition, our ability
to obtain financing depends on a number of other factors, many of which are also
beyond our control, such as interest rates and national and local business
conditions. If the cost of obtaining needed financing is too high or the terms
of such financing are otherwise unacceptable in relation to the opportunity we
are presented with, we may decide to forego that opportunity. Additional
indebtedness could increase our leverage and make us more vulnerable to economic
downturns and may limit our ability to withstand competitive pressures.
Additional equity financing could result in dilution to our shareholders. Our
future operating results may fluctuate significantly depending upon a number of
factors, including industry conditions, prices of crude oil and natural gas,
rates of production, timing of capital expenditures and drilling success. These
variables could have a material adverse effect on our business, financial
condition, results of operations and the market price of our Common Stock.
Estimates of crude oil and natural gas reserves depend on many
assumptions that may turn out to be inaccurate.
7
Estimates of our proved reserves for crude oil and natural gas and the
estimated future net revenues from the production of such reserves rely upon
various assumptions, including assumptions as to crude oil and natural gas
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. The process of estimating crude oil and natural gas
reserves is complex and imprecise. Actual future production, crude oil and
natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable crude oil and natural gas reserves may
vary substantially from the estimates we obtain from reserve engineers. Any
significant variance in these assumptions could materially affect the estimated
quantities and present value of reserves we have set forth. In addition, our
proved reserves may be subject to downward revision due to factors that are
beyond our control, such as production history, results of future exploration
and development, prevailing crude oil and natural gas prices and other factors.
Approximately 16% of our total estimated proved reserves at December
31, 2005 were proved undeveloped reserves, which are by their nature less
certain.
Recovery of such reserves requires significant capital expenditures and
successful drilling operations. The reserve data set forth in the reserve
engineer reports assumes that substantial capital expenditures are required to
develop such reserves. Although cost and reserve estimates attributable to our
crude oil and natural gas reserves have been prepared in accordance with
industry standards, we cannot be sure that the estimated costs are accurate,
that development will occur as scheduled or that the results of such development
will be as estimated.
You should not interpret the present value referred to in this annual
report as the current market value of our estimated crude oil and natural gas
reserves.
In accordance with Securities and Exchange Commission requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the date of the estimate. Actual future prices
and costs may be materially higher or lower.
The estimates of our proved reserves and the future net revenues from
which the present value of our properties is derived were calculated based on
the actual prices of our various properties on a property-by-property basis at
December 31, 2005. The average sales prices of all properties were $57.79 per
barrel of oil and $10.90 per thousand cubic feet (Mcf) of natural gas at that
date.
Actual future net cash flows will also be affected by increases or
decreases in consumption by crude oil and natural gas purchasers and changes in
governmental regulations or taxation. The timing of both the production and the
incurring of expenses in connection with the development and production of crude
oil and natural gas properties affect the timing of actual future net cash flows
from proved reserves. In addition, the 10% discount factor, which is required by
the Securities and Exchange Commission to be used in calculating discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor. The effective interest rate at various times and
the risks associated with our business or the oil and gas industry in general
will affect the accuracy of the 10% discount factor.
Except to the extent that we acquire properties containing proved
reserves or conduct successful development or exploitation activities, our
proved reserves will decline as they are produced.
In general, the volume of production from crude oil and natural gas
properties declines as reserves are depleted. Our future crude oil and natural
gas production is highly dependent upon our success in finding or acquiring
additional reserves.
The business of acquiring, enhancing or developing reserves requires
considerable capital.
Our ability to make the necessary capital investment to maintain or
expand our asset base of crude oil and natural gas reserves could be impaired to
the extent that cash flow from operations is reduced and external sources of
capital become limited or unavailable. In addition, we cannot be sure that our
future acquisition and development activities will result in additional proved
reserves or that we will be able to drill productive wells at acceptable costs.
Crude oil and natural gas drilling and production activities are
subject to numerous risks, many of which are beyond our control. These risks
include (i) the possibility that no commercially productive oil or gas
reservoirs will be encountered; and, (ii) that operations may be curtailed,
delayed or canceled due to title problems, weather conditions, governmental
requirements, mechanical difficulties, or delays in the delivery of drilling
rigs and other equipment that may limit our ability to develop, produce and
market our reserves. We cannot assure you that new wells we drill will be
productive or that we will recover all or any portion of our investment in such
new wells.
8
Drilling for crude oil and natural gas may not be profitable.
Any wells that we drill may be dry wells or wells that are not
sufficiently productive to be profitable after drilling. Such wells will have a
negative impact on our profitability. In addition, our properties may be
susceptible to drainage from production by other operators on adjacent
properties.
Our industry experiences numerous operating risks that could cause us
to suffer substantial losses.
Such risks include fire, hurricanes, explosions, blowouts, pipe failure
and environmental hazards, such as oil spills, natural gas leaks, ruptures or
discharges of toxic gases. We could also suffer losses due to personnel injury
or loss of life; severe damage to or destruction of property; or environmental
damage that could result in clean-up responsibilities, regulatory investigation,
penalties or suspension of our operations. In accordance with customary industry
practice, we maintain insurance policies against some, but not all, of the risks
described above. Our insurance policies may not adequately protect us against
loss or liability. There is no guarantee that insurance policies that protect us
against the many risks we face will continue to be available at justifiable
premium levels.
As owners and operators of crude oil and natural gas properties, we may
be liable under federal, state and local environmental regulations for
activities involving water pollution, hazardous waste transport, storage,
disposal or other activities.
Our past growth has been attributable to acquisitions of producing
crude oil and natural gas properties with proved reserves. There are risks
involved with such acquisitions.
The successful acquisition of properties requires an assessment of
recoverable reserves, future crude oil and natural gas prices, operating costs,
potential environmental and other liabilities, and other factors beyond our
control. Such assessments are necessarily inexact and their accuracy uncertain.
In connection with such an assessment, we perform a review of the subject
properties that we believe to be generally consistent with industry practices.
Such a review, however, will not reveal all existing or potential problems, nor
will it permit us, as the buyer, to become sufficiently familiar with the
properties to fully assess their capabilities or deficiencies. We may not
inspect every well and, even when an inspection is undertaken, structural and
environmental problems may not necessarily be observable.
When we acquire properties, in most cases, we are not entitled to
contractual indemnification for pre-closing liabilities, including environmental
liabilities.
We generally acquire interests in properties on an "as is" basis with
limited remedies for breaches of representations and warranties, and in these
situations we cannot assure you that we will identify all areas of existing or
potential exposure. In those circumstances in which we have contractual
indemnification rights for pre-closing liabilities, we cannot assure you that
the seller will be able to fulfill its contractual obligations. In addition, the
competition to acquire producing crude oil and natural gas properties is intense
and many of our larger competitors have financial and other resources
substantially greater than ours. We cannot assure you that we will be able to
acquire producing crude oil and natural gas properties that have economically
recoverable reserves for acceptable prices.
We may acquire royalty, overriding royalty or working interests in
properties that are less than the controlling interest.
In such cases, it is likely that we will not operate, nor control the
decisions affecting the operations, of such properties. We intend to limit such
acquisitions to properties operated by competent parties with whom we have
discussed their plans for operation of the properties.
We will need additional financing in the future to continue to fund our
development and exploitation activities.
9
We have made and will continue to make substantial capital expenditures
in our exploitation and development projects. We intend to finance these capital
expenditures with cash flow from operations, existing financing arrangements or
new financing. We cannot assure you that such additional financing will be
available. If it is not available, our development and exploitation activities
may have to be curtailed, which could adversely affect our business, financial
condition and results of operations.
The marketing of our natural gas production depends, in part, upon the
availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities.
We could be adversely affected by changes in existing arrangements with
transporters of our natural gas since we do not own most of the gathering
systems and pipelines through which our natural gas is delivered to purchasers.
Our ability to produce and market our natural gas could also be adversely
affected by federal, state and local regulation of production and
transportation.
The crude oil and natural gas industry is highly competitive in all of
its phases.
Competition is particularly intense with respect to the acquisition of
desirable producing properties, the acquisition of crude oil and natural gas
prospects suitable for enhanced production efforts, the obtaining of goods and
services from industry providers, and the hiring of experienced personnel. Our
competitors in crude oil and natural gas acquisition, development, and
production include the major oil companies, in addition to numerous independent
crude oil and natural gas companies, individual proprietors and drilling
programs.
Many of these competitors possess and employ financial and personnel
resources substantially in excess of those which are available to us and may,
therefore, be able to pay more for desirable producing properties and prospects
and to define, evaluate, bid for, and purchase a greater number of producing
properties and prospects than our financial or personnel resources will permit.
Our ability to generate reserves in the future will be dependent on our ability
to select and acquire suitable producing properties and prospects while
competing with these companies.
The domestic oil industry is extensively regulated at both the federal
and state levels. Although we believe we are presently in compliance with all
laws, rules and regulations, we cannot assure you that changes in such laws,
rules or regulations, or the interpretation thereof, will not have a material
adverse effect on our financial condition or the results of our operations.
Legislation affecting the oil and gas industry is under constant review
for amendment or expansion, frequently increasing the regulatory burden on the
industry. There are numerous federal and state agencies authorized to issue
rules and regulations affecting the oil and gas industry. These rules and
regulations are often difficult and costly to comply with and carry substantial
penalties for noncompliance.
State statutes and regulations require permits for drilling operations,
drilling bonds, and reports concerning operations. Most states also have
statutes and regulations governing conservation matters, including the
unitization or pooling of properties, and the establishment of maximum rates of
production from wells. Some states have also enacted statutes prescribing price
ceilings for natural gas sold within their states.
Our industry is also subject to numerous laws and regulations governing
plugging and abandonment of wells, discharge of materials into the environment
and other matters relating to environmental protection. The heavy regulatory
burden on the oil and gas industry increases the costs of our doing business as
an oil and gas company, consequently affecting our profitability.
We have "blank check" preferred stock.
Our Certificate of Incorporation authorizes the Board of Directors to
issue preferred stock without further shareholder action in one or more series
and to designate the dividend rate, voting rights and other rights preferences
and restrictions. The issuance of preferred stock could have an adverse impact
on holders of Common Stock. Preferred stock is senior to Common Stock.
Additionally, preferred stock could be issued with dividend rights senior to the
rights of holders of Common Stock. Finally, preferred stock could be issued as
part of a "poison pill", which could have the effect of deterring offers to
acquire the Company. "See "Description of Securities"
10
We are not paying dividends on our Common Stock.
Our board of directors presently intends to retain all of our earnings
for the expansion of our business; therefore we do not anticipate distributing
cash dividends on our Common Stock in the foreseeable future. Any decision of
our board of directors to pay cash dividends will depend upon our earnings,
financial position, cash requirements and other factors.
One investor controls us.
As a result of preferred stock offerings in February 2005, OCMGW
Holdings ("OCMGW") acquired a controlling interest in us. OCMGW has or has the
right to acquire 48,972,694 shares of our Common Stock pursuant to conversion of
Series G Preferred Stock, including undeclared convertible dividends, and Series
H Preferred Stock owned by it which represents approximately 60% of the
currently outstanding Common Stock, assuming the conversion of preferred stock
and undeclared dividends held by it. Pursuant to the terms of Series G Preferred
Stock, the holders of the Series G Preferred Stock, voting as a class, have the
right to elect a majority of our board of directors. OCMGW currently owns
approximately 95% of the Series G Preferred Stock.
Additionally, OCMGW and all current directors and officers as a group
represent approximately 55% of the outstanding voting power (assuming they
convert all preferred stock other than the Series G Preferred Stock and Series H
Preferred Stock, which vote on an as converted basis, and exercise all currently
exercisable warrants and options held by them). For as long as OCMGW and the
other directors and officers continue to own over a majority of the outstanding
voting power, they will be able to control elections to the board of directors
that common shareholders are entitled to vote on and other matters submitted to
shareholders. The percentage ownership of OCMGW, directors and officers could be
reduced by the issuance of Common Stock on conversion of preferred stock and the
exercise of warrants, although it is impossible to say how many shares will be
actually issued.
The holders of our Common Stock do not have cumulative voting rights,
preemptive rights or rights to convert their Common Stock to other securities.
We are authorized to issue 200,000,000 shares of Common Stock, $.001
par value per share. As of March 29, 2006 there were 33,041,332 shares of Common
Stock issued and outstanding. Since the holders of our Common Stock do not have
cumulative voting rights, the holder(s) of a majority of the shares of Common
Stock, and Series G Preferred Stock and Series H Preferred Stock (on an as
converted basis) present, in person or by proxy, will be able to elect all of
the remaining members of our board of directors that the holders of the Series G
Preferred Stock are not entitled to elect as a class. The holders of shares of
our Common Stock do not have preemptive rights or rights to convert their Common
Stock into other securities.
The number of shares of outstanding Common Stock could increase
significantly as a result of the recent sale of Series G Preferred Stock sold to
OCMGW and Affiliates.
If all of the Common Stock underlying our various convertible and
derivative securities, including warrants and granted employee stock options, is
issued by us, the number of our outstanding shares of Common Stock would
increase to approximately 118.6 million shares. Currently, we are only
authorized to issue 200,000,000 shares of our Common Stock, 33,041,332 shares of
which are outstanding as of March 29, 2006. It is impossible to say how many
shares, if any, we will issue and how many shares, in turn, will be resold.
However, it is possible that our stock price could decline significantly as a
result of an increased number of shares being offered into the market.
ITEM 2. Our Properties.
At December 31, 2005, we owned a total of 246 gross wells, of which 143
were producing, 84 were shut-in or temporarily abandoned and 19 were injection
or saltwater wells. We owned an average 85% working interest in the 143 gross
(122 net) producing wells. Gross wells are the total wells in which we own a
working interest. Net wells are the sum of the fractional working interests we
own in gross wells. Our part of the estimated proved reserves these properties
contain was approximately 2.7 million barrels (MMBL) of oil and 24.7 billion
cubic feet (Bcf) of natural gas at December 31, 2005. Substantially all of our
properties are located onshore or shallow inland waters in Texas, Colorado and
Louisiana.
11
Proved Reserves.
The following table reflects our estimated proved reserves at December
31 for each of the preceding three years.
2005 2004 2003
------------- ------------- -------------
Crude Oil (MBbl)
Developed 2,423 2,575 3,773
Undeveloped 285 388 1,265
------------- ------------- -------------
Total 2,708 2,963 5,038
============= ============= =============
Natural Gas (MMcf)
Developed 19,658 20,966 24,642
Undeveloped 4,992 8,125 8,018
------------- ------------- -------------
Total 24,650 29,091 32,660
============= ============= =============
Total (MMcfe) 40,898 46,869 62,888
============= ============= =============
(a) Approximately 84% of our total proved reserves were classified as
proved developed at December 31, 2005.
Standardized Measure of Discounted Future Net Cash Flows.
The following table sets forth as of December 31 for each of the
preceding three years, the estimated future net cash flow from and standardized
measure of discounted future net cash flows of our proved reserves, which were
prepared in accordance with the rules and regulations of the SEC and the
Financial Accounting Standard Board. Future net cash flow represents future
gross cash flow from the production and sale of proved reserves, net of crude
oil and natural gas production costs (including production taxes, ad valorem
taxes and operating expenses) and future development costs. The calculations
used to produce the figures in this table are based on current cost and price
factors at December 31 for each year. We cannot assure you that the proved
reserves will all be developed within the periods used in the calculations or
those prices and costs will remain constant.
2005 2004 2003
------------------- ---------------- -----------------
Future cash inflows $ 425,080,357 $ 290,998,312 $ 336,795,385
Future production and development costs
Production 101,677,305 80,880,330 109,468,727
Development 27,467,896 24,141,982 21,460,459
------------------- ---------------- -----------------
Future cash flows before income taxes 295,935,156 185,976,000 205,866,199
Future income taxes (91,664,228) (49,871,272) (46,885,360)
------------------- ---------------- -----------------
Future net cash flows after income taxes 204,270,928 136,104,728 158,980,839
10% annual discount for estimated
timing of cash flows (85,873,789) (52,602,351) (70,653,419)
------------------- ---------------- -----------------
Standardized measure of discounted
future net cash flows $ 118,397,139 $ 83,502,377 $ 88,327,420
=================== ================ =================
(1) The average sales prices utilized in the estimation of our proved reserves
were $57.79 per Bbl and $10.90, $40.41 per Bbl and $5.89 per Mcf and $29.51
per Bbl and $5.82 per Mcf, at December 31, 2005, 2004 and 2003,
respectively.
12
Significant Properties.
Summary information on our properties with proved reserves is set forth
below as of December 31, 2005.
Present
Productive Wells Proved Reserves Value(1)
------------------------- ---------------------------------------- -----------
Gross Net
Productive Productive Crude Natural
Wells Wells Oil Gas Total Amount
----------- ----------- ----------- ---------- ----------- -----------
(MBbl) (MMcf) (MMcfe) ($M)
Texas 86 77.37 1,089 11,909 18,443 $ 75,378
Colorado 34 23.25 284 5,117 6,818 26,574
Louisiana 21 20.88 1,316 7,624 15,520 69,184
Mississippi 1 0.37 19 - 114 426
Offshore 1 .25 - - - -
=========== =========== =========== ========== =========== ===========
Total 143 122.12 2,708 24,650 40,895 $ 171,562
=========== =========== =========== ========== =========== ===========
(1) The average sales prices used in the estimation of our proved reserves were
$57.79 per Bbl and $10.90 per Mcf at December 31, 2005.
All information set forth herein relating to our proved reserves,
estimated future net cash flows and present values is taken from reports
prepared by Pressler Petroleum Consultants, independent petroleum engineers. The
estimates of these engineers were based upon their review of production
histories and other geological, economic, ownership and engineering data
provided by and relating to us. No reports on our reserves have been filed with
any federal agency. In accordance with the SEC's guidelines, our estimates of
proved reserves and the future net revenues from which present values are
derived are made using year end crude oil and natural gas sales prices held
constant throughout the life of the properties (except to the extent a contract
specifically provides otherwise). Operating costs, development costs and certain
production-related taxes were deducted in arriving at estimated future net
revenues, but such costs do not include debt service, general and administrative
expenses and income taxes.
There are numerous uncertainties inherent in estimating crude oil and
natural gas reserves and their values, including many factors beyond our
control. The reserve data set forth in this report are based upon estimates.
Reservoir engineering is a subjective process, which involves estimating the
sizes of underground accumulations of crude oil and natural gas that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data, engineering and geological interpretation of
that data, and judgment. As a result, estimates of different engineers,
including those used by us, may vary. In addition, estimates of reserves are
subject to revision based upon actual production, results of future development,
exploitation and exploration activities, prevailing crude oil and natural gas
prices, operating costs and other factors. Such revisions may be material.
Accordingly, reserve estimates are often different from the quantities of crude
oil and natural gas that are ultimately recovered and are highly dependent upon
the accuracy of the assumptions upon which they are based. We cannot assure you
that the estimates contained in this report are accurate predictions of our
crude oil and natural gas reserves or their values. Estimates with respect to
proved reserves that may be developed and produced in the future are often based
upon volumetric calculations and upon analogy to similar types of reserves
rather than upon actual production history. Estimates based on these methods are
generally less reliable than those based on actual production history.
Subsequent evaluation of the same reserves based upon production history will
result in potentially substantial variations in the estimated reserves.
13
Production, Revenue and Price History.
The following table sets forth information (associated with our proved
reserves) regarding production volumes of crude oil and natural gas, revenues
and expenses attributable to such production (all net to our interests) and
certain price and cost information for the years ended December 31, 2005, 2004
and 2003.
2005 2004 2003
------------ ------------ ------------
Production
Oil (Bbl) 177,833 173,865 221,335
Natural gas (Mcf) 1,482,250 1,033,433 1,190,624
------------ ------------ ------------
Total (MCFE) 2,549,248 2,076,623 2,518,634
Revenue
Oil production $ 7,044,429 $ 5,498,598 $ 5,362,657
Natural gas production 10,507,221 5,602,516 5,481,803
------------ ------------ ------------
Total $17,551,650 $11,101,114 $10,844,460
Operating Expenses $ 5,585,297 $ 4,879,754 $ 5,527,841
Production Data
Average sales price (1)
Per barrel of oil $ 39.61 $ 31.63 $ 24.23
Per Mcf of natural gas $ 7.09 $ 5.42 $ 4.60
Per MCFE $ 6.89 $ 5.35 $ 4.31
Average expenses per MCFE
Lease operating $ 2.19 $ 2.35 $ 2.19
Geological and Geophysical $ .16
Depreciation, depletion and
Amortization $ 1.23 $ 1.05 $ .88
General and administrative $ 1.48 $ .92 $ .90
(1) Average sales prices are shown net of the settled amounts of our oil and
gas hedge contracts. Average sales prices per MCFE, before adjustments for
the hedge contracts, were $8.43, $6.23 and $4.90 in 2005, 2004 and 2003,
respectively.
Productive Wells at December 31, 2005:
The following table shows the number of producing wells we own by
location:
Gross Net Gross Net
Oil Wells Oil Wells Gas Wells Gas Wells
--------- --------- ---------- ----------
Texas 33 30.00 53 47.37
Colorado 18 11.90 16 11.36
Louisiana 15 14.88 6 6.00
Mississippi 1 0.37 - -
Offshore 0 0 1 0.25
--------- --------- ---------- ----------
Total 67 57.15 76 64.98
========= ========= ========== ==========
In addition, the Company has 84 inactive wells (70 net) and 19 salt
water disposal wells (18 net).
14
Developed Acreage at December 31, 2005.
The following table shows the developed acreage that we own, by
location, which is acreage spaced or assigned to productive wells. Gross acres
are the total acres in which we own a working interest. Net acres are the sum of
the fractional working interests we own in gross acres.
Gross Acres Net Acres
--------------- ----------------
Texas 8,855 8,149
Colorado 3,000 2,100
Louisiana 1,440 1,440
--------------- ----------------
Total 13,295 11,689
=============== ================
Undeveloped Acreage at December 31, 2005.
The following table shows the undeveloped acreage that we own, by
location. Undeveloped acreage is acreage on which wells have not been drilled or
completed to a point that would form the basis to determine whether the property
is capable of production of commercial quantities of crude oil and natural gas.
Gross Acres Net Acres
--------------- ----------------
Texas 13,640 11,430
Colorado 14,300 10,700
Louisiana 160 160
--------------- ----------------
Total 28,100 22,290
=============== ================
Drilling Results.
In 2005, we drilled 2 wells in Texas and participated for a 25% working
interest in one offshore well. One was drilled in our Iola field in east Texas
and it was completed as a gas well in March 2005 which had an initial net rate
of 800 mcfepd and declined to 200 mcfepd by year-end. We participated in a 40%
working interest in an exploration well in south Texas and it was unsuccessful.
We participated for a 25% working interest in an offshore well at Mustang Island
749. Efforts were underway at year-end to flow back the Mustang Island 749
exploratory well, drilled earlier in the year, to finally determine if
commercial quantities of gas were present. Because we believe that this well
will ultimately be determined to be uneconomical, we recorded a $3.2 million
impairment of this well in the fourth quarter. In 2004, we drilled one natural
gas well which is producing and we did not drill any wells in 2003.
Costs Incurred
The following table shows the costs incurred in our oil and gas
producing activities for the past three years:
2005 2004 2003
------------- ------------- -------------
Property Acquisitions
Proved $ 142,867 $ 6,742 $ -
Unproved 1,244,975 17,347 110,119
Development Costs 6,171,241 6,117,899 2,024,663
------------- ------------- -------------
$ 7,559,083 $ 6,141,988 $ 2,134,782
============= ============= =============
15
Property Dispositions
The following table shows oil and gas property dispositions:
2005 2004 2003
------------- ------------- -------------
Oil and gas properties $ 31,337 $ 5,425,040 $ 31,979
Accumulated DD&A - (1,659,001) (11,569)
------------- ------------- -------------
Net oil and gas properties $ 31,337 $ 3,766,039 $ 20,410
============= ============= =============
As a result of these sales we recorded a loss of $13,022, $2,029,932
and $ 20,409 in 2005, 2004 and 2003 respectively.
Marketing
We sell substantially all of our crude oil and natural gas production
to purchasers pursuant to sales contracts that typically have a thirty-day
primary term, although occasionally we enter into longer term contracts when it
is advantageous to do so. The sales prices for crude oil and condensate are tied
to industry standard posted prices plus negotiated premiums. The sales prices
for natural gas are based upon published index prices, subject to negotiated
price deductions.
ITEM 3. Legal Proceedings.
From time to time, we are involved in litigation relating to claims
arising out of our operations or from disputes with vendors in the normal course
of business. As of March 29, 2006, we were not engaged in any legal proceedings
that are expected, individually or in the aggregate, to have a material adverse
effect on the Company.
ITEM 4. Submission of Matters to a Vote of Security Holders.
We did not submit any matters to a vote of our security holders during
the fourth quarter of the fiscal year ended December 31, 2005.
PART II
ITEM 5. Market for Our Common Stock and Related Stockholder Matters.
The high and low trading prices for the Common Stock for each quarter
in 2005, 2004 and 2003 are set forth below. The trading prices represent prices
between dealers, without retail mark-ups, mark-downs, or commissions, and may
not necessarily represent actual transactions.
High Low
-------- --------
2005
First Quarter $ 1.46 $ .75
Second Quarter 1.20 .85
Third Quarter 1.38 .88
Fourth Quarter 1.11 .85
2004
First Quarter $ .45 $ .32
Second Quarter .56 .33
Third Quarter .85 .45
Fourth Quarter .94 .66
2003
First Quarter $ .45 $ .42
Second Quarter .47 .35
Third Quarter .47 .43
Fourth Quarter .47 .32
16
Common Stock.
We are authorized to issue up to 200,000,000 shares of Common Stock,
par value $.001 per share. As of March 29, 2006, there were 33,041,332 shares of
Common Stock issued and outstanding and held by approximately 253 record
holders. Our Common Stock is traded over-the-counter (OTC) under the symbol
"CXPI.OB". Fidelity Transfer Company, 1800 South West Temple, Suite 301, Box 53,
Salt Lake City, Utah 84115, (801) 484-7222 is the transfer agent for the Common
Stock.
Holders of Common Stock are entitled, among other things, to one vote
per share on each matter submitted to a vote of shareholders and, in the event
of liquidation, to share ratably in the distribution of assets remaining after
payment of liabilities (including preferential distribution and dividend rights
of holders of preferred stock). Holders of Common Stock have no cumulative
rights. The holders of a majority of the outstanding shares of the Common Stock
and Series G and H (on an as converted basis) have the ability to elect all of
the directors that the Series G does not elect. On February 28, 2005, the
holders of the Series G Preferred Stock were granted the right to elect a
majority of our Board of Directors.
Holders of Common Stock have no preemptive or other rights to subscribe
for shares. Holders of Common Stock are entitled to such dividends as may be
declared by the Board out of funds legally available therefore. We have never
paid cash dividends on the Common Stock and do not anticipate paying any cash
dividends in the foreseeable future.
Preferred Stock.
Our board of directors is authorized, without further shareholder
action, to issue preferred stock in one or more series and to designate the
dividend rate, voting rights and other rights, preferences and restrictions of
each such series. Our preferred stock is senior to our Common Stock regarding
liquidation. The holders of the preferred stock do not have voting rights
(except for the Series G and Series H Preferred Stock holders as discussed
below) or preemptive rights, nor are they subject to the benefits of any
retirement or sinking fund. We are authorized to issue up to 10,000,000 shares
of preferred stock.
As of March 29, 2006, there was a total of 103,250 shares of preferred
stock issued and outstanding in four series: Series D, E, G and H Preferred
Stock.
The Series D Preferred Stock is not entitled to dividends, nor is it
redeemable, however it is convertible to Common Stock at anytime based on $8.00
per share of Common Stock. The 8,000 outstanding shares of Series D Preferred
Stock are held by a former director and none has been converted. On a fully
converted basis, the 8,000 shares of Series D Preferred Stock would convert to
500,000 shares of Common Stock.
The Series E Preferred Stock is entitled to receive dividends at the
rate of 6% per share per annum, which may be deferred for the next four years
and those deferred dividends will be convertible into Common Stock at the
conversion price of $.90 per share of Common Stock. The conversion price for the
Series E Preferred Stock is based on $2.00 per share of Common Stock. The Series
E Preferred Stock is held by a former director and none of the 9,000 outstanding
shares has been redeemed or converted. On a fully converted basis, the 9,000
shares of Series E Preferred Stock would convert to 2,250,000 shares of Common
Stock. The Series E Preferred Stock has an aggregate liquidation preference of
$4.5 million, and is senior to all of our Common Stock and of equal preference
with our Series D Preferred Stock and junior to our Series G Preferred Stock and
Series H Preferred Stock.
17
The 81,000 shares of our Series G Preferred Stock bears a coupon of 8%
per year and has an aggregate liquidation preference of $40.5 million. For the
first four years after issuance, we may defer the payment of dividends on the
Series G Preferred Stock and these deferred dividends will also be convertible
into our Common Stock at $0.90 per share. In addition, the Series G Preferred
Stock is entitled to vote on an as-converted basis with the holders of our
Common Stock and, as a class, is entitled to nominate and elect a majority of
the members of our Board of Directors. The Series G Preferred Stock is senior to
all of Crimson's outstanding capital stock in liquidation preference.
The Series H Preferred Stock is required to be paid a dividend of 40
shares of Common Stock per Series H Preferred Stock share per year. In addition,
the Series H Preferred Stock is convertible into Common Stock at a conversion
price of $0.35 per share. The Series H Preferred Stock has an aggregate
liquidation value of $2.6 million and is senior to all of GulfWest's outstanding
capital stock in liquidation preference other than its Series G Preferred Stock.
There were 5,250 shares of Series H Preferred Stock outstanding at December 31,
2005.
Outstanding Options and Warrants.
At December 31, 2005, we had outstanding employee stock options, under
our 1994 and 2004 Stock Option and Compensation Plans, to purchase 1,710,000
(1,375,000 vested) shares of Common Stock at prices ranging from $.45 to $1.81
per share and warrants to purchase 1,470,000 shares of Common Stock at prices
ranging from $.01 to $.75 per share. In conjunction with the subsequent
financing event on February 28, 2005, we established our 2005 Stock Incentive
Plan and authorized the issuance of 27 million shares of Common Stock pursuant
to awards under the plan, 22,400,000 (none vested) shares which were outstanding
at December 31, 2005.
Recent Sales of Unregistered Securities.
As shown in the table that follows, during 2005 we sold preferred stock
convertible to Common Stock not registered under the Securities Act of 1933, as
amended, and exempt under Section 4(2) of the Act. No underwriters were used,
and no underwriting discounts or commissions were paid in connection with the
sales.
Exercise/
Underlying Conversion
Date Derivative Holder(s) Shares Price Consideration
--------- -------------- -------------- ------------- ----------- -------------
Accredited
03/22/05 Warrants Investors 20,000 $.01 $ 200
03/30/05 Options Employee 25,000 $.45 $11,250
Accredited
04/04/05 Warrants Investors 2,018,224 $.01 N/A *
Accredited
06/01/05 Common Stock Investors 34,090 N/A Compensation
Accredited
08/25/05 Options Investors 100,000 $.45 $45,000
*Received reduced number of shares in exchange for the exercise
price.
ITEM 6. Selected Financial Data.
The following table sets forth selected historical financial data of
our company as of December 31, 2005, 2004, 2003, 2002 and 2001, and for each of
the periods then ended. See "Item 1. Business" and "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations." The
income statement data for the years ended December 31, 2005, 2004 and 2003 and
the balance sheet data at December 31, 2005 and 2004 are derived from our
audited financial statements contained elsewhere herein. The income statement
data for the years ended December 31, 2002 and 2001 and the balance sheet data
at December 31, 2003, 2002 and 2001 are derived from our Annual Report on Form
10-K for those periods. You should read this data in conjunction with our
consolidated financial statements and the notes thereto included elsewhere
herein.
18
-------------------------------------------------------------------------
Year Ended December 31,
2005 2004 2003 2002 2001
----------- ----------- ----------- ----------- -----------
Income Statement Data
---------------------
Operating Revenues $17,682,808 $11,207,673 $11,010,723 $10,839,797 $12,990,581
Net income from
operations 676,324 1,557,815 558,774 310,290 3,451,875
Net income (loss) (3,543,239) 8,072,221 (3,024,426) (4,502,313) 1,044,291
Dividends on preferred stock (3,562,472) (455,612) (127,083) (112,500) (56,250)
Net income (loss) available to
common shareholders (7,105,711) 7,616,609 (3,151,509) (4,614,813) 988,401
Net income (loss), per share
of Common Stock, basic $ (.27) $ .41 $ (.17) $ (.25) $ .05
Weighted average number
of shares of common
stock outstanding 26,738,815 18,535,022 18,492,541 18,492,541 18,464,343
Balance Sheet Data
------------------
Current assets $ 5,825,078 $ 3,808,878 $ 1,742,689 $ 2,353,046 $ 2,205,862
Total assets 63,114,949 57,876,164 52,428,774 53,088,941 51,379,209
Current liabilities 6,855,735 37,249,217 44,619,652 43,998,566 12,492,365
Long-term obligations 2,414,365 1,950,304 1,393,607 137,808 26,541,957
Other liabilities 1,039,587 - 591,467 1,128,993 -
Stockholders' Equity $52,805,262 $18,676,643 $ 5,824,648 $ 7,823,574 $12,344,887
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
Overview.
We are primarily engaged in the acquisition, development, exploitation
and production of crude oil and natural gas, primarily in the onshore producing
regions of the United States. Our focus is on increasing production from our
existing properties through further exploitation, development and exploration,
and on acquiring additional interests in undeveloped crude oil and natural gas
properties. Our gross revenues are derived from the following sources:
1. Oil and gas sales that are proceeds from the sale of crude oil
and natural gas production to midstream purchasers.
2. Operating overhead and other income that consists of
administrative fees received for operating crude oil and
natural gas properties for other working interest owners, and
for marketing and transporting natural gas for those owners.
This also includes earnings from other miscellaneous
activities.
The following is a discussion of our consolidated results of
operations, financial condition and capital resources. You should read this
discussion in conjunction with our Consolidated Financial Statements and the
Notes thereto contained elsewhere herein.
Results of Operations.
The factors which most significantly affect our results of operations
are (1) the sales price of crude oil and natural gas, (2) the level of total
sales volumes of crude oil and natural gas, (3) the cost and efficiency of
operating our own properties, (4) depletion and depreciation of oil and gas
property costs and related equipment (5) the level of and interest rates on
borrowings, (6) the level and success of acquiring or finding new reserves, and
the acquisition, finding and development costs incurred in adding these
reserves, and (7) the adoption of changes in accounting rules.
19
We consider depletion and depreciation of oil and gas properties and
related support equipment to be critical accounting estimates, based upon
estimates of total recoverable oil and gas reserves.
The estimates of oil and gas reserves utilized in the calculation of
depletion and depreciation are estimated in accordance with guidelines
established by the Society of Petroleum Engineers, the Securities and Exchange
Commission and the Financial Accounting Standards Board, which require that
reserve estimates be prepared under existing economic and operating conditions
with no provision for price and cost escalations over prices and costs existing
at year end, except by contractual arrangements.
We emphasize that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information
becomes available. Our policy is to amortize capitalized oil and gas costs on
the unit of production method, based upon these reserve estimates. It is
reasonably possible that the estimates of future cash inflows, future gross
revenues, the amount of oil and gas reserves, the remaining estimated lives of
the oil and gas properties, or any combination of the above may be increased or
reduced in the near term. If reduced, the carrying amount of capitalized oil and
gas properties may be reduced materially in the near term.
Comparative results of operations for the periods indicated are discussed below.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Revenues
Oil and Gas Sales. Revenues from the sale of crude oil and natural gas,
net of realized losses from the hedging instruments, increased 58% from
$11,101,000 in 2004 to $17,552,000 in 2005. Losses realized on our hedges during
2005 were $2,468,000 for oil and $1,475,000 for gas compared to $1,251,000 for
oil and $590,000 for gas in 2004. The increase in revenues was due to higher oil
and gas sales volumes and higher crude oil and natural gas prices, as further
described below.
In 2005, our sales volumes were 177,833 barrels of crude oil and
1,482,250 Mcf of natural gas, or 2,549,248 natural gas equivalents (mcfe),
compared to 173,865 barrels of crude oil and 1,033,433 Mcf of natural gas, or
2,076,623 Mcfe in 2004. On a daily basis we produced an average of 6,984 Mcfe in
2005 compared to a daily average of 5,689 Mcfe in 2004. Higher sales volumes
were a direct result of the development program we began in late 2004 and
continued in 2005. The developmental program included our drilling and
completing 2 new gas wells in east Texas in early 2005, the completion of
workover and facility projects at Grand Lake and Lacassine fields in southwest
Louisiana, and the workover of wells in east and south Texas. Volume increases
generated through our development program not only offset the loss of production
from property sales in 2004, but also allowed us to achieve the 23% increase in
production despite the shut-in of approximately 4,500 Mcfepd from the effects of
Hurricane Rita during parts of September and October, with production still
approximately 12% below pre-hurricane levels due to delays in getting water
disposal facilities back fully operational. We estimate, on average, that the
average daily rate for 2005 was negatively impacted by 400 Mcfed.
Oil and Gas prices are reported net of the realized effect of our
hedging agreements. Prices realized were $39.61 per Bbl and $7.09 per Mcf in
2005 compared to $31.63 per Bbl ad $5.42 per Mcf in 2004. Prices before the
effects of the hedging agreements were $53.49 per Bbl and $8.08 per Mcf in 2005
compared to $38.82 per Bbl and $5.99 per Mcf in 2004.
Operating Overhead and Other Income. Revenues from these activities
increased 22% from $107,000 in 2004 to $131,000 in 2005 due to higher
transportation fees resulting from higher volume.
Costs and Expenses
Lease Operating Expenses. Overall, operating expenses increased 14%
from $4,880,000 in 2004 to $5,585,000 in 2005. The increase was primarily due to
higher production taxes as a result of increased sales volumes and commodity
prices, and to a lesser extent, general price increases for goods and services
industry wide.
On a per unit basis, expenses decreased from $2.35 per Mcfe in 2004 to
$2.19 per Mcfe in 2005. This decrease in lifting cost was due to the higher
sales volume, not offset by higher lifting costs.
20
Depreciation, Depletion and Amortization (DD & A). DD & A increased 43%
from $2,185,000 in 2004 to $3,131,000 in 2005, due to higher production volumes,
and an increase in the DD & A rate per unit from $1.05 per Mcfe in 2004 to $1.23
per Mcfe in 2005. The increase in our DD &A rate in 2005 resulted from a capital
expenditure plan consisting primarily of development projects that increased
production and cash flow, but added no reserves.
General and Administrative (G & A) Expenses. G & A expenses increased
87% from $2,019,000 in 2004 to $3,773,000 in 2005 due to higher salaries
resulting from additions to our management team to carry out our post
recapitalization growth plan. On a per unit basis, expenses increased from $.92
per Mcfe in 2004 to $1.48 per Mcfe in 2005.
Interest Expense. Interest expense decreased 69% from $4,154,000 in
2004 to $1,303,000 in 2005, primarily due to the retirement of debt associated
with our Februray 2005 recapitalization.
Geological and Geophysical Expense (G&G). G&G expense was $395,000 in
2005 as we began to acquire seismic data as part of our strategy to develop an
internal exploratory prospect generation capability. No G&G costs were incurred
in 2004 as we focused our capital program on the development of its proved
reserves.
Dry Holes, Abandonment Costs and Impaired Assets. Dry hole, abandonment
and impairment expense was $4,063,000 in 2005 compared to $453,000 in 2004.
Included in the 2005 expense were two exploratory dry holes, one of which was
plugged and abandoned and one of which is still being evaluated. The Mustang
Island 749 #1 well is technically still being evaluated, however, we do not
believe that it will ultimately be determined to be economical, therefore
included in this expense for 2005 was an impairment of $3.2 million. The 2004
expense was comprised primarily of leasehold abandonment costs.
Debt Issuance Costs. Other financing costs were $1,956,000 in 2005
compared with $1,472,000 in 2004. Costs in 2005 included the writeoff of
previously capitalized debt issuance costs associated with previous financings
that were repaid with proceeds from the sale of the Series G Preferred Stock in
February 2005. The expense in 2004 was comprised primarily of the amortization
of capitalized costs associated with the financings repaid in February 2005.
Unrealized (Gain)/Loss on Derivative Instruments. Unrealized gain or
loss on derivative instruments is the change during the year in the
mark-to-market exposure under our commodity price hedging instruments. This
non-cash expense for 2005 was $1,643,000 compared with an expense of $1,506,000
for the 2004 year. This expense will vary period to period, and will be a
function of the hedges in place, and the strike prices of those hedges, at each
balance sheet date.
Income Tax Benefit. Income tax benefit for 2005 was $792,000 compared
to a benefit of $3,204,000 for the year 2004.
Dividends on Preferred Stock. Dividends on preferred stock were
$3,562,000 in 2005 compared with $456,000 in 2004. Dividends in 2005 included
$2,725,000 on the Series G Preferred Stock $166,000 on the Series H Preferred
Stock $271,000 on the Series E and $401,000 for the other series of preferred
stock previously issued by the Company and/or its subsidiaries and retired as
part of the February 28, 2005 recapitalization. Dividends on preferred stock for
2004 included $195,000 on the Series E Preferred Stock and $261,000 for the
other series of preferred stock previously issued by the Company and/or its
subsidiaries and retired as part of the February 28, 2005 recapitalization.
Comparative results of operations for the periods indicated are
discussed below.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil
and natural gas increased by 2% from $10,844,000 in 2003 to $11,101,000 in 2004.
Revenue increases due to higher oil and natural gas sales prices were
substantially offset by a 17% decrease in sales volumes, 12% of which was due to
normal oil and gas production declines and 5% due to property sales.
21
Operating Overhead and Other Income. Revenues from these activities
decreased 36% from $166,000 in 2003 to $107,000 in 2004, primarily due to (1) a
one time $58,000 contract settlement received in 2003, and (2) lower pipeline
volumes resulting in less transportation revenue.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses decreased 12% from
$5,528,000 in 2003 to $4,880,000 in 2004, 5% was due to lower variable costs on
lower production volumes and 7% due to property sales. On a per Mcfe basis,
costs increased from $2.19 in 2003 to $2.35 per Mcfe in 2004 because of lower
volume and higher vendor prices.
Depreciation, Depletion and Amortization (DD & A). DD & A decreased 2%
from $2,226,000 in 2003 to $2,185,000 in 2004, due to lower production volumes.
On a per Mcfe basis, the DD & A rate increased from $.88 in 2003 to $1.05 per
Mcfe in 2004 due to higher than anticipated development costs.
Dry Holes, Abandoned Property and Impaired Assets. The cost of dry
holes, abandoned property and impaired assets expense in 2004 was $452,500
(abandoned- $391,000; impaired- $62,000), compared to $359,000 (dry holes-
$70,000; abandoned $289,000) in 2003. The abandoned property was due to a lack
of capital to complete projects resulting in the loss of leases.
General and Administrative (G & A) Expenses. G & A expenses decreased
11% from $2,262,000 in 2003 to $2,019,000 in 2004 due to expenses incurred in
2003 associated with financing efforts that were not culminated.
Interest Expense. Interest expense increased 24% from $3,363,000 in
2003 to $4,154,000 in 2004. In April 2004 we retired debt of approximately $27.6
million carrying an interest rate of prime plus 3.5% and replaced it with debt
of approximately $18.0 million that carries an interest rate of prime plus
11.0%. Also, included in 2004 is non cash interest expense of approximately $.4
million resulting from the discounting on a note payable issued in 2004.
Debt Issuance Costs. Other financing costs increased 47% from
$1,000,000 in 2003 to $1,472,000 in 2004. In 2003, we recorded an expense of
$1,000,000 to account for the issuance of 2,000 shares of our preferred stock in
conjunction with the financial agreement on the retired debt referred to above.
The expense in 2004 represents the amortized portion of loan fees associated
with the refinancing of debt referred to above.
Unrealized Gain (Loss) on Derivative Instruments. The estimated future
fair value of derivative instruments at December 31, 2004 resulted in an
estimated unrealized loss of $1,506,000 in 2004 compared to an unrealized gain
of $538,000 in 2003. Estimated unrealized gain/loss on oil and gas price hedges
in place on a particular balance sheet date is based on a "mark to market"
calculation based on a market price forecast on the balance sheet date compared
to the prices provided for in the derivative instruments.
Loss on Sale of Property and Equipment. We recorded a loss on sale of
property and equipment of $2,034,000 in 2004 as compared to $20,000 in 2003. See
Note 3 to the Financial Statements.
Forgiveness of Debt. In 2004 we had $12,476,000 in debt forgiven as the
result of debt refinancing in April, 2004.
Dividends on Preferred Stock. In 2004, a dividend on preferred stock
due was $456,000. In 2003 dividends on preferred stock due was $127,000. The
board of directors did not declare any dividends be paid.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Revenues
Oil and Gas Sales. Our operating revenues from the sale of crude oil
and natural gas increased by 4% from $10,447,000 in 2002 to $10,844,000 in 2003.
This increase was due to higher sales prices, offset by normal oil and gas
production declines and resulting in lower production volumes. We were unable to
offset those declines and maintain or increase production through development
efforts because of limited development capital.
22
Operating Overhead and Other Income. Revenues from these activities
decreased 53% from $354,000 in 2002 to $166,000 in 2003, primarily due to (1)
the loss of an oil and gas marketing contract and (2) lower pipeline volumes
resulting in less transportation revenue.
Costs and Expenses
Lease Operating Expenses. Lease operating expenses increased 2% from
$5,430,000 in 2002 to $5,528,000 in 2003 due to increased vendor prices.
Depreciation, Depletion and Amortization (DD & A). DD & A decreased 17%
from $2,698,000 in 2002 to $2,226,000 in 2003, due to lower production volumes.
We also recorded in other income $262,000 related to the cumulative effect of
adopting SFAS 143 "Asset Retirement Obligations".
Dry Holes, Abandoned Property and Impaired Assets. The cost of
abandoned property in 2003 was $359,000 because the lack of capital to complete
projects resulted in the loss of leases. This compared to combined costs of dry
holes, abandoned property and impaired assets of $617,000 in 2002.
General and Administrative (G and A) Expenses. G and A expenses
increased 31% from $1,728,000 in 2002 to $2,262,000 in 2003 due to expenses
associated with financing efforts that were not culminated.
Intrest Expense. Interest expense increased 6% from $3,159,000 in 2002
to $3,363,000 in 2003 due to penalty interest paid to our largest lender under a
provision in the loan agreement.
Debt Issuance Costs. In 2003, we recorded an expense of $1,000,000 to
account for the failed issuance of 2,000 shares of our preferred stock to our
largest lender under a financial agreement.
Unrealized Gain (Loss) on Derivative Instruments. The estimated future
fair value of derivative instruments at December 31, 2003 resulted in an
unrealized gain of $538,000 in 2003 compared to an unrealized loss of $1,597,000
in 2002.
Loss on Sale of Property and Equipment. We recorded a loss on sale of
property and equipment of $20,000 in 2003 as compared to $57,000 in 2002. See
Note 3 to the Financial Statements.
Dividends on Preferred Stock. In 2003, dividends due on preferred stock
due was $127,000, however the board of directors did not declare any dividends
to be paid. In 2002, dividends on preferred stock due was $112,000, and paid was
$112,000.
Contractual Obligations
Our obligations as of December 31, 2005, under contractual obligations
with maturities exceeding one year, were as follows:
More than 5
Total 2006 2007 2008 2009 2010 years
------------ ------------ ------------ ------------ ------------ ------------ ------------
Long-term debt
obligations $ 1,184,115 $ 80,883 $ 31,600 $ 1,058,150 $ 10,449 $ 3,033 $ -
Operating lease
obligations 169,300 135,323 33,977 - - - -
Asset retirement
obligations 1,311,133 - 24,820 10,075 38,337 45,707 1,192,194
------------ ------------ ------------ ------------ ------------ ------------ ------------
$ 2,664,548 $ 216,206 $ 90,397 $ 1,068,225 $ 48,786 $ 48,740 $ 1,192,194
============ ============ ============ ============ ============ ============ ============
23
Financial Condition and Capital Resources.
At December 31, 2005, our current liabilities exceeded our current
assets by $1,030,657. We had loss available to common shareholders of $7,105,711
compared to income available to common shareholders of $7,616,609 at December
31, 2004. (See ITEM 7 Management Discussion and Analysis)
On February 28, 2005, we sold in a private placement, 81,000 shares of
our Series G Preferred Stock to OCM GW Holdings, LLC ("OCMGW") for an aggregate
offering price of $40.5 million. GulfWest Oil and Gas Company ("GWOG"), a
subsidiary of the Company, issued, in a private placement, 2,000 shares of our
Series A Preferred Stock, having a liquidation preference of $1.0 million, to
OCMGW for $1.5 million. Net proceeds of the offerings of approximately $38.2
million after expenses were used for the repayment of substantially all of our
outstanding debt and other past due liabilities and for general corporate
purposes.
The Series G Preferred Stock bears a coupon of 8% per year, has an
aggregate liquidation preference of $40.5 million (excluding accumulated
undeclared dividends), is convertible into common stock at $0.90 per share and
is senior to all of our capital stock. For the first four years after issuance,
we may defer the payment of dividends on the Series G Preferred Stock and these
deferred dividends will also be convertible into our common stock at $0.90 per
share. In addition, the Series G Preferred Stock is entitled to nominate and
elect a majority of the members of our Board of Directors.
In connection with these recapitalization transactions, the terms of
the Series A Preferred Stock were amended such that by March 15, 2005, all such
stock would either convert into a newly created Series H Preferred Stock on a
one for one basis or into common stock at a conversion price of $0.35 per share.
The Series H Preferred Stock is required to be paid a dividend of 40 shares of
common stock per share of Series H Preferred Stock per year. The outstanding
Series H Preferred Stock has an aggregate liquidation preference of $2.625
million. The Series H Preferred Stock is senior to all of our capital stock
other than Series G Preferred Stock.
In addition, we amended the terms of our 9,000 shares of Series E
Preferred Stock such that the coupon of 6% per year may be deferred for the next
four years and these deferred dividends will be convertible into common stock at
conversion price of $0.90 per share. The original liquidation preference of the
Series E Preferred Stock of $500 per share remains convertible into common stock
at $2.00 per share. The Series E Preferred Stock has an aggregate liquidation
preference of $4.5 million (excluding accumulated undeclared dividends), and is
senior to all of our common stock, of equal preference with our Series D
Preferred Stock as to liquidation and junior to our Series G and Series H
Preferred Stock.
On May 17, 2005, we executed a promissory note for the benefit of OCM
GW Holdings, in the principal amount of $1 million, payable on the earlier of
July 17, 2005 or the day on which we are able to make draws under a credit
facility under which greater than $1 million may be borrowed. Interest on the
unpaid principal accrued at 4.59% per annum. We repaid the note in full on July
19, 2005 from borrowings under our new $100 million senior secured revolving
credit facility.
On July 15, 2005, we entered into a $100 million senior secured
revolving credit facility with Wells Fargo Bank, National Association.
Borrowings under the new credit facility will be subject to a borrowing base
limitation based on our current proved oil and gas reserves. The current
borrowing base is set at $20 million and will be subject to semi-annual
redeterminations. The facility is secured by a lien on all our assets, and the
assets of our subsidiaries, as well as a security interest in the stock of all
our subsidiaries. The credit facility has a term of three years, and all
principal amounts, together with all accrued and unpaid interest, will be due
and payable in full on June 30, 2008. Proceeds from extensions of credit under
the facility will be for acquisitions of oil and gas properties and for general
corporate purposes. The facility also provides for the issuance of
letters-of-credit up to a $3 million sub-limit. We incurred $323,662 in issuance
costs associated with the credit facility which are being amortized over its
life.
Advances under the facility will be in the form of either base rate
loans or Eurodollar loans. The interest rate on the base rate loans fluctuates
based upon the higher of (1) the lender's "prime rate" and (2) the Federal Funds
rate, plus a margin of 0.50%, plus a margin of between 0.0% and 0.5% depending
on the percent of the borrowing base utilized at the time of the credit
extension. The interest rate on the Eurodollar loans fluctuates based upon the
rate at which Eurodollar deposits in the London Interbank market ("Libor") are
quoted for the maturity selected, plus a margin of 1.25% to 2.00% depending on
the percent of the borrowing base utilized at the time of the credit extension.
Eurodollar loans of one, three and nine months may be selected by us. A
commitment fee of 0.375% on the unused portion of the borrowing base will
accrue, and be payable quarterly in arrears.
24
The credit agreement includes usual and customary affirmative covenants
for credit facilities of this type and size, as well as customary negative
covenants, including, among others, limitation on liens, hedging, mergers, asset
sales or dispositions, payments of dividends, incurrence of additional
indebtedness, certain leases and investments outside of the ordinary course of
business. The credit agreement also requires us to maintain a ratio of current
assets to current liabilities, except that any availability under the borrowing
base will be considered as an addition to current assets, and any current assets
or liabilities resulting from hedging agreements will be excluded, of at least
1.0 to 1.0, an interest coverage ratio of EBITDAX (earnings before interest,
taxes, depreciation and amortization and exploration expense) to cash interest
expense of 3.0 to 1.0 and a tangible net worth of at least $45 million, subject
to adjustment based on future results of operations and any sales of equity
securities. EBITDAX and tangible net worth are calculated without consideration
of unrealized gains and losses related to stock derivatives accounted for under
variable accounting rules for commodity hedges. At December 31, 2005 we were in
compliance with the aforementioned financial covenants.
We believe that we have sufficient liquidity through our cash from
operations and borrowing capacity under our revolving credit facility to meet
our short-term and long-term normal reacurring operating needs, derivative
obligations, debt service obligations, contingencies and anticipated capacity
expenditures.
Inflation and Changes in Prices.
While the general level of inflation affects certain costs associated
with the petroleum industry, factors unique to the industry result in
independent price fluctuations. Such price changes have had, and will continue
to have a material effect on our operations; however, we cannot predict these
fluctuations.
The following table indicates the average crude oil and natural gas
prices received over the last three years by quarter. Average prices per MCF
equivalent, computed by converting oil production to natural gas equivalents at
the rate of 6 Mcf per barrel, indicate the composite impact of changes in crude
oil and natural gas prices.
Average Prices(1)
---------------------------------------------
Crude Oil Per
And Natural Equivalent
Liquids Gas MCF
------------- ------------- -------------
(per Bbl) (per Mcf)
2005
----
First $ 35.84 $ 5.91 $ 5.94
Second 37.26 6.15 6.18
Third 38.58 7.46 7.03
Fourth 47.98 9.09 8.63
2004
----
First $ 27.97 $ 4.87 $ 4.76
Second 30.41 5.34 5.20
Third 32.72 5.44 5.45
Fourth 35.32 5.97 5.93
2003
----
First $ 24.53 $ 5.36 $ 4.68
Second 23.53 4.47 4.17
Third 23.85 4.32 4.14
Fourth 24.99 4.56 4.17
(1) Average sales price are shown net of the settled amounts of our oil and gas
hedge contracts. ITEM 7A. Qualitative and Quantitative Disclosures About Market
Risk.
25
ITEM 7A. Qualitative and Quantitative Disclosures About Market Risk.
The following market rate disclosures should be read in conjunction
with our financial statements and notes thereto beginning on Page F-1 of this
Annual Report. All of our financial instruments are for purposes other than
trading. We only enter into derivative financial instruments in conjunction with
our oil and gas sales price hedging activities. Hypothetical changes in interest
rates and prices chosen for the following stimulated sensitivity effects are
considered to be reasonably possible near-term changes generally based on
consideration of past fluctuations for each risk category. It is not possible to
accurately predict future changes in interest rates and product prices.
Accordingly, these hypothetical changes may not be an indicator of probable
future fluctuations.
Interest Rate Risk
We are exposed to interest rate risk on debt with variable interest
rates. At December 31, 2005, we carried variable rate debt of $1,306,282.
Assuming a one percentage point change at December 31, 2005 on our variable rate
debt, the annual pretax net income or loss would change by $13,063.
Commodity Price Risk
In the past we have entered into, and may in the future enter into,
certain derivative arrangements with respect to portions of our oil and natural
gas production to reduce our sensitivity to volatile commodity prices. During
2005 and 2004, we entered into price swaps and put agreements with financial
institutions. We believe that these derivative arrangements, although not free
of risk, allow us to achieve a more predictable cash flow and to reduce exposure
to price fluctuations. However, derivative arrangements limit the benefit to us
of increases in the prices of crude oil and natural gas sales. Moreover, our
derivative arrangements apply only to a portion of our production and provide
only partial price protection against declines in price. Such arrangements may
expose us to risk of financial loss in certain circumstances. We expect that the
monthly volume of derivative arrangements will vary from time to time. We
continuously reevaluate our price hedging program in light of increases in
production, market conditions, commodity price forecasts, and capital spending
and debt service requirements. The following derivatives were in place at
December 31, 2005.
Fair Value
Asset
Crude Oil Volume/ Month Average Price/ Unit (Liability)
--------- ------------- ------------------- -----------
January 2006 thru March 2006 Collar 10,000 Bbls Floor $50.00-$59.00 Ceiling $(123,840)
April 2006 thru December 2006 Collar 9,000 Bbls Floor $50.00-$59.00 Ceiling $(568,944)
January 2007 thru December 2007 Collar 3,000 Bbls Floor $45.00-$59.45 Ceiling $(311,988)
Fair Value
Asset
Natural Gas Volume/ Month Average Price/ Unit (Liability)
----------- ------------- ------------------- -----------
January 2006 thru December 2006 Collar 70,000 MMBTU Floor $6.00-$8.25 Ceiling $(1,484,784)
January 2007 thru December 2007 Collar 20,000 MMBTU Floor $6.00-$6.95 Ceiling $(658,614)
We also had the following put options in place at December 31, 2005,
for the months reflected.
Crude Oil Monthly Volume Price per Bbl
--------- -------------- -------------
January 2006 thru April 2006 7,000 Bbls $25.75 put
May 2006 thru October 2006 6,000 Bbls $25.75 put
November 2006 thru April 2007 5,000 Bbls $25.75 put
The value of these put options was minimal.
26
At the end of each reporting period we are required by SFAS 133
"Accounting for Derivative Instruments and Hedging Activities," to record on our
balance sheet the marked to market valuation of our derivative instruments. We
recorded a liability for derivative instruments at December 31, 2005 and 2004 of
$3,148,170 and $1,680,800 respectively. As a result of these agreements, we
recorded a non-cash charge to earnings, for unsettled contracts, of $1,642,643
for the twelve month period ended December 31, 2005 and a charge of $1,505,577
for the twelve month period ended December 31, 2004 and a non-cash increase in
earnings of $537,526 for the twelve month period ended December 31, 2003. The
estimated change in fair value of the derivatives is reported in Other Income
and Expense as unrealized (gain) loss on derivative instruments.
For settled contracts, we realized losses, reflected as reductions in
oil and gas revenues, of $3,942,710, $1,841,209 and $1,496,303 for the twelve
month periods ended December 31, 2005, 2004 and 2003 respectively.
ITEM 8. Financial Statements and Supplementary Data.
Information with respect to this Item 8 is contained in our financial
statements beginning on Page F-1 of this Annual Report.
ITEM 9. Changes In and Disagreements With Accountants and Accounting and
Financial Disclosure.
Not Applicable
ITEM 9A. Controls and Procedures
At the end of 2005, our President, Chief Executive Officer and Chief
Financial Officer evaluated the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Rule 13a-15 (b) under the
Securities Exchange Act of 1934, as amended ("the Exchange Act"). Based upon
this evaluation, they concluded that, subject to the limitations described
below, the Company's disclosure controls and procedures offer reasonable
assurance that the information required to be disclosed by the Company in the
reports it files under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the rules and forms adopted by the
Securities and Exchange Commission.
During the period covered by this report, there has been no change in
the Company's internal controls over financial reporting that materially
affected, or is reasonably likely to materially affect, these controls.
Limitations on the Effectiveness of Controls. Our management, including
the President, Chief Executive Officer and Chief Financial Officer, does not
expect that the Company's disclosure controls and procedures will prevent all
error and all fraud. A well conceived and operated control system is based in
part upon certain assumptions about the likelihood of future events and can
provide only reasonable, not absolute, assurance that the objectives of the
control systems are met. Further, 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.
ITEM 9B. Other Information
Not Applicable
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
Information regarding directors and executive officers of the
registrant is incorporated herein by reference to our Proxy Statement that is
expected to be filed prior to April 30, 2006.
ITEM 11. Executive Compensation.
Information regarding executive compensation is incorporated herein by
reference to our Proxy Statement that is expected to be filed prior to April 30,
2006.
27
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
Information regarding security ownership of certain beneficial owners
and management and related stockholder matters is incorporated herein by
reference to our Proxy Statement that is expected to be filed prior to April 30,
2006.
ITEM 13. Certain Relationships and Related Transactions.
Information regarding certain relationships and related transactions is
incorporated herein by reference to our Proxy Statement that is expected to be
filed prior to April 30, 2006.
ITEM 14. Principal Accountant Fees and Services.
Information regarding principal accountant fees and services is
incorporated herein by reference to our Proxy Statement that is expected to be
filed prior to April 30, 2006.
GLOSSARY OF INDUSTRY TERMS AND ABBREVIATIONS
The following are definitions of certain industry terms and abbreviations used
in this report:
Bbl. Barrel.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in
which a working interests is owned.
Horizontal Drilling. High angle directional drilling with lateral penetration of
one or more productive reservoirs.
Mcf. One thousand cubic feet.
Mcfe. Natural gas equivalent. One barrel of oil is equivalent to six Mcf.
Net Acres or Net Wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Overriding Royalty Interest. The right to receive a share of the proceeds of
production from a well, free of all costs and expenses, except transportation.
Present Value. The pre-tax present value, discounted at 10%, of future net cash
flows from estimated proved reserves, calculated holding prices and costs
constant at amounts in effect on the date of the report (unless such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in
accordance with the Commission's rules for inclusion of oil and gas reserve
information in financial statements filed with the Commission.
Proceeds of Production. Money received (usually monthly) from the sale of oil
and gas produced from producing properties.
Producing Properties. Properties that contain one or more wells that produce oil
and/or gas in paying quantities (i.e., a well for which proceeds from production
exceed operating expenses).
Productive Well. A well that is producing oil or gas or that is capable of
production.
Prospect. A lease or group of leases containing possible reserves, capable of
producing crude oil, natural gas, or natural gas liquids in commercial
quantities, either at the time of acquisition, or after vertical or horizontal
drilling, completion of workovers, recompletions, or operational modifications.
Proved Reserves. Estimated quantities of crude oil, natural gas, and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic conditions; i.e., prices and costs as of the date the estimate is made.
Reservoirs are considered proved if either actual production or a conclusive
formation test supports economic production.
28
The area of a reservoir considered proved includes:
a. That portion delineated by drilling and defining by gas-oil or
oil-water contacts, if any; and
b. The immediately adjoining portions not yet drilled but which
can be reasonably judged as economically productive on the
basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir.
Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
Proved Reserves do not include:
a. Oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";
b. Crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors;
c. Crude oil, natural gas, and natural gas liquids that may occur in
undrilled prospects; and
d. Crude oil, natural gas, and natural gas liquids that may be recovered
fromoil sales and other sources.
Proved Developed Reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Additional oil and
gas expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as proved developed only after testing by
a pilot project or after operation of an installed program has confirmed through
production response that increased recovery will be achieved.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other units that have
not been drilled can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proven effective by actual tests in the area and in the same reservoir.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil or gas that is confined by impermeable rock or
water barriers and is individual and separate from other reservoirs.
Royalty. The right to a share of production from a well, free of all costs and
expenses, except transportation.
Royalty Interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves, after income taxes, calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
29
Waterflood. An engineered, planned effort to inject water into an existing oil
reservoir with the intent of increasing oil reserve recovery and production
rates.
Working Interest. The operating interest under a lease, the owner of which has
the right to explore for and produce oil and gas covered by such lease. The full
working interest bears 100 percent of the costs of exploration, development,
production, and operation, and is entitled to the portion of gross revenue from
the proceeds of production which remains after proceeds allocable to royalty and
overriding royalty interests or other lease burdens have been deducted.
Workover. Rig work performed to restore an existing well to production or
improve its production from the current existing reservoir.
PART IV
ITEM 15. Exhibits and Financial Statement Schedules.
(a) The following documents are filed as part of this Report:
(1) Financial Statements:
Consolidated Balance Sheets at December 31, 2005 and 2004.
Consolidated Statements of Operations for the years ended
December 31, 2005, 2004 and 2003.
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 2005, 2004 and 2003.
Consolidated Statements of Cash Flows for the years ended
December 31, 2005, 2004 and 2003.
Notes to Consolidated Financial Statements, December 31, 2005,
2004 and 2003.
(2) Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
(3) Exhibits:
Number Description
------ -----------
*2.1 Agreement and Plan of Merger, dated March 14, 2006, among
Crimson Exploration, Inc., Exploration Operating, Inc., Core
Natural Resources, Inc. and its stockholders.
3.1 Certificate of Incorporation of the Registrant. (Previously
filed on our current report on Form 8-K filed July 5, 2005.)
3.2 Certificate of Designation, Preferences and Rights of Series
D Preferred Stock. (Previously filed on our current report
on Form 8-K filed July 5, 2005.)
3.3 Certificate of Designation, Preferences and Rights of
Cumulative Convertible Preferred Stock, Series E.
(Previously filed on our current report on Form 8-K filed
July 5, 2005.)
3.4 Certificate of Designation, Preferences and Rights of Series
G Convertible Preferred Stock. (Previously filed on our
current report on Form 8-K filed July 5, 2005.)
3.5 Certificate of Designation, Preferences and Rights of Series
H Convertible Preferred Stock. (Previously filed on our
current report on Form 8-K filed July 5, 2005.)
3.6 Bylaws of the Registrant. (Previously filed on our current
report on Form 8-K filed July 5, 2005.)
4.1 Letter Agreement by and among GulfWest Energy Inc., a Texas
corporation, GulfWest Oil & Gas Company and the investors
listed on the signature page thereof, dated April 22, 2004.
(Previously filed with our Current Report on Form 8-K, dated
April 29, 2004 and filed with the Commission on May 10,
2004.)
30
4.2 Warrant Agreement made by and between GulfWest Energy Inc.,
and Highbridge/Zwirn Special Opportunities FUND, L.P., and
Drawbridge Special Opportunities Fund LP, Grantees, dated
and effective April 29, 2004. (Previously filed with our
Current Report on Form 8-K dated April 29, 2004 and filed
with the Commission on May 10, 2004.)
4.3 Shareholders Rights Agreement between GulfWest Energy Inc.
and OCM GW Holdings, LLC dated February 28, 2005.
(Previously filed with our Form 13D, Reg. No. 005-54301,
filed with the Commission on March 10, 2005.)
4.4 Omnibus and Release Agreement among GulfWest Energy Inc.,
OCM GW Holdings, LLC and those signatories set forth on the
signature page thereto, dated as of February 28, 2005.
(Previously filed with the Form 13D, Reg. No. 005-54301,
filed with the Commission on March 10, 2005.)
4.5 Share Transfer Restriction Agreement between J. Virgil
Waggoner and OCM GW Holdings, LLC, dated February 28, 2005.
(Previously filed with the Form 13D, Reg. No. 005-54301,
filed with the Commission on March 10, 2005.)
4.6 Irrevocable Proxy executed by J. Virgil Waggoner dated
February 28, 2005. (Previously filed with the Form 13D, Reg.
No. 005-54301, filed with the Commission on March 10, 2005.)
4.7 Exchange Agreement between GulfWest Energy Inc. and GulfWest
Oil & Gas Company, dated February 28, 2005. (Previously
filed with our Annual Report on Form 10-K for the year ended
December 31, 2004, File No. 001-12108, filed with the
Commission on March 31, 2005.)
4.8 Letter Agreement among OCM GW Holdings, LLC, OCM Principal
Opportunities Fund III, L.P., OCM Principal Opportunities
Fund III GP, LLC, Oaktree Capital Management, LLC, GulfWest
Energy Inc., GuflWest Oil & Gas Company and J. Virgil
Waggoner dated February 28, 2005 (Previously filed with our
Annual Report on Form 10-K for the year ended December 31,
2004, File No. 001-12108, filed with the Commission on March
31, 2005.)
4.9 Subscription Agreement among OCM GW Holdings, LLC, Allan D.
Keel and those individuals listed on the signature page
thereto, dated February 28, 2005. (Previously filed with the
Form 13D, Reg. No. 005-54301, filed with the Commission on
March 10, 2005.)
4.10 First Amendment to Warrant Agreement among GulfWest Energy
Inc., D.B. Zwirn Special Opportunities Fund, L.P. and
Drawbridge Special Opportunities Fund, dated February 28,
2005. (Previously filed with our Annual Report on Form 10-K
for the year ended December 31, 2004, File No. 001-12108,
filed with the Commission on March 31, 2005.)
*4.11 Registration Rights Agreement, dated March 20, 2006, among
Crimson Exploration Inc. and the stockholders of Core
Natural Resources, Inc.
10.1 Employment Agreement between Allan D. Keel and GulfWest
Energy, Inc., dated February 28, 2005. (Previously filed
with our Annual Report on Form 10-K for the year ended
December 31, 2004, File No. 001-12108, filed with the
Commission on March 31, 2005.)
10.2 Employment Agreement between E. Joseph Grady and GulfWest
Energy, Inc., dated February 28, 2005. (Previously filed
with our Annual Report on Form 10-K for the year ended
December 31, 2004, File No. 001-12108, filed with the
Commission on March 31, 2005.)
31
10.3 GulfWest Oil Company 1994 Stock Option and Compensation
Plan, amended and restated as of April 1, 2001 and approved
by the shareholders on May 18, 2001. (Previously filed with
our Proxy Statement on Form DEF 14A, filed with the
Commission on April 16, 2001.)
10.4 GulfWest Energy Inc. 2004 Stock Option Incentive Plan.
(Previously filed with our Annual Report on Form 10-K for
the year ended December 31, 2004, File No. 001-12108, filed
with the Commission on March 31, 2005.)
10.5 GulfWest Energy Inc. 2005 Stock Option Incentive Plan.
(Previously filed with our Annual Report on Form 10-K for
the year ended December 31, 2004, File No. 001-12108, filed
with the Commission on March 31, 2005.)
10.6 Form of GulfWest Energy Inc. 2005 Stock Incentive Plan Stock
Option Agreement. (Previously filed with our Annual Report
on Form 10-K for the year ended December 31, 2004, File No.
001-12108, filed with the Commission on March 31, 2005.)
10.7 Form of Warrant Agreement. (Previously filed with our Annual
Report on Form 10-K for the year ended December 31, 2004,
File No. 001-12108, filed with the Commission on March 31,
2005.)
10.8 Form of Indemnification Agreement for directors and
officers. (Previously filed with our Form 8-K, Reg. No.
001-12108, filedwith the Commission on July 21, 2005.)
10.9 Letter Agreement among D.B. Zwirn Special Opportunities
Fund, LP, GulfWest Oil & Gas, and Drawbridge Special
Opportunities Fund, LP, dated January 7, 2005. (Previously
filed with our Annual Report on Form 10-K for the year ended
December 31, 2004, File No. 001-12108, filed with the
Commission on March 31, 2005.)
10.10 Series G Subscription Agreement between GulfWest Energy
Inc. and OCM GW Holdings, LLC dated February 28, 2005.
(Previously filed with the Form 13D, Reg. No. 005-54301,
filed with the Commission on March 10, 2005.)
10.11 Series A Subscription Agreement between GulfWest Oil & Gas
Company and OCW GW Holdings, LLC dated February 28, 2005.
(Previously filed with the Form 13D, Reg. No. 005-54301,
filed with the Commission on March 10, 2005.)
10.12 Letter Agreement between W.L. Addison Investment, L.L.C.,
GulfWest Energy Inc., and Setex Oil and Gas Company dated
February 24, 2005 extending Option Agreement for the
Purchase of Oil and Gas Leases dated March 5, 2004.
(Previously filed with our Annual Report on Form 10-K for
the year ended December 31, 2004, File No. 001-12108, filed
with the Commission on March 31, 2005.)
10.13 Letter Agreement between W.L. Addison Investment, L.L.C.,
GulfWest Energy Inc., and Setex Oil and Gas Company dated
July 15, 2004 extending Option Agreement for the Purchase of
Oil and Gas Leases dated March 5, 2004. (Previously filed
with our Annual Report on Form 10-K for the year ended
December 31, 2004, File No. 001-12108, filed with the
Commission on March 31, 2005.)
10.14 Oil and Gas Property Acquisition, Exploration and
Development Agreement with Summit Investment Group-Texas,
L.L.C. effective December 1, 2001. (Previously filed with
our Registration Statement on Form S-1, Reg. No. 333-116048,
filed with the Commission on June 1, 2004.)
10.15 Credit Facility between GulfWest Energy Inc. and
Highbridge/Zwirn Special Opportunities FUND, L.P., and
Drawbridge Special Opportunities Fund LP, Grantees, dated
and effective April 29, 2004. (Previously filed with our
Registration Statement on Form S-1, Reg. No. 333-116048,
filed with the Commission on June 1, 2004.)
32
10.16 Employment Agreement between Tracy Price and GulfWest
Energy Inc., dated April 1, 2005. (Previously filed with our
Post Effective Amendment No. 1 to our Registration Statement
on Form S-1, Reg. No. 333-116048, filed with the Commission
on April 6, 2005.)
10.17 Employment Agreement between Tommy Atkins and GulfWest
Energy Inc., dated April 1, 2005. (Previously filed with our
Post Effective Amendment No. 1 to our Registration Statement
on Form S-1, Reg. No. 333-116048, filed with the Commission
on April 6, 2005.)
10.18 Employment Agreement between Jay S. Mengle and GulfWest
Energy Inc., dated April 1, 2005. (Previously filed with our
Post Effective Amendment No. 1 to our Registration Statement
on Form S-1, Reg. No. 333-116048, filed with the Commission
on April 6, 2005.)
10.19 Employment Agreement between Thomas R. Kaetzer and GulfWest
Energy Inc., dated April 1, 2005. (Previously filed with our
Post Effective Amendment No. 1 to our Registration Statement
on Form S-1, Reg. No. 333-116048, filed with the Commission
on April 6, 2005.)
10.20 Summary terms of June 2005 Director Compensation Plan.
10.21 Credit Agreement, dated July 15, 2005, among Crimson
Exploration Inc., Wells Fargo, N.A., as agent and a lender,
and each lender from time to time a party thereto.
(Previously filed with our Form 8-K, Reg. No. 001-12108,
filed with the Commission on July 21, 2005.)
10.22 Form of director restricted stock grant. (Previously filed
with our Form 8-K, Reg. No. 001-12108, filed with the
Commission on July 21, 2005.)
10.23 Limited Waiver of Shareholders Rights Agreement, dated July
14, 2005, by OCM GW Holdings, LLC. (Previously filed with
our Post Effective Amendment No. 2 to our Registration
Statement on Form S-1, Reg. No. 333-116048, filed with the
Commission on July 26, 2005.)
*10.24 First Amendment to Credit Agreement, dated as of March 6,
2006, among Crimson Exploration, Inc., Crimson Exploration
Operating, Inc., LTW Pipeline Co., and Wells Fargo Bank,
National Association.
22.1 Subsidiaries of the Registrant (included on [page 2] of
this Annual Report.
*23.1 Consent of Grant Thornton LLP
25 Power of Attorney (included on signature page of this Annual
Report).
*31.1 Certification of Chief Executive Officer pursuant to
Exchange Rule 13a-15(e) as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002; filed herewith.
*31.2 Certification of Chief Financial Officer pursuant to
Exchange Rule 13a-15(e) as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002; filed herewith.
*32.1 Certification of Chief Executive Officer pursuant to
18.U.S.C Section 1350 pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002; filed herewith.
32.2 Certification of Chief Financial Officer pursuant to
18.U.S.C Section 1350 pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002; filed herewith.
33
S I G N A T U R E S
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Crimson Exploration Inc.
Date: March 31,2006 By \s\ Allan D. Keel
-------------------------------
Allan D. Keel, President
POWER OF ATTORNEY
Know all men by these presents, that each person whose signature
appears below constitutes and appoints Allan D. Keel as his true and lawful
attorney-in-fact and agent, with full power of substitution, for him and in his
name, place, and stead, in any and all capacities to sign any and all amendments
or supplements to this Annual Report on Form 10-K, and to file the same, and
with all exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorney-in-fact and
agent full power and authority to do and perform each and every act and thing
requisite and necessary to be done as fully to all intents and purposes as he
might or could do in person, hereby ratifying and confirming all that said
attorney-in-fact and agent or his substitute or substitutes, may lawfully do or
cause to be done by virtue hereof.
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/ Allan D. Keel President, Chief Executive March 29, 2006
----------------- Officer and Director
Allan D. Keel
/s/ E. Joseph Grady Senior Vice President and March 29, 2006
------------------- Chief Financial Officer
E. Joseph Grady
/s/ Richard L. Creel Vice President Finance and March 29, 2006
-------------------- Chief Accounting Officer
Richard L. Creel
/s/ Skardon F. Baker Director March 29, 2006
--------------------
Skardon F. Baker
/s/B. James Ford Director March 29, 2006
----------------
B. James Ford
/s/ Lon Mc Cain Director March 29, 2006
---------------
Lon Mc Cain
/s/ Lee B. Backsen Director March 29, 2006
------------------
Lee B. Backsen
34
C O N T E N T S
Page
----
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS....................F-1
FINANCIAL STATEMENTS
Consolidated Balance Sheets.........................................F-3
Consolidated Statements of Operations...............................F-5
Consolidated Statements of Stockholders' Equity.....................F-6
Consolidated Statements of Cash Flows...............................F-8
Notes to Consolidated Financial Statements..........................F-9
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS...................F-31
FINANCIAL STATEMENT SCHEDULE
SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS.....................F-33
All other Financial Statement Schedules
have been omitted because they are either
inapplicable or the information required
is included in the financial statements
or the notes thereto.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Crimson Exploration Inc.
We have audited the accompanying consolidated balance sheets of Crimson
Exploration Inc. and subsidiaries as of December 31, 2005 and 2004, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for the years then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Crimson
Exploration Inc. and subsidiaries as of December 31, 2005 and 2004, and the
results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.
/s/GRANT THORNTON LLP
Houston, Texas
March 24, 2006
F-1
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Stockholders and
Board of Directors
Crimson Exploration Inc.
We have audited the accompanying consolidated statements of operations,
stockholders' equity and cash flows of Crimson Exploration Inc. for the year
ended December 31, 2003. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with standards of the Public Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statements presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated results of operations of
Crimson Exploration Inc. and its cash flows for the year ended December 31,
2003, in conformity with accounting principles generally accepted in the United
States of America.
As explained in Note 1 to the financial statements effective January 1, 2003,
the Company changed its accounting method for asset retirement obligations.
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 19, 2004
F-2
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2005 AND 2004
ASSETS
2005 2004
------------- -------------
CURRENT ASSETS
Cash and cash equivalents $ 474,393 $ 411,377
Accounts receivable - net of allowance
for doubtful accounts of $30,674 in 2005
and $-0-in 2004 3,498,488 1,674,448
Prepaid expenses 249,424 128,717
Deferred tax asset, net 1,602,773 1,594,336
------------- -------------
Total current assets 5,825,078 3,808,878
------------- -------------
PROPERTY AND EQUIPMENT
Oil and gas properties, using the successful
efforts method of accounting 65,598,691 58,557,072
Other property and equipment 1,560,464 1,437,206
Less accumulated depreciation, depletion and
amortization (12,936,096) (9,870,962)
------------- -------------
Net oil and gas properties and other property
and equipment 54,223,059 50,123,316
------------- -------------
OTHER ASSETS
Deposits 49,502 9,804
Investments 225,689 274,362
Debt issuance cost, net 274,214 1,756,316
Deferred tax asset, net 2,517,407 1,728,215
Derivative instruments - 175,273
------------- -------------
Total other assets 3,066,812 3,943,970
------------- -------------
TOTAL ASSETS $ 63,114,949 $ 57,876,164
============= =============
The Notes to Consolidated Financial Statements are an integral part of
these statements.
F-3
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2005 AND 2004
LIABILITIES AND STOCKHOLDERS' EQUITY
2005 2004
------------- -------------
CURRENT LIABILITES
Notes payable $ 40,300 $ 4,916,568
Notes payable - related parties - 2,140,000
Current portion of long-term debt 80,883 22,686,254
Current portion of long-term debt - related
parties - 112,192
Accounts payable - trade 4,107,441 4,654,561
Accrued expenses 487,453 940,587
Income taxes payable 31,075 118,255
Derivative instruments 2,108,583 1,680,800
------------- -------------
Total current liabilities 6,855,735 37,249,217
------------- -------------
NONCURRENT LIABILITIES
Long-term debt, net of current portion 1,103,232 805,450
Asset retirement obligation 1,311,133 1,144,854
------------- -------------
Total noncurrent liabilities 2,414,365 1,950,304
------------- -------------
OTHER LIABILITES
Derivative instruments 1,039,587 -
------------- -------------
Total liabilities 10,309,687 39,199,521
------------- -------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock 1,033 253
Common stock 28,991 19,394
Additional paid-in capital 72,851,626 34,062,502
Retained deficit (20,076,388) (15,405,506)
------------- -------------
Total stockholders' equity 52,805,262 18,676,643
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 63,114,949 $ 57,876,164
============= ==============
The Notes to Consolidated Financial Statements are an integral part of
these statements.
F-4
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
2005 2004 2003
------------- ------------- -------------
OPERATING REVENUES
Oil and gas sales $ 17,551,650 $ 11,101,114 $ 10,844,460
Operating overhead and other income 131,158 106,559 166,263
------------- ------------- -------------
Total operating revenues 17,682,808 11,207,673 11,010,723
------------- ------------- -------------
OPERATING EXPENSES
Lease operating expenses 5,585,297 4,879,754 5,527,841
Geological and geophysical 395,327 - -
Depreciation, depletion and amortization 3,130,647 2,184,815 2,226,123
Dry holes, abandoned property and impaired
assets 4,062,592 452,516 358,737
Asset retirement obligations 59,850 114,027 76,823
General and administrative 3,772,771 2,018,746 2,262,425
------------- ------------- -------------
Total operating expenses 17,006,484 9,649,858 10,451,949
------------- ------------- -------------
INCOME FROM OPERATIONS 676,324 1,557,815 558,774
------------- ------------- -------------
OTHER INCOME AND EXPENSE
Interest expense (1,302,894) (4,153,578) (3,363,330)
Debt issuance costs (1,955,501) (1,472,318) (1,000,000)
Loss from equity in investments (71,679) - -
Loss on sale of assets (38,501) (2,034,079) (19,848)
Unrealized gain (loss) on derivative
instruments (1,642,643) (1,505,527) 537,526
Forgiveness of debt - 12,475,612 -
------------- ------------- -------------
Total other income and (expense) (5,011,218) 3,310,110 (3,845,652)
------------- ------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES (4,334,894) 4,867,925 (3,286,878)
INCOME TAX BENEFIT 791,655 3,204,296 -
------------- ------------- -------------
INCOME (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLES (3,543,239) 8,072,221 (3,286,878)
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES, NET OF INCOME
TAXES - - 262,452
------------- ------------- -------------
NET INCOME (LOSS) (3,543,239) 8,072,221 (3,024,426)
DIVIDENDS ON PREFERRED STOCK
(PAID 2005-$1,127,643; 2004-$0-; 2003-$0) (3,562,472) (455,612) (127,083)
------------- ------------- -------------
NET INCOME (LOSS) AVAILABLE TO COMMON
SHAREHOLDERS $ (7,105,711) $ 7,616,609 $ (3,151,509)
============= ============= =============
NET INCOME (LOSS) PER SHARE, BASIC
BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLES $ (.27) $ .41 $ (.18)
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES - - .01
------------- ------------- -------------
NET INCOME (LOSS) PER SHARE BASIC $ (.27) $ .41 $ (.17)
============= ============= =============
NET INCOME (LOSS) PER SHARE, DILUTED BEFORE
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES $ (.27) $ .26 $ (.18)
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLES - - .01
------------- ------------- -------------
NET INCOME (LOSS) PER SHARE, DILUTED $ (.27) $ .26 $ (.17)
============= ============= =============
The Notes to Consolidated Financial Statements are an integral part of
these statements.
F-5
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
Number of Shares
Preferred Common
Stock Stock
------------- -------------
BALANCE, December 31, 2002 17,000 18,492,541
Issuance of warrants for additional financing - -
Issuance of preferred stock related to current financing 2,000 -
Net loss - -
------------- -------------
BALANCE, December 31, 2003 19,000 18,492,541
============= =============
Issuance of warrants for additional financing - -
Issuance of preferred stock related to current
refinancing 8,000 -
Conversion of preferred stock to Common Stock. (1,710) 901,428
Net income - -
------------- -------------
BALANCE, December 31, 2004 25,290 19,393,969
============= =============
Common stock issued for services and fees - 63,190
Preferred stock issued
Series A 2,000 -
Series G 81,000 -
Preferred stock conversions
Series A to common stock (3,250) 4,642,859
Series F to common stock (340) 170,000
Series H to common stock (1,450) 2,071,429
Common stock dividends paid
Series A preferred - 356,250
Series H preferred - 129,723
Options and warrants exercised - 2,163,223
Current year loss - -
Dividends paid on preferred stock - -
------------- -------------
BALANCE, December 31, 2005 103,250 28,990,643
============= =============
The Notes to Consolidated Financial Statements are an integral part of
these statements.
F-6
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
Preferred Common Additional Retained
Stock Stock Paid-in Capital Deficit
-------------- -------------- -------------- --------------
$ 170 $ 18,493 $ 28,258,212 $ (20,453,301)
- - 25,500 -
20 - 999,980 -
- - - (3,024,426)
-------------- -------------- -------------- --------------
190 $ 18,493 $ 29,283,692 $ (23,477,727)
============== ============== ============== ==============
- - 916,029 -
80 - 3,863,665 -
(17) 901 (884) -
- - - 8,072,221
-------------- -------------- -------------- --------------
$ 253 $ 19,394 $ 34,062,502 $ (15,405,506)
============== ============== ============== ==============
- 63 53,216 -
20 - 1,499,980 -
810 - 36,686,311 -
(33) 4,643 (4,610) -
(3) 170 (167) -
(14) 2,071 (2,057) -
- 357 330,957 (331,314)
- 130 114,858 (114,988)
- 2,163 110,636 -
- - - (3,543,239)
- - - (681,341)
-------------- -------------- -------------- --------------
$ 1,033 $ 28,991 $ 72,851,626 $ (20,076,388)
============== ============== ============== ==============
The Notes to Consolidated Financial Statements are an integral part of
these statements.
F-7
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
2005 2004 2003
-------------- -------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (3,543,239) $ 8,072,221 $ (3,024,426)
Adjustments to reconcile net income (loss) to
net cash
provided by operating activities:
Depreciation, depletion and amortization 3,130,647 2,184,815 2,226,123
Dry holes, abandoned property, impaired
assets 3,698,633 452,516 358,737
Asset retirement obligations 59,850 46,478 76,823
Stock compensation expense 44,164 - 25,500
Debt issuance cost 1,829,046 1,379,818 -
Discount on note payable 502,120 413,910 -
Forgiveness of debt - (12,475,612) -
Other financing costs - - 1,000,000
Deferred tax benefit ( 797,629) (3,322,551) -
Income tax payable (87,180) 118,255 -
Notes payable issued for interest expense - 61,046 -
Loss on sale of assets 38,501 2,034,079 19,848
Loss from equity in investments 71,679 - -
Unrealized (gain) loss on derivative
instruments 1,642,643 1,505,527 (537,526)
Cumulative effect of accounting change - - (262,452)
Provision for bad debts 30,674 - 29,201
(Increase) decrease in accounts receivable
- trade, net (1,997,038) (267,271) 232,443
(Increase) decrease in prepaid expenses (120,707) 30,552 144,637
Increase (decrease) in accounts payable and
accrued expenses (958,069) 279,859 1,235,503
-------------- -------------- --------------
Net cash provided by operating
activities 3,544,095 513,642 1,524,411
-------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Deposits returned (39,698) 10,338 -
Proceeds from sale of property and equipment 101,905 1,250,675 38,561
Capital expenditures (10,797,961) (6,141,988) (1,067,924)
-------------- -------------- --------------
Net cash used in investing activities (10,735,754) (4,880,975) (1,029,363)
-------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of preferred stock, net 38,187,121 3,363,745 -
Proceeds from common stock options exercised 56,450 - -
Payments on debt (34,258,132) (18,144,776) (1,672,288)
Proceeds from debt issuance 4,274,241 21,304,258 973,164
Debt issuance cost (323,664) (2,228,135) -
Dividends paid (681,341) - -
-------------- -------------- --------------
Net cash provided by (used in)
financing activities 7,254,675 4,295,092 (699,124)
-------------- -------------- --------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 63,016 (72,241) (204,076)
CASH AND CASH EQUIVALENTS,
Beginning of year 411,377 483,618 687,694
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS,
End of year $ 474,393 $ 411,377 $ 483,618
============== ============== ==============
CASH PAID FOR INTEREST $ 2,000,218 $ 3,718,940 $ 3,216,034
CASH PAID FOR INCOME TAXES $ 93,154 $ - $ -
============== ============== ==============
The Notes to Consolidated Financial Statements are an integral part of
these statements.
F-8
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Summary of Significant Accounting Policies
The following is a summary of the significant accounting policies
consistently applied by management in the preparation of the
accompanying consolidated financial statements.
Organization
On June 29, 2005, our predecessor, GulfWest Energy Inc., a
Texas corporation ("GulfWest"), merged with and into Crimson
Exploration Inc., a Delaware corporation ("Crimson"), for the purpose
of changing our state of incorporation from Texas to Delaware (the
"Reincorporation"). The Reincorporation was accomplished pursuant to an
Agreement and Plan of Merger, dated June 28, 2005, which was approved
by GulfWest's shareholders at the 2005 Annual Shareholders' Meeting
held June 1, 2005.
On January 5, 2006 we formed Crimson Exploration Operating,
Inc., a Delaware corporation, as our wholly owned subsidiary through
which all oil and gas operations will be conducted. Effective March 2,
2006, we merged all our subsidiaries, with the exception of LTW
Pipeline Co., into this newly formed corporation. LTW Pipeline Co.
remains an inactive subsidiary of Crimson Exploration Inc.
Cash and Cash Equivalents
We consider all highly liquid investment instruments purchased
with remaining maturities of three months or less to be cash
equivalents for purposes of the consolidated statements of cash flows
and other statements. We maintain cash on deposit in non-interest
bearing accounts, which, at times, exceed federally insured limits. We
have not experienced any losses on such accounts and believe we are not
exposed to any significant credit risk on cash and equivalents.
Non-cash Investing and Financing Activities
During the twelve month period ended December 31, 2005, we
settled $446,302 in dividends by issuing 485,973 shares of common stock
and we issued 29,100 shares of common stock to satisfy a $23,280 fee
for a loan extension prior to the sale of the Series G Preferred Stock.
In addition we recorded $29,999 in director fee expense associated with
the issuance of 34,090 shares of restricted common stock to directors
under the new Director Compensation Plan. Also accrued compensation of
$56,350 was converted to additional paid in capital when 87,500
options, accounted for under variable option accounting rules, were
exercised. During 2005, we also invested $23,006 in an oil and gas
partnership by contributing our cost basis in undrilled oil and gas
leases and acquired $142,323 in oil and gas properties in exchange of
an account receivable. In addition, we financed new field trucks for
$45,724.
During the twelve month period ended December 31, 2004, in
settlement of a contract we issued a note payable for $600,000 in
replacement of an account payable for $538,954 and the recognition of
an additional $61,046 of interest expense. Also, as a result of
refinancing debt in which we recorded a $12,475,612 forgiveness of
debt, we issued Common Stock warrants valued at $916,029 which was
recorded as a discount to the face value of the new note issued; we
issued $500,000 of preferred stock of a wholly owned subsidiary as a
commission to our financial advisor, and we recorded a $360,000 payable
for a loan termination fee. The termination fee was subsequently
increased by $48,000 as a result of increasing the principal amount of
the new note. We also financed field trucks for $78,036. In addition,
we invested $274,362 in a partnership by contributing our cost basis of
$76,732 in a natural gas pipeline and $197,630 in undeveloped oil and
gas leases to the partnership.
Use of Estimates in the Preparation of Financial Statements
The preparation of consolidated financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
F-9
Note 1. Organization and Summary of Significant Accounting Policies- continued
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the consolidated financial statements
and the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Oil and Gas Properties
We use the successful efforts method of accounting for oil and
gas producing activities. Costs to acquire mineral interests in oil and
gas properties, to drill and equip exploratory wells that find proved
reserves, and to drill and equip development wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves,
delay rentals and geological and geophysical costs are expensed (except
those costs used to determine a drillsite location).
As we acquire significant oil and gas properties, any unproved
property that is considered individually significant is periodically
assessed for impairment of value, and a loss is recognized at the time
of impairment by providing an impairment allowance. Capitalized costs
of producing oil and gas properties and support equipment, after
considering estimated dismantlement and abandonment costs and estimated
salvage values, are depreciated and depleted by the unit-of-production
method.
On the sale of an entire interest in an unproved property,
gain or loss on the sale is recognized, taking into consideration the
amount of any recorded impairment if the property has been assessed
individually. If a partial interest in an unproved property is sold,
the amount received is treated as a reduction of the cost of the
interest retained. On the sale of an entire or partial interest in a
proved property, gain or loss is recognized, based upon the fair values
of the interests sold and retained.
Other Property and Equipment
The following tables set forth certain information with
respect to our other property and equipment. Other property and
equipment is recorded at cost and we provide for depreciation and
amortization using the straight-line method over the following
estimated useful lives of the respective assets:
Assets Years
--------------------------------- -------------
Automobiles 3-5
Office equipment 7
Computer software 7
Gathering system 10
Well servicing equipment 10
F-10
Note 1. Organization and Summary of Significant Accounting Policies- continued
Other Property and Equipment - continued
Capitalized costs relating to other properties and equipment:
2005 2004
-------------- --------------
Automobiles $ 367,882 $ 285,384
Office equipment 196,189 148,173
Computer software 129,150 -
Gathering system 271,651 271,651
Well servicing equipment 595,592 731,998
-------------- --------------
1,560,464 1,437,206
Less accumulated depreciation (966,449) (872,364)
-------------- --------------
Net capitalized cost $ 594,015 $ 564,842
============== ==============
Impairments
We have adopted SFAS 144 "Accounting for the Impairment or
Disposal of Long- Lived Assets". Accordingly, impairments, measured
using fair market value, are recognized whenever events or changes in
circumstances indicate that the carrying amount of long-lived assets
(other than unproved oil and gas properties discussed above) may not be
recoverable and the future undiscounted cash flows attributable to the
asset are less than its carrying value.
Revenue Recognition
The Company follows the "sales" (takes or cash) method of
accounting for oil and gas revenues. Under this method, we recognize
revenues on production as it is taken and delivered to its purchasers.
The volumes sold may be more or less than the volumes we are entitled
to base our ownership interest in the property. These differences
result in a condition known in the industry as a production imbalance.
Our crude oil and natural gas imbalances are not significant.
Trade Accounts Receivable
We grant credit to creditworthy independent and major oil and
gas companies for the sale of crude oil and natural gas. In addition,
we grant credit to joint owners of oil and gas properties, which we
operate through our subsidiaries. Such amounts are secured by the
underlying ownership interests in the properties.
Trade accounts receivable are reported in the consolidated
balance sheets at the outstanding principal adjusted for any
chargeoffs. An allocation for doubtful accounts is recognized by
management based upon a review of specific customer balances,
historical losses and general economic conditions.
Fair Value of Financial Instruments
At December 31, 2005 and 2004, our financial instruments
consist of accounts receivable, notes payable and long-term debt.
Interest rates currently available to us for notes payable and
long-term debt with similar terms and remaining maturities are used to
estimate fair value of such financial instruments. Accordingly, since
interest rates on substantially all of our debt are variable, market
based rates, the carrying amounts are a reasonable estimate of fair
value.
Debt Issuance Costs
Debt issuance costs incurred are capitalized and subsequently
amortized over the term of the related debt on a straight-line basis.
F-11
Earnings (Loss) Per Share
Note 1. Organization and Summary of Significant Accounting Policies- continued
We have adopted Statement of Financial Accounting Standards
(SFAS) No. 128 "Earnings Per Share", which requires that both basic
earnings (loss) per share and diluted earnings (loss) per share be
presented on the face of the statement of operations. Basic earnings
(loss) per share are based on the weighted-average number of
outstanding common shares. Diluted earnings (loss) per-share are based
on the weighted-average number of outstanding common shares and the
effect of all potentially diluted common shares.
Stock Based Compensation
Stock-based compensation arrangements are accounted for using
the intrinsic value method as prescribed in Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees" ("APB Opinion
25") and related interpretations. Accordingly, compensation cost for
options granted to employees is measured as the excess, if any, of the
fair value of shares at the date of grant over the exercise price an
employee must pay to acquire the shares. No compensation cost has been
recognized in the accompanying consolidated financial statements
related to stock option awards.
In December 2004, the Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards ("SFAS")
No. 123 (revised 2004) "Share-Based Payment" ("SFAS No. 123R"), which
replaces SFAS No. 123, "Accounting for Stock-Based Compensation" and
supersedes APB Opinion 25. SFAS No. 123R requires all share-based
payments to employees, including grants of employee stock options, to
be recognized in the financial statements based on the fair values
beginning with the first interim period in fiscal year 2006, with early
adoption encouraged. The pro forma disclosures previously permitted
under SFAS No. 123 no longer will be an alternative to financial
statement recognition.
The Company adopted SFAS No. 123R on January 1, 2006 using the
modified prospective method in which compensation cost is recognized
beginning with the effective date (a) based on the requirements of SFAS
No. 123R for all share-based payments granted after January 1, 2006 and
(b) on the requirements of SFAS No. 123 for all awards granted to
employees prior to January 1, 2006 that remain unvested on January 1,
2006. The Company is estimating that the cost relating to stock options
granted through 2005 will be $2,335,219 for the year ended December 31,
2006 and $11,676,097 over the remaining life; however, due to the
uncertainty of the level of share-based payments to be granted in the
future, these amounts are estimates and subject to change.
During 2005, 2004 and 2003, we issued options and warrants
totaling: 22,400,000 in 2005; (non exercisable) 1,610,000 shares in
2004 (exercisable-1,085,000); 35,000 in 2003 (all exercisable),
respectively, to employees and directors as compensation. If we had
used the fair value method required by SFAS 123, our net income (loss)
and per share information would approximate the following amounts:
2005 2004 2003
-------------------------- ------------------------ --------------------------
As Reported ProForma As Reported ProForma As Reported ProForma
------------ ------------ ----------- ----------- ------------ ------------
SFAS 123
compensation cost $ - $ 2,008,123 $ - $ 425,500 $ - $ 7,350
APB 25
compensation cost $ - $ - $ 129,260 $ (129,260) $ - $ -
Net income (loss) $(7,105,711) $(9,113,834) $7,616,609 $7,320,369 $(3,151,509) $(3,158,859)
Income (loss) per
common share-basic $ (.27) $ (.34) $ .39 $ .39 $ (.17) $ (.17)
Income (loss) per
common share-diluted $ (.27) $ (.34) $ .26 $ .25 $ (.17) $ (.17)
F-12
Note 1. Organization and Summary of Significant Accounting Policies- continued
Stock Based Compensation - continued
We anticipate making additional stock based employee
compensation awards in the future.
We use the Black-Sholes option-pricing model to estimate the
fair value of the options and warrants (to employee and non-employees)
on the grant date. Significant assumptions include (1) risk free
interest rate 2005-3.0%, 2004- 3.0%; 2003 - 3.0%; (2) weighted average
expected life 2005-6.0, 2004- 3.0; 2003 - 3.4; (3) expected price
volatility of 2005- 92.75%, 2004- 94.32%; 2003 - 147.43% and (4) no
expected dividends.
Asset Retirement Obligations
Beginning in 2003, Statement of Financial Accounting Standards
No. 143, "Asset Retirement Obligations" ("SFAS 143") requires us to
recognize an estimated liability for the plugging and abandonment of
our oil and gas wells and associated pipelines and equipment.
Consistent with industry practice, historically we had assumed the cost
of plugging and abandonment would be offset by salvage value received.
This statement requires us to record a liability in the period in which
our asset retirement obligation ("ARO") is incurred. Upon initial
recognition of the liability, we must capitalize an additional asset
cost equal to the amount of the liability. In addition to any
obligation that arises after the effective date of SFAS 143, upon
initial adoption we recognized (1) a liability for existing ARO's, (2)
capitalized cost related to the liability, and (3) accumulated
depreciation, depletion and amortization on that capitalized cost
adjusting for the salvage value of related equipment.
The estimated liability is based on historical experience in
plugging and abandoning wells, estimated remaining lives of those wells
based on reserves estimates and federal and state regulatory
requirements. The liability is discounted using an assumed
credit-adjusted risk-free rate. Revisions to the liability could occur
due to changes in estimates of plugging and abandonment costs, changes
in the risk-free rate or remaining lives of the wells, or if federal or
state regulators enact new plugging and abandonment requirements. At
the time of abandonment, we are required to recognize a gain or loss on
abandonment to the extent that actual costs do not equal the estimated
costs.
The adoption of SFAS 143 resulted in a January 1, 2003
cumulative effect adjustment to record a $1,058,445 increase in the
carrying value of proved properties, a $484,390 decrease in
accumulated depreciation, depletion and amortization, a $1,280,383
increase in noncurrent liabilities, and a $262,452 gain, net of
tax.
Recent Accounting Pronouncements
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes
and Error Corrections: a replacement of APB Opinion No. 20 and FASB
Statement No. 3." SFAS No. 154 requires voluntary changes in accounting
principles to be applied retrospectively, unless it is impracticable to
determine either the period specific effects or the cumulative effects
of the change. SFAS No. 154's retrospective application requirement
replaces APB 20's requirement to recognize most voluntary changes in
accounting principle by including in net income of the period of the
change the cumulative effect of changing to the new accounting
principle. If retrospective application for all prior periods is
impracticable, the method used to report the change and the reason the
retrospective application is impracticable are to be disclosed.
Under SFAS No. 154, retrospective application will be the
transition method in the unusual event that a newly issued accounting
pronouncement does not provide specific transition guidance. It is
expected that most pronouncements will specify transition methods other
than the retrospective method. SFAS No. 154 is effective for accounting
changes made in fiscal years beginning after December 15, 2005, and the
adoption of this statement is expected to have no impact on the
Company's financial position or results of operations.
F-13
Note 1. Organization and Summary of Significant Accounting Policies- continued
In February of 2006, the FASB issued SFAS No. 155 "Accounting for
Certain Hybrid Financial Instruments." SFAS No. 155 amends SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" and
SFAS No. 140 "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities." SFAS No. 155 permits fair
value remeasurement for any hybrid financial instrument that contains
an embedded derivative that would otherwise require bifurcation,
clarifies which interest-only strips and principal-only strips are not
subject to the requirements of SFAS No. 133, establishes a requirement
to evaluate interests in securitized financial assets to identify
interests that are freestanding derivatives or that are hybrid
financial instruments that contain an embedded derivative requiring
bifurcation, clarifies that concentrations of credit risk in the form
of subordination are not embedded derivatives and amends SFAS No. 140
to eliminate the prohibition on a qualifying special-purpose entity
from holding a derivative financial instrument that pertains to a
beneficial interest other than another derivative financial instrument.
SFAS No. 155 is effective for all financial instruments acquired or
issued after the beginning of an entity's first fiscal year that begins
after September 15, 2006. At adoption, any difference between the total
carrying amount of the individual components of the existing bifurcated
hybrid financial instrument and the fair value of the combined hybrid
financial instrument should be recognized as cumulative-effect
adjustment to beginning retained earnings. Adoption of this statement
is expected to have no impact on the Company's financial position or
results of operations.
Note 2. Recapitalization
On April 27, 2004, we completed an $18,000,000 financing
package with new energy lenders. We used $15,700,000 in net proceeds
from the financing to retire existing debt of $27,584,145, resulting in
forgiveness of debt of $12,475,612, the elimination of a hedging
liability and the return to the Company of Series F Preferred Stock
with an aggregate liquidation preference of $1,000,000 (this preferred
stock, at the request of the Company, was transferred by the previous
lender to a financial advisor to the Company and to two affiliated
companies). The taxable gain resulting from these transactions was
completely offset by available net operating loss carryforwards for
income tax purposes. The term of the note was eighteen months and it
bore interest at the prime rate plus 11%. The rate increased by .75%
per month beginning in month ten. We paid the new lenders $1,180,000 in
cash fees and also issued them warrants to purchase 2,035,621 shares of
our common stock at an exercise price of $.01 per share, expiring in
five years (exercised in April, 2005). The warrants were subject to
anti-dilution provisions. In connection with the February 2005
transactions described below, the anti-dilution provisions were amended
such that additional issuances of stock (other than issuances to all
holders) would not trigger an adjustment to the number of shares
issuable upon exercise of the warrants.
On January 7, 2005, we amended our April 2004 credit agreement
to extend the target date for repayment to February 28, 2005. We
exercised this option on January 26, 2005 and issued 29,100 shares of
our common stock in connection with this amendment.
On February 28, 2005, we sold in a private placement, 81,000
shares of our Series G Preferred Stock to OCM GW Holdings, LLC
("OCMGW") for an aggregate offering price of $40.5 million. GulfWest
Oil and Gas Company ("GWOG"), a subsidiary of the Company, issued, in a
private placement, 2,000 shares of our Series A Preferred Stock,
having a liquidation preference of $1.0 million, to OCMGW for $1.5
million. Net proceeds of the offerings of approximately $38.2
million after expenses were used for the repayment of substantially
all of our outstanding debt and other past due liabilities and for
general corporate purposes.
The Series G Preferred Stock bears a coupon of 8% per year,
has an aggregate liquidation preference of $40.5 million (excluding
accumulated undeclared dividends), is convertible into common stock at
$0.90 per share and is senior to all of our capital stock. For the
first four years after issuance, we may defer the payment of dividends
on the Series G Preferred Stock and these deferred dividends will also
be convertible into our common stock at $0.90 per share. In addition,
the Series G Preferred Stock is entitled to nominate and elect a
majority of the members of our Board of Directors.
In connection with these recapitalization transactions, the
terms of the Series A Preferred Stock were amended such that by March
15, 2005, all such stock would either convert into a newly created
Series H Preferred Stock on a one for one basis or into common
stock at a conversion price of $0.35 per share.
F-14
Note 2. Recapitalization-continued
The Series H Preferred Stock is required to be paid a dividend of 40
shares of common stock per share of Series H Preferred Stock per year.
At March 15, 2005, holders of 6,700 shares of Series A Preferred
Stock converted to Series H Preferred Stock and holders of 3,250 shares
of Series A Preferred Stock converted to an aggregate 4,642,859 shares
of common stock. One Series H Preferred Stock holder converted its
shares of Series H Preferred Stock into 285,715 shares of common stock.
In April, 2005, an additional 1,250 shares converted into 1,785,714 of
common stock. The outstanding Series H Preferred Stock has an aggregate
liquidation preference of $2.625 million. The Series H Preferred Stock
is senior to all of our capital stock other than Series G Preferred
Stock (See Note 6).
In addition, we amended the terms of our 9,000 shares of
Series E Preferred Stock such that the coupon of 6% per year may be
deferred for the next four years and these deferred dividends will be
convertible into common stock at conversion price of $0.90 per share.
The original liquidation preference of the Series E Preferred Stock of
$500 per share remains convertible into common stock at $2.00 per
share. The Series E Preferred Stock has an aggregate liquidation
preference of $4.5 million (excluding accumulated undeclared
dividends), and is senior to all of our common stock, of equal
preference with our Series D Preferred Stock as to liquidation and
junior to our Series G and Series H Preferred Stock.
On May 17, 2005, we executed a promissory note for the benefit
of OCM GW Holdings, in the principal amount of $1 million, payable on
the earlier of July 17, 2005 or the day on which we are able to make
draws under a credit facility under which greater than $1 million may
be borrowed. Interest on the unpaid principal accrued at 4.59% per
annum. We repaid the note in full on July 19, 2005 from borrowings
under our new $100 million senior secured revolving credit facility.
On July 15, 2005, we entered into a $100 million senior
secured revolving credit facility with Wells Fargo Bank, National
Association. Borrowings under the new credit facility will be subject
to a borrowing base limitation based on our current proved oil and gas
reserves. The current borrowing base is set at $20 million and will be
subject to semi-annual redeterminations. The facility is secured by a
lien on all our assets, and the assets of our subsidiaries, as well as
a security interest in the stock of all our subsidiaries. The credit
facility has a term of three years, and all principal amounts, together
with all accrued and unpaid interest, will be due and payable in full
on June 30, 2008. Proceeds from extensions of credit under the facility
will be for acquisitions of oil and gas properties and for general
corporate purposes. The facility also provides for the issuance of
letters-of-credit up to a $3 million sub-limit. We incurred $323,662 in
issuance costs associated with the credit facility which are being
amortized over its life.
Advances under the facility will be in the form of either base
rate loans or Eurodollar loans. The interest rate on the base rate
loans fluctuates based upon the higher of (1) the lender's "prime rate"
and (2) the Federal Funds rate, plus a margin of 0.50%, plus a margin
of between 0.0% and 0.5% depending on the percent of the borrowing base
utilized at the time of the credit extension. The interest rate on the
Eurodollar loans fluctuates based upon the rate at which Eurodollar
deposits in the London Interbank market ("Libor") are quoted for the
maturity selected, plus a margin of 1.25% to 2.00% depending on the
percent of the borrowing base utilized at the time of the credit
extension. Eurodollar loans of one, three and nine months may be
selected by us. A commitment fee of 0.375% on the unused portion of the
borrowing base will accrue, and be payable quarterly in arrears.
The credit agreement includes usual and customary affirmative
covenants for credit facilities of this type and size, as well as
customary negative covenants, including, among others, limitation on
liens, hedging, mergers, asset sales or dispositions, payments of
dividends, incurrence of additional indebtedness, certain leases and
investments outside of the ordinary course of business. The credit
agreement also requires us to maintain a ratio of current assets to
current liabilities, except that any availability under the borrowing
base will be considered as an addition to current assets, and any
current assets or liabilities resulting from hedging agreements will be
excluded, of at least 1.0 to 1.0, an interest coverage ratio of EBITDAX
(earnings before interest, taxes, depreciation and amortization and
exploration expense) to cash interest expense of 3.0 to 1.0 and a
tangible net worth of at least $45 million, subject to adjustment based
on future results of operations and any sales of equity securities.
EBITDAX and tangible net worth are calculated without consideration of
unrealized gains and losses related to stock derivatives accounted for
under variable accounting rules for commodity hedges. At December 31,
2005 we were in compliance with the aforementioned financial covenants.
F-15
Note 3. Asset Retirement Obligations
A reconciliation of our asset retirement obligation liability is as
follows:
2005 2004
------------- -------------
Balance Beginning of Year $ 1,144,854 $ 1,357,206
Accretion expense 77,634 72,247
Liabilities incurred 65,852
Liability settled - (25,769)
Liability reduced from assets sold - (331,173)
Revisions 22,793 72,343
------------- -------------
Balance End of Year $ 1,311,133 $ 1,144,854
============= =============
Note 4. Accrued Expenses
Accrued expenses consisted of the following:
December 31, December 31,
2005 2004
------------- -------------
Accrued compensation $ 340,450 $ 129,260
Interest 72,003 769,327
Professional fees 75,000 42,000
------------- -------------
$ 487,453 $ 940,587
============= =============
F-16
Note 5. Notes Payable and Long-Term Debt
Notes payable are as follows:
2005 2004
------------- -------------
Non-interest bearing note payable to an unrelated party; payable out of
50% of the net transportation revenues from a certain natural gas
pipeline that is not yet in service; no due date. $ 40,300 $ 40,300
Promissory note payable to a former director at 8%; due May, 2001;
unsecured. Retired March, 2005 40,000
Promissory note payable to an unrelated party at 10%; payable on
demand; unsecured. Retired March, 2005 5,000
Promissory note payable to an unrelated party; payable on demand;
interest at 8%; interest increased to 12% on January 1, 2003; secured
by certain oil and gas properties. Retired March, 2005. 180,000
Note payable to a bank; due July, 2004; secured by guaranty of a
director; interest at prime rate (prime rate 5.25% at December
31, 2004 with a floor of 4.75% and a ceiling of 8.0%. Retired February, 2005 948,291
Promissory note payable to unrelated party; interest at 6%; due June,
2003. Retired January, 2005. 55,300
Promissory note payable to one of our directors; interest at 8%;
due on demand; unsecured. Retired March, 2005. 50,000
Promissory note payable to one of our directors; interest at
prime rate (prime rate 5.25% at December 31, 2004); due May, 2003;
secured by Common Stock of DutchWest Oil Company, our wholly
owned subsidiary. Retired March, 2005 1,450,000
Promissory note payable to an unrelated party at 8%; due June 2003;
secured by 4% in the last draft of the Common Stock of DutchWest
Oil Company, our wholly owned subsidiary. Retired March, 2005. 100,000
Promissory note payable to an unrelated party at 8%; due May 2003;
secured by 8% of the Common Stock of DutchWest Oil Company,
our wholly owned subsidiary. Retired March, 2005. 140,000
Note payable to an entity owned by two directors of the company, due
September 2004; interest at prime plus 2% (prime rate 5.25% at
December 31, 2004). Secured by oil and gas leases. Retired March,
2005. 600,000
Line of credit (up to $3,500,000) to a bank; due June 2004; secured
by the guaranty of a director; interest at prime rate (prime rate
5.25% at December 31, 2004) with a floor of 4.75%
and a ceiling of 8.0% Retired February, 2005. 3,447,677
------------- -------------
$ 40,300 $
7,056,568
============= =============
The weighted average interest rate for notes payable at
December 31, 2005 and 2004 was 0.00%, due to zero notes payable, and
5.79%, respectively.
F-17
Note 5. Notes Payable and Long-Term Debt-continued
Long-term debt is as follows:
2005 2004
------------- -------------
Line of credit (up to $3,000,000) to a bank; due July, 2005; secured
by the guaranty of a director; interest greater prime rates less
.25% or 5.25% (prime note 5.25% at December 31, 2004);
retired February 2005. $ 2,995,488
Subordinated promissory notes to various individuals at 9.5% interest
per annum; amounts include $50,000 due to related parties; past due.
Retired $100,000 March, 2005. 50,000 150,000
Notes payable to finance vehicles, payable in aggregate monthly
installments of approximately $4,000, including interest of 0.9% to
13% at December 31, 2005 per annum; secured by the related equipment;
due various dates through 2010. 97,833 99,900
Promissory note to a director; interest at 8.5%; due December 31, 2003.
Retired March, 2005. 62,192
Note payable to lender; interest at prime plus 11% (prime rate 5.25% at
December 31, 2004) interest only; due October, 2006; secured by
related oil and gas properties. Retired February, 2005. 19,021,880
Note payable to a bank with monthly principal payments of $36,000;
interest at prime plus 1% (prime rate 5.25% at December 31, 2004
with a minimum prime rate of 5.5%; final payment due November, 2003;
secured by related oil and gas properties; extended to July, 2007.
Retired February, 2005 1,224,000
Note payable to unrelated party to finance saltwater disposal well with
monthly installments of $4,540, including interest at 10% per annum;
final payment due January, 2005; secured by related well. Retired
March, 2005. 50,436
Line of credit (up to $20,000,000) to a bank due June 2008; secured by
oil and gas properties; interest at the higher of prime or Federal
Fund rate plus a margin of .50%. Rate at December 31, 2005 was 7.25% 1,036,282
------------- -------------
1,184,115 23,603,896
Less current portion (80,883) (22,798,446)
------------- -------------
Total long-term debt $ 1,103,232 $ 805,450
============= =============
Estimated annual maturities for long-term debt are as follows:
2006 $ 80,883
2007 31,600
2008 1,058,150
2009 10,449
2010 3,033
--------------
$ 1,184,115
==============
F-18
Note 6. Stockholders' Equity
Common Stock
------------
2005 2004
------------- -------------
Par value $.001; 200,000,000 shares authorized; 28,990,643
and 19,393,969 shares issued and outstanding as of
December 31, 2005 and 2004, respectively $ 28,991 $ 19,394
============= =============
Preferred Stock
Series D, par value $.01; 12,000 shares authorized; 8,000 shares issued
and outstanding at December 31, 2005 and 2004. The Series D preferred
stock does not pay dividends and is not redeemable. The liquidation
value is $500 per share. After three years from the date of issue,
and thereafter, the shares are convertible to Common Stock based upon
a value of $500 per Series D share
divided by $8 per share of Common Stock. 80 80
Series E, par value $.01; 9,000 shares authorized; 9,000 shares
issued and outstanding at December 31, 2005 and 2004. The
Series E pays dividends, as declared, at a rate of 2.5% per
annum increasing to 6% per annum July 1, 2004, has a
liquidation value of $500 per share, may be redeemed at
our option and, as amended, is convertible to Common Stock
based upon a value of $500 per Series E share divided
by $2 per share of Common Stock. 90 90
Series G, par value $.01; 81,000 shares authorized; 81,000 and 0 shares
issued and outstanding at December 31, 2005 and December 31, 2004
respectively. The Series G preferred stock pays dividends, as declared,
at a rate of $ 8% annually, has a liquidation value of $500 per share,
may be redeemed at our option and is convertible to Common Stock based
upon a value of $500 per Series F share divided by $.90 per share of
Common Stock. We may defer dividends for the first four years and
they are also convertible into our common stock at $.90 per share 810
Series H, par value $.01; 6,500 shares authorized; 5,250 shares
issued and outstanding at December 31, 2005. The Series H
preferred stock pays dividends, as declared, at a rate of
40 common shares per preferred share per annum, has a
liquidation value of $500 per share, may be redeemed at our option
and is exchangeable for Common Stock based upon a value of $500 per
Series H share divided by $.35 per share of Common Stock. 53
Series F, par value $.01; 2,000 shares authorized; 340 issued and
outstanding at December 31, 2004 The Series F preferred stock pays
dividends, as declared, at a rate of $2.5% per share annum, has a
liquidation value of $500 per share, may be redeemed at our option and
is convertible to Common Stock based upon a value of $500 per Series F
share divided by $1 per share of Common Stock 3
F-19
Note 6. Stockholders' Equity-continued
2005 2004
---- ----
Series A, par value $.01; 10,000 shares authorized; 7,950 shares issued
and outstanding at December 31, 2004. The Series A preferred stock
pays dividends, as declared, at a rate of 9 % per annum, has a
liquidation value of $500 per share, may be redeemed at our option and
is exchangeable for Common Stock based upon a value of $500 per Series
A share divided by $.35 per share of Common Stock. 80
------------- -------------
============= =============
$ 1,033 $ 253
============= =============
All classes of preferred shareholders have liquidation preference over
common shareholders of $500 per preferred share, plus accrued dividends.
Accumulated, unpaid and undeclared dividends at December 31, 2005 were
$3,002,994 (Series E $227,096; Series G $2,725,151; Series H $50,747).
Stock Options
-------------
We maintained a 1994 Stock Option and Compensation Plan (the "1994
Plan"), which terminated on February 11, 2004. There are options to purchase
310,000 shares of Common Stock still outstanding and exercisable under the 1994
Plan. Effective July 15, 2004, we implemented our 2004 Stock Option and
Compensation Plan (the "2004 Plan"). There are options to purchase 1,400,000
shares of Common Stock outstanding under the 2004 Plan. Effective February 28,
2005 we implemented our 2005 Stock Incentive Plan ("2005 Plan") and there were
options to purchase 22,400,00 shares of Common Stock outstanding under the 2005
Plan. Following is a schedule by year of the activity related to stock options,
including weighted-average ("WTD AVG") exercise prices of options in each
category.
2005 2004 2003
------------------------ ---------------------- ------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
-------- ------------- ------- ------------- ------- --------------
Balance, January 1 $ .60 1,949,000 $ .90 1,102,000 $ .90 1,067,000
Options issued $ 1.42 22,400,000 $ .48 1,610,000 $ .75 35,000
Options expired $ (.82) (239,000) $ (.80) (763,000) $ - -
------------- ------------- --------------
Balance, December 31 $ 1.36 24,110,000 $ .60 1,949,000 $ .90 1,102,000
============= ============= ==============
Options to purchase 1,375,000 shares of Common Stock were exercisable
at December 31, 2005, at exercise prices ranging from $.45 to $1.81 . Following
is a schedule by year and by exercise price of the expiration of our stock
options issued as of December 31, 2005:
2006 2007 2008 2009 Thereafter Total
----------- ----------- ------------ ----------- ------------- -------------
$ .45 825,000 240,000 235,000 1,300,000
$ .75 35,000 250,000 285,000
$ .83 65,000 65,000
$ .97 3,600,000 3,600,000
$1.16 2,066,333 2,066,333
$1.25 5,400,000 5,400,000
$1.70 11,333,667 11,333,667
$1.81 60,000 60,000
----------- ----------- ------------ ----------- ------------- -------------
65,000 35,000 1,135,000 240,000 22,635,000 24,110,000
=========== =========== ============ =========== ============= =============
Stock Warrants
--------------
We have issued a significant number of stock warrants for a variety of
reasons, including compensation to employees, additional inducements to purchase
our common or preferred stock, inducements related to the issuance
F-20
Note 6. Stockholders' Equity - continued
of debt and for payment of goods and services. Following is a schedule by year
of the activity related to stock warrants, including weighted-average exercise
prices of warrants in each category:
2005 2004 2003
------------------------ ------------------------- ------------------------
Wtd Avg Wtd Avg Wtd Avg
Prices Number Prices Number Prices Number
--------- ------------- ---------- ------------- --------- -------------
Balance, January 1 $ .38 4,000,621 $ .76 1,965,000 $ 1.24 2,181,754
Warrants issued $ .01 50,000 $ .01 2,035,621 $ .75 150,000
Warrants exercised
or expired $ (.17) (2,580,621) - - $ 3.61 (366,754)
------------- ------------- -------------
Balance, December 31 $ .74 1,470,000 $ .38 4,000,621 $ .76 1,965,000
============= ============= =============
Following is a schedule by year and by exercise price of the expiration
of our stock warrants issued as of December 31, 2005:
2006 2007 2008 Total
----------- ---------- ----------- -----------
$ .01 - 30,000 30,000
.75 1,440,000 - - 1,440,000
.875 - - - -
----------- ---------- ----------- -----------
1,440,000 - 30,000 1,470,000
=========== ========== =========== ===========
Note 7. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and denominators
used in computing income (loss) per share:
2005 2004 2003
-------------- --------------- --------------
Net income (loss) $ (3,543,239) $ 8,072,221 $ (3,024,426)
Preferred stock dividends (3,562,472) (455,612) (127,083)
-------------- --------------- --------------
Income (loss) available to common shareholders $ (7,105,711) $ 7,616,609 $ (3,151,509)
============== =============== ==============
Weighted-average number of shares
of Common Stock - basic
(denominator) 26,738,815 18,535,022 18,492,541
-------------- --------------- --------------
Income (loss) per share - basic $ (.27) $ .41 $ (.17)
============== =============== ==============
Weighted - average number of shares of Common
Stock - diluted (denominator) 26,738,815 31,618,275 18,492,541
-------------- --------------- --------------
Income (loss) per share - diluted $ (.27) $ .26 $ (.17)
============== =============== ==============
The numerator for basic earning per share is income (loss) available to
common shareholders. The numerator for diluted earnings per share is net income
in 2004 and net loss available to common shareholders in 2005 and 2003, due to
antidilution.
Potential dilutive securities (vested stock options, vested stock
warrants and convertible preferred stock) in 2005 and 2003 have not been
considered since we reported a net loss and, accordingly, their effects would be
antidilutive. The potentionaly dilutive shares would have been 56,061,975 shares
and 3,750,000 shares in 2005 and 2003 respectively.
F-21
Note 8. Related Party Transactions
As described in "Our Company - Financial Recapitalization" OCM GW
Holdings purchased 81,000 shares of Series G Preferred Stock and 2,000 shares of
Series A Preferred Stock for $42 million. Skardon F. Baker, a director, is an
employee of and B. James Ford, also a director is a managing director of Oaktree
Capital Management, LLC, the ultimate parent of OCM GW Holdings.
On May 17, 2005, we executed a promissory note for the benefit of OCM
GW Holdings, in the principal amount of $1 million, payable on the earlier of
July 17, 2005 or the day on which we are able to make draws under a credit
facility under which greater than $1 million may be borrowed. Interest on the
unpaid principal accrued at 4.59% per annum. We repaid the note in full on July
19, 2005 from borrowings under our new $100 million senior secured revolving
credit facility.
In connection with our April 2004 financing, J. Virgil Waggoner, a
director, and Star-Tex Trading Co., an entity managed by John Loehr, an officer
at the time and currently a director, purchased 3,000 shares and 200 shares,
respectively, of Series A Preferred Stock at a price of $500 per share. Both Mr.
Waggoner and Star-Tex, in connection with the February 2005 offering, elected to
exchange those shares for an equal number of shares of Series H Preferred Stock.
On October 23, 1995, we sold $25,000 each of 9% promissory notes in a
private offering to two trusts, the trustee of whom is John E. Loehr, an officer
at the time of the transaction and currently a director. The balance of the
notes plus accrued interest thereon at February 28, 2005 was $87,855. The note
was paid off in connection with the February 2005 offering.
In June, 1999, we issued a promissory note with interest at 8.5% to Mr.
Marshall A. Smith III, an officer and director at the time, in the amount of
$124,083 for accrued compensation. At February 28, 2005, the note had a balance
and accrued and unpaid interest of $99,360 and was being paid in monthly
installments of approximately $1,500 per month. The note was paid off in
connection with the February 2005 offering.
On November 6, 2002, Mr. J. Virgil Waggoner, a director, provided us a
loan in the initial amount of $1,200,000, which was subsequently increased to a
total of $1,500,000, which was outstanding at February 28, 2005. We issued Mr.
Waggoner a promissory note with interest at the prime rate (prime rate 4.0% at
May 26, 2004), secured by common stock of our wholly-owned subsidiary, DutchWest
Oil Company. Mr. Waggoner also received warrants to purchase 625,000 shares of
our common stock at an exercise price of $.75 per share. The note with accrued
interest was paid off in connection with the February 2005 offering, for a total
payment amount of $1,727,655.
On April 26, 2001, we obtained a line of credit of up to $2,500,000
from a bank for which two directors, Mr. J. Virgil Waggoner and Mr. Marshall A.
Smith, were guarantors. On April 3, 2002, the balance of the line of credit was
retired and a new line of credit of up to $3,000,000 was obtained from the bank
for which Mr. Waggoner and Mr. Smith were guarantors. The line of credit was
paid off in connection with the February 2005 offering.
On March 5, 2004, we entered into an Option Agreement for the Purchase
of Oil and Gas Leases (the "Addison Agreement") with W. L. Addison Investments
L.L.C., a private company owned by Mr. J. Virgil Waggoner and Mr. John E. Loehr,
two of our directors ("Addison"). Under the Addison Agreement, Addison agreed to
pay Summit, on our behalf, the non-recouped and outstanding advanced funds
amounting to $1,200,000, thereby retiring the Summit Agreement except for
certain surviving obligations with respect to areas of mutual interest and lease
bank agreements. Under the Summit Agreement, Summit loaned the company $600,000
for the workover of selected wells and Summit funded $600,000 for leasing in the
Iola field of east Texas. In return Summit earned a 8.5% working interest in the
workover wells and retained a 25% working interest in the Iola leases and
drilling program. For consideration of such payment, Addison acquired certain
oil and gas leases and wellbores from Summit but agreed to grant us a 180-day
redemption option (which was extended by mutual consent) to purchase the same
for $1,200,000, plus interest at the prime rate plus 2%. We tendered Addison a
promissory note in the amount of $600,000, with interest at the prime rate plus
2%, to substitute for an account payable to Summit, pursuant to the Summit
Agreement, in the same amount. The note would be considered paid in full if we
exercised the redemption option and paid the $1,200,000, plus interest. Summit
retained the right to participate up to a 25% working interest in the drilling
of any wells on the leases acquired by Addison. In the event we exercised the
redemption option, Addison could have, at its sole option, retained up to a 25%
working interest in the leases.
F-22
Note 8. Related Party Transactions-continued
The Addison Agreement was extended on July 15, 2004. We exercised the redemption
option and Addison received $1,275,353 at the closing of the February 2005
offering and waived its rights under the agreement to a working interest under
the leases.
As part of the April 2004 refinancing, the former lender agreed to
return all 2,000 shares of our Series F Preferred Stock held by it. Rather than
receive the shares as treasury shares (which would have meant cancellation of
the series) at our request the former lender transferred 400 of the shares to ST
Advisory Corp., an entity owned by John Loehr, our former CEO and a current
director, 400 of the shares to a financial advisor to the Company, and 200 of
the shares to Thomas R. Kaetzer, our President and Director at that time and
1,000 shares to Intermarket Management LLC, an entity partially owned by M.
Scott Manolis, one of our directors at that time. These transfers were to
compensate the financial advisor and Mr. Loehr, Kaetzer and Manolis for service
to the Company. On September 29, 2004, the financial advisor with 400 shares
transferred 140 shares to three non-management transferees.
Approximately $675,203 of the proceeds from the February 2005 offering
were used to pay accrued and unpaid dividends on the preferred stock. J. Virgil
Waggoner received $469,603 as a result. On December 22, 2004, ST Advisory Corp,
Intermarket Management LLC and Mr. Kaetzer converted their Series F preferred
shares into common stock. At the closing of the February 2005 offering they were
paid their proportionate share of accrued dividends due on the 2000 shares,
which totaled $17,167.
As part of the closing of the February 2005 offering, the investor and the
Company agreed to pay certain legal, accounting and other due diligence costs
and, also certain closing fees which totaled approximately $3.75 million. Of
this amount certain related parties received the following fees: OCM GW
$1,000,000; Intermarket Management LLC $500,000; Mr. Allan D. Keel $300,000
(which was used to invest in the subject offering).
In January 2005, Allan D. Keel, our current president and chief
executive officer, and another individual lent an aggregate of $200,000 to the
Company, which was repaid in full out of the proceeds of the February 2005
offering. Approximately $120,000 of that loan was attributable to Mr. Keel. In
addition, Mr. Keel received warrants to purchase 30,000 shares of Common Stock
at $0.01 share in connection with this transaction.
Note 9. Income Taxes
Income tax (benefit) for 2005 and 2004 consist of the following (we had
no income tax provision in 2003):
2005 2004
-------------- ---------------
Current tax $ 5,974 $ 118,255
Deferred tax benefit (797,629) (3,322,551)
-------------- ---------------
Income tax benefit $ (791,655) $ (3,204,296)
============== ===============
The following table summarizes changes in our deffered tax asset
obtained by applying a tax rate of 38% to the income (loss) before income taxes
for the year ended December 31, 2005 and 2004 and 34% for the years ended
December 31, 2003.
2005 2004 2003
------------- ------------- --------------
Tax (benefit) calculated at statutory
rate $ (1,647,259) $ 1,849,812 $ (1,028,305)
Increase (reductions) in taxes due to:
Income tax credits (5,974) (118,255)
Effect on non-deductible expenses 223,918 170,530 362,910
Change in valuation allowance 582,809 (4,693,201) 934,422
Other 48,877 (531,437) (269,027)
------------- ------------- --------------
Income tax benefit $ (797,629) $ (3,322,551) $ -
============= ============= ==============
F-23
Note 9. Income Taxes-continued
As of December 31, 2005 we had net operating loss carryforwards of
approximately $12,500,000, which are available to reduce future taxable income
and the related income tax liability. We expect we will not be able to utilize
carryforwards of approximately $9,100,000 due to the limitations of Internal
Revenue Code Section 382. The net operating loss carryforward expires at various
dates through 2023.
The components of the net deferred federal income tax assets
(liabilities) recognized in our consolidated balance sheets are as follows:
December 31, December 31,
2005 2004
-------------- --------------
Deferred tax assets
Net operating loss carryforwards $ 4,249,890 $ 4,873,859
Income tax credits 124,229 118,255
Oil and gas properties 1,461,983 198,596
Derivative instruments 1,196,304 572,100
Asset retirement obligations accretion 68,433 56,647
Deferred compensation 87,400 -
Accounts receivable allowance 11,656 -
-------------- --------------
Net deferred tax assets before
valuation allowance 7,199,895 5,819,457
Valuation Allowance (3,079,715) (2,496,906)
-------------- --------------
Net deferred tax assets $ 4,120,180 $ 3,322,551
============== ==============
At December 31, 2003 we had recorded a valuation allowance for the
entire balance of our deferred tax asset, due the uncertainty of our ability to
ever realize that benefit. Due to a change in circumstances described below, we
made an adjustment to the valuation allowance in 2004 resulting from a change in
judgment about the realizability of the net operating loss carryforwards in
future years. On February 28, 2005 we sold $ 42,000,000 in newly issued
preferred stock, resulting in proceeds of approximately $38,000,000, net of
offering expenses (See Note 2). With these proceeds we retired substantially all
of our notes payable, paid substantial amounts of accounts payable and accrued
expenses and retained approximately $2,000,000 for working capital. After these
transactions we had approximately $190,000 in notes payable remaining. Of the
retired notes, $20,094,000 bore interest at the prime rate plus 11%. As a result
of these transactions we believe we will generate enough future taxable income
to fully realize all of our available net operating loss carryforwards other
than those limited by Internal Revenue Code Section 382.
Note 10. Oil and Gas Hedging Activities
In the past we have entered into, and may in the future enter into,
certain derivative arrangements with respect to portions of our oil and natural
gas production to reduce our sensitivity to volatile commodity prices. During
2005 and 2004, we entered into price swaps and put agreements with financial
institutions. We believe that these derivative arrangements, although not free
of risk, allow us to achieve a more predictable cash flow and to reduce exposure
to price fluctuations. However, derivative arrangements limit the benefit to us
of increases in the prices of crude oil and natural gas sales. Moreover, our
derivative arrangements apply only to a portion of our production and provide
only partial price protection against declines in price. Such arrangements may
expose us to risk of financial loss in certain circumstances. We expect that the
monthly volume of derivative arrangements will vary from time to time. We
continuously reevaluate our price hedging program in light of increases in
production, market conditions, commodity price forecasts, capital spending and
debt service requirements. The following derivatives were in place at December
31, 2005.
F-24
Note 10. Oil and Gas Hedging Activities-continued
Fair Value Asset
Crude Oil Volume/ Month Average Price/ Unit Liability)
--------- ------------- ------------------- ----------
January 2006 thru March 2006 Collar 10,000 Bbls Floor $50.00-$59.00 Ceiling $ (123,840)
April 2006 thru December 2006 Collar 9,000 Bbls Floor $50.00-$59.00 Ceiling (568,944)
January 2007 thru December 2007 Collar 3,000 Bbls Floor $45.00-$59.45 Ceiling (311,988)
-----------------
$ 1,004,772
=================
Natural Gas Volume/ Month Average Price/ Unit Fair Value Asset
(Liability)
January 2006 thru December 2006 Collar 70,000 MMBTU Floor $6.00-$8.25 Ceiling $ (1,484,784)
January 2007 thru December 2007 Collar 20,000 MMBTU Floor $6.00-$6.95 Ceiling (658,614)
-----------------
$ 2,143,398
=================
Total fair value $ 3,148,170
Current portion 2,108,583
-----------------
Noncurrent portion $ 1,039,587
=================
The settlement date for the December 2006 oil contract is January
2007. Accordingly, it is recorded as noncurrent. The estimate fair value of this
contract is a liability of $68,985.
We also had the following put options in place at December 31, 2005, for the
months reflected.
Crude Oil Monthly Volume Price per Bbl
--------- -------------- -------------
January 2006 thru April 2006 7,000 Bbls $25.75 put
May 2006 thru October 2006 6,000 Bbls $25.75 put
November 2006 thru April 2007 5,000 Bbls $25.75 put
The value of these put options was minimal.
At the end of each reporting period we are required by SFAS 133
"Accounting for Derivative Instruments and Hedging Activities," to record on our
balance sheet the marked to market valuation of our derivative instruments. We
recorded a net liability for derivative instruments at December 31, 2005 and
2004 of $3,148,170 and $1,505,527 respectively. As a result of these agreements,
we recorded a non-cash charge to earnings, for unsettled contracts, of
$1,642,643 for the twelve month period ended December 31, 2005 and a charge of
$1,505,577 for the twelve month period ended December 31, 2004 and a non-cash
increase in earnings of $537,526 for the twelve month period ended December 31,
2003. The estimated change in fair value of the derivatives is reported in Other
Income and Expense as unrealized (gain) loss on derivative instruments.
For settled contracts, we realized losses, reflected as reductions in
oil and gas revenues, of $3,942,710, $1,841,209 and $1,496,303 for the twelve
month periods ended December 31, 2005, 2004 and 2003, respectively.
Note 11. Commitments and Contengencies
Lease Obligations
We lease office space at one location under a sixty-four (64) month
lease, which commenced December 1, 2001 and was amended May 30, 2002, after
expansion. The lease expires March 2007 and the annual commitments under the
lease are: 2006 - $135,323 and 2007 - $33,977. Total rent expense for the years
ended December 31, 2005, 2004 and 2003, were approximately $153,000, $142,500
and $134,500 respectively.
F-25
Note 11. Commitments and Contengencies-continued
Litigation
From time to time, we are involved in litigation arising out of our
operations or from disputes with vendors in the normal course of business. As of
March 26, 2006, we are not currently engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material effect on our
consolidated financial statements.
Employment Agreement
Effective February 28, 2005, we entered into employment agreements with our
President/Chief Executive Officer and Senior Vice President /Chief Financial
Officer. Each agreement has a term of three years with automatic yearly
extensions unless we or the officer elects not to extend the agreement. These
agreements provide for a base salary of $240,000 per year and $220,000
respectively, and a first year bonus of $120,000 and $110,000 respectively for
the year ending December 31, 2005, payable on or before February 26, 2006. If
the contracts are terminated by us without cause or by the employee for good
reason, and the employee has been in compliance with employee contract terms,
the employee may receive a cash payment equal to the greater of two times
current year base salary plus prior year bonus, or $600,000, and health
insurance benefits for two years in the future.
Effective April 1, 2005, we entered into employment agreements with our
four other Senior Vice Presidents. Each agreement has a term of two years with
automatic yearly extensions unless we or the officer elects not to extend the
agreement. These agreements provide for a base salary ranging from $180,000 to
$185,000, and have no termination clauses.
Note 12. Oil and Gas Properties (Unaudited)
The following tables set forth certain information with
respect to our oil and gas producing activities for the periods
presented: Capitalized Costs Relating to Oil and Gas Producing
Activities:
2005 2004
-------------- --------------
Unproved oil and gas properties $ 1,326,341 $ 81,366
Proved oil and gas properties 59,614,594 54,947,396
Support equipment and facilities 4,657,756 3,528,310
-------------- --------------
65,598,691 58,557,072
Less accumulated depreciation, depletion
and amortization (11,969,647) (8,998,598)
-------------- --------------
Net capitalized costs $ 53,629,044 $ 49,558,474
============== ==============
Results of Operations for Oil and Gas Producing Activities:
2005 2004 2003
------------- ------------- -------------
Oil and gas sales $ 17,551,650 $ 11,101,114 $ 10,844,466
Production costs (5,585,297) (4,879,754) (5,527,841)
Geological and geophysical (395,327) - -
Depreciation, depletion and amortization (2,971,050) (1,954,256) (1,527,727)
Dry holes, abandoned property and impaired
assets (4,062,592) (452,516) (358,737)
Asset retirement obligation (59,850) (114,027) (76,823)
Income tax expense - - -
------------- ------------- -------------
Results of operations for oil and gas
producing activities - income $ 4,477,534 $ 3,700,561 $ 3,353,338
============= ============= =============
F-26
Note 12. Oil and Gas Properties (Unaudited)-continued
The following table sets forth the composition of dry holes, abandoned
property and impaired assets:
2005 2004 2003
--------------- -------------- --------------
Dry holes $ 361,803 $ $ 70,342
Abandoned property 10,552 390,522 288,395
Impaired assets 3,690,237 61,994
--------------- -------------- --------------
$ 4,062,592 $ 452,516 $ 358,737
=============== ============== ==============
Costs Incurred in Oil and Gas Producing Activities:
2005 2004 2003
------------ ------------ ------------
Property Acquisitions
Proved $ 142,867 $ 6,742 $ -
Unproved 1,244,975 17,347 110,119
Development Costs 6,171,241 6,117,899 2,024,663
------------ ------------ ------------
$ 7,559,083 $ 6,141,988 $ 2,134,782
============ ============ ============
The following table shows oil and gas property dispositions:
2005 2004 2003
------------- ------------ ------------
Oil and gas properties $ 31,337 $ 5,425,040 $ 31,979
Accumulated DD&A - (1,659,001) (11,569)
------------- ------------ ------------
Net oil and gas properties $ 31,337 $ 3,766,039 $ 20,410
============= ============ ============
As a result of these sales we recorded a loss of $13,022, $2,029,932
and $ 20,409 in 2005, 2004 and 2003 respectively.
Oil and Gas Reserves Information
The estimates of proved oil and gas reserves utilized in the
preparation of the financial statements are estimated in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board, which require that reserve estimates be
prepared under existing economic and operating conditions with no provision for
price and cost escalations over prices and costs existing at year end except by
contractual arrangements.
We emphasize that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information
becomes available. Our policy is to amortize capitalized oil and gas costs on
the unit of production method, based upon these reserve estimates. It is
reasonably possible that, because of changes in market conditions or the
inherent imprecision of these reserve estimates, that the estimates of future
cash inflows, future gross revenues, the amount of oil and gas reserves, the
remaining estimated lives of the oil and gas properties, or any combination of
the above may be increased or reduced in the near term. If reduced, the carrying
amount of capitalized oil and gas properties may be reduced materially in the
near term.
F-27
Note 12. Oil and Gas Properties (Unaudited)-continued
The following unaudited table sets forth proved oil and gas reserves,
all within the United States, at December 31, 2005, 2004, and 2003, together
with the changes therein.
Crude Oil Natural Gas
(BBls) (Mcf)
------------- -------------
QUANTITIES OF PROVED RESERVES:
Balance December 31, 2002 5,521,906 34,158,823
Revisions (262,608) (308,080)
Extensions, discoveries and additions - -
Purchase - -
Sales - -
Production (221,335) (1,190,624)
------------- -------------
Balance December 31, 2003 5,037,963 32,660,119
Revisions (426,932) (2,857,240)
Extensions, discoveries and additions - 2,823,427
Purchase - -
Sales (1,474,115) (2,502,596)
Production (173,865) (1,033,433)
------------- -------------
Balance December 31, 2004 2,963,051 29,090,277
Revisions (78,648) (3,025,395)
Extensions, discoveries and additions - -
Purchase 953 67,631
Sales - -
Production (177,833) (1,482,250)
------------- -------------
Balance December 31, 2005 2,707,523 24,650,263
------------- -------------
PROVED DEVELOPED RESERVES:
December 31, 2003 3,772,926 24,642,407
============= =============
December 31, 2004 2,575,403 20,965,574
============= =============
December 31, 2005 2,423,196 19,658,165
============= =============
Standardized measure of discounted future net cash flows relating to
proved reserves:
2005 2004 2003
--------------- -------------- --------------
Future cash inflows $ 425,080,357 $ 290,998,312 $ 336,795,385
Future production and development
costs
Production 101,677,305 80,880,330 109,468,727
Development 27,467,896 24,141,982 21,460,459
--------------- -------------- --------------
Future cash flows before income
taxes 295,935,156 185,976,000 205,866,199
Future income taxes (91,664,228) (49,871,272) (46,885,360)
--------------- -------------- --------------
Future net cash flows after income
taxes 204,270,928 136,104,728 158,980,839
10% annual discount for estimated
timing of cash flows (85,873,789) (52,602,351) (70,653,419)
--------------- -------------- --------------
Standardized measure of discounted
future net cash flows $ 118,397,139 $ 83,502,377 $ 88,327,420
=============== ============== ==============
F-28
Note 12. Oil and Gas Properties (Unaudited)-continued
The following reconciles the change in the standardized measure of
discounted future net cash flows:
2005 2004 2003
---- ---- ----
Beginning of year $ 83,502,377 $ 88,327,420 $ 77,623,835
Changes from:
Purchases of proved reserves 230,291 - -
Sales of producing properties - (13,756,990) -
Extensions, discoveries and
improved
recovery, less related costs - 10,280,787 -
Sales of oil and gas produced,
net of
production costs (11,966,353) (6,221,360) (5,316,619)
Revision of quantity estimates (16,437,404) (12,614,337) (3,751,921)
Accretion of discount 11,415,713 11,439,568 9,889,881
Change in income taxes (22,544,291) (4,552,701) (4,793,281)
Changes in estimated future
development costs (6,461,166) (8,040,393) 2,003,801
Development costs incurred that
reduced future development
costs 6,171,241 6,117,899 2,024,663
Change in sales and transfer
prices,
net of production costs 88,819,225 8,245,446 16,470,113
Changes in production rates
(timing)
and other (14,332,494) 4,277,038 (5,823,052)
--------------- -------------- --------------
End of year $ 118,397,139 $ 83,502,377 $ 88,327,420
=============== ============== ==============
The calculations used to produce the figures in this table are based on
current cost and price factors at December 31 for each year. The average
sales prices utilized in the estimation of our proved reserves were $57.79
per Bbl and $10.90 per Mcf, $40.41 per Bbl and $5.89 per Mcf and $29.51 per
Bbl and $5.82 per Mcf, at December 31, 2005, 2004 and 2003, respectively.
Note 13. Subsequent Events (Unaudited)
On March 22, 2006 we purchased a 100% working interest (75% net revenue
interest) in leases on approximately 22,000 undeveloped acres in Culberson
County Texas. The acreage, believed to contain producible reserves in the
Barnett Shale and Atoka formations, is being acquired through our acquisition,
by merger, of Core Natural Resources, Inc. ("Core"), a privately-held entity
that was incorporated solely to hold the leases being acquired by us. Pursuant
to the merger agreement, each issued and outstanding share of common stock of
Core was converted into the right to receive (i) 5.39270725 shares of the common
stock, par value $.001 per share, of the Company (the "Stock Consideration") and
(ii) cash in an amount determined by dividing $706,123.25 by 600,000 (the "Cash
Consideration," and, together with the Stock Consideration, the "Merger
Consideration"). Pursuant to the merger agreement, we assumed $2,045,258 of Core
indebtedness that was paid off at the closing of the merger. The cash paid at
closing was funded from cash on hand and temporary borrowings under our credit
facility. As of the date of the merger agreement, 600,000 shares of Core Common
Stock were issued and outstanding. We issued 3,235,624 shares of our common
stock as the Stock Consideration. In a separate transaction, the Company will
also issue an additional 462,231 shares of common stock of the Company to a Core
stockholder as consideration for the assignment of a 2% overriding royalty
interest owned by that stockholder in the oil and gas leases of Core (giving us
a total 77% net revenue interest). All stock issued in conjunction with these
transactions is restricted stock subject to resale limitations under Rule 144(a)
of the Securities Act of 1933. Core stockholders were also granted certain
limited piggyback registration rights.
F-29
Note 14. Quarterly Results (Unaudited)
Summary data relating to the results of operations for each quarter for
the years ended December 31, 2005 and 2004 follows:
Three Months Ended
-----------------------------------------------------------
March 31 June 30 September 30 December 31
------------- ------------ -------------- --------------
2005
Net sales $ 3,664,333 $ 4,393,040 $ 4,736,297 $ 4,889,138
Gross profit 968,147 849,565 1,381,323 (2,522,711)
Net income (loss)
available to common
shareholders (3,547,445) (79,362) (2,188,922) (1,289,982)
Income(loss)per common
share Basic and
Diluted $ (.17) $ .00 $ (.08) $ (.04)
2004
Net sales $ 2,538,729 $ 2,535,266 $ 2,802,946 $ 3,330,732
Gross profit 363,693 (6,060) 542,172 658,010
Net income (loss)
available to common
shareholders (303,003) 9,323,281 (4,905,958) 3,502,289
Income(loss) per common
share-Basic $ (.02) $ .50 $ (.27) $ .19
Diluted $ (.02) $ .29 $ (.27) $ .10
F-30
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Crimson Exploration Inc.
We have audited in accordance with the standards of the Public Accounting
Oversight Board (United States) the consolidated financial statements of Crimson
Exploration Inc. and subsidiaries referred to in our report dated March 24,
2006, which is included in this Form 10-K. Our audit was conducted for the
purpose of forming an opinion on the basic financial statements taken as a
whole. Schedule II is presented for purposes of additional analysis and is not a
required part of the basic financial statements. The information for the years
ended December 31, 2004 and 2005 included in Schedule II has been subjected to
the auditing procedures applied in the audit of the basic financial statements
and, in our opinion, is fairly stated in all material respects in relation to
the basic financial statements taken as a whole.
/s/ GRANT THORNTON LLP
Houston, Texas
March 24, 2006
F-31
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM ON THE
FINANCIAL STATEMENT SCHEDULE
To the Stockholders and
Board of Directors
Crimson Exploration Inc.
Our report on the consolidated financial statements of Crimson Exploration Inc.
for the year ended December 31, 2003 is included on page F-2. In connection with
our audit of such consolidated financial statements, we have also audited the
related financial statement schedule for the year ended December 31, 2003 on
page F-33.
In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic consolidated financial statements taken as a
whole, presents fairly, in all material respects, the information required to be
included therein.
[GRAPHIC OMITTED][GRAPHIC OMITTED]
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 19, 2004
F-32
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
BALANCE BALANCE
AT AT
BEGINNING PROVISIONS/ RECOVERIES/ END
DECRIPTION OF PERIOD ADDITIONS DEDUCTIONS OF PERIOD
----------------------------------------- ------------- -------------- -------------- --------------
For the year ended
December 31, 2003
Valuation allowance for
deferred tax assets $ 6,255,685 $ 934,422 $ 7,190,107
============= ============= ============== =============
For the year ended
December 31, 2004
Valuation allowance for
deferred tax assets $ 7,190,107 $ (4,693,201) $ 2,496,906
============= ============== ============= =============
For the year ended
December 31, 2005
Accounts receivable $ $ 30,674 $ $ 30,674
============= ============= ============= =============
Valuation allowance for
deferred tax assets $ 2,496,906 $ 582,809 $ $ 3,079,715
============= ============= ============= =============
F-33