FORM 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 1-12108
CRIMSON EXPLORATION INC.
------------------------
(Exact name of Registrant as specified in its charter)
Texas 87-0444770
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
480 North 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)
GulfWest Energy Inc.
(Former name)
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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
YES NO X
----- -----
The number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date, August 15, 2005, was 28,838,144 shares
of Common Stock, $.001 par value.
CRIMSON EXPLORATION INC.
FORM 10-Q FOR THE QUARTER ENDED
JUNE 30, 2005
Page of
Form 10-Q
---------
Part I: Financial Statements
Item 1. Financial Statements
Consolidated Balance Sheets, June 30, 2005
and December 31, 2004 3
Consolidated Statements of Operations-for the three
months and six months ended June 30, 2005 and 2004 5
Consolidated Statements of Cash Flows-for the six
months ended June 30, 2005 and 2004 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations 15
Item 3. Quantitative and Qualitative Disclosures about Market Risk 18
Item 4. Controls and Procedures 19
Part II: Other Information
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 20
Item 4. Submission of Matters to a Vote of Security Holders 20
Item 6. Exhibits 22
Signatures 24
2
PART I. FINANCIAL INFORMATION
-----------------------------
ITEM 1. FINANCIAL STATEMENTS.
------- ---------------------
CRIMSON EXPLORATION INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, December 31,
2005 2004
(Unaudited) (Audited)
------------------- --------------------
CURRENT ASSETS
Cash and cash equivalents $ 1,083,304 $ 411,377
Accounts receivable - net of allowance
for doubtful accounts of $-0- in 2005 and 2004 2,696,344 1,674,448
Prepaid expenses 220,929 128,717
------------------- --------------------
Total current assets 4,000,577 2,214,542
------------------- --------------------
PROPERTY AND EQUIPMENT
Oil and gas properties, using the successful efforts
method of accounting 64,848,517 58,557,072
Other property and equipment 1,394,485 1,437,206
Less: accumulated depreciation, depletion and
amortization (11,296,458) (9,870,962)
------------------- --------------------
Net property and equipment 54,946,544 50,123,316
------------------- --------------------
OTHER ASSETS
Deposits 9,804 9,804
Investments 261,209 274,362
Debt issue cost, net 2,640 1,756,316
Deferred tax asset, net 4,172,353 3,322,551
Derivative instruments - 175,273
------------------- --------------------
Total other assets 4,446,006 5,538,306
------------------- --------------------
TOTAL ASSETS $ 63,393,127 $ 57,876,164
=================== ====================
The Notes to Consolidated Financial Statements are
an integral part of these statements.
3
CRIMSON EXPLORATION INC.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
June 30, December 31,
2005 2004
(Unaudited) (Audited)
---------------- ----------------
CURRENT LIABILITIES
Notes payable $ 40,300 $ 4,916,568
Notes payable - related parties 1,000,000 2,140,000
Current portion of long-term debt 87,886 22,686,254
Current portion of long-term debt - related parties - 112,192
Accounts payable - trade 3,355,741 4,654,561
Accrued expenses 279,880 940,587
Income taxes payable 118,255 118,255
Derivative insruments 2,156,988 1,680,800
---------------- ----------------
Total current liabilities 7,039,050 37,249,217
---------------- ----------------
NONCURRENT LIABILITIES
Long-term debt, net of current portion 84,134 805,450
Asset retirement obligations 1,183,176 1,144,854
---------------- ----------------
Total noncurrent liabilities 1,267,310 1,950,304
---------------- ----------------
OTHER LIABILITIES
Derivative instruments 743,245 -
---------------- ----------------
Total Liabilities 9,049,605 39,199,521
---------------- ----------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock 1,033 253
Common stock 28,783 19,394
Additional paid-in capital 72,679,741 34,062,502
Retained deficit (18,366,035) (15,405,506)
---------------- ----------------
Total stockholders' equity 54,343,522 18,676,643
---------------- ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 63,393,127 $ 57,876,164
================ ================
The Notes to Consolidated Financial Statements are
an integral part of these statements.
4
CRIMSON EXPLORATION INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Six Months
Ended June 30, Ended June 30,
2005 2004 2005 2004
------------- ------------- ------------ ------------
OPERATING REVENUES
Oil and gas sales $ 4,367,751 $ 2,494,347 $ 8,001,911 $ 4,994,987
Operating overhead and other income 25,289 40,919 55,462 79,008
------------- ------------- ------------ ------------
Total operating revenues 4,393,040 2,535,266 8,057,373 5,073,995
------------- ------------- ------------ ------------
OPERATING EXPENSES
Lease operating expenses 1,364,998 1,284,972 2,765,862 2,599,256
Depreciation, depletion and amortization 835,231 437,043 1,491,009 876,245
Dry holes, abandoned property and impaired assets 389,183 326,512 391,339 326,512
Accretion expense 19,161 20,358 38,322 40,716
General and administrative 934,902 472,441 1,553,129 873,633
------------- ------------- ------------ ------------
Total operating expenses 3,543,475 2,541,326 6,239,661 4,716,362
------------- ------------- ------------ ------------
INCOME (LOSS) FROM OPERATIONS 849,565 (6,060) 1,817,712 357,633
------------- ------------- ------------ ------------
OTHER INCOME AND EXPENSE
Interest expense (18,099) (1,014,609) (1,216,600) (1,934,777)
Other financing costs (5,000) (369,270) (1,910,159) (369,270)
Loss from equity in investments (36,159) - (36,159) -
Loss on sale of assets (25,894) (226,809) (38,916) (226,809)
Unrealized gain (loss) on derivative instruments 618,775 (1,438,249) (1,394,706) (1,150,402)
Forgiveness of debt - 12,475,612 - 12,475,612
------------- ------------- ------------ ------------
Total other income and expense 533,623 9,426,675 (4,596,540) 8,794,354
------------- ------------- ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES 1,383,188 9,420,615 (2,778,828) 9,151,987
INCOME TAXES (537,889) - 849,802 -
------------- ------------- ------------ ------------
NET INCOME (LOSS) 845,299 9,420,615 (1,929,026) 9,151,987
DIVIDENDS ON PREFERRED STOCK (924,661) (97,334) (1,697,781) (131,709)
------------- ------------- ------------ ------------
NET INCOME (LOSS) AVAILABLE TO
COMMON SHAREHOLDERS $ (79,362) $ 9,323,281 $(3,626,807) $ 9,020,278
============= ============= ============ ============
NET INCOME (LOSS) PER COMMON SHARE,
BASIC $ (.00) $ .50 $ (.15) $ .49
============= ============= ============ ============
DILUTED $ (.00) $ .29 $ (.15) $ .34
============= ============= ============ ============
The Notes to Consolidated Financial Statements are
an integral part of these statements
5
CRIMSON EXPLORATION INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
-------------------------------------
2005 2004
----------------- -----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (1,929,026) $ 9,151,987
Adjustments to reconcile net income (loss) to net cash
Provided by operating activities:
Depreciation, depletion and amortization 1,491,009 876,245
Accretion expense 38,322 40,716
Stock option expense 19,670 -
Stock compensation expense 29,999 -
Debt issue cost expense 1,779,596 -
Discount on note payable 502,120 107,177
Loss from equity in investments 36,159 -
Deferred tax benefit (849,802) -
Forgiveness of debt - (12,475,612)
Note payable issued and charged to interest - 61,046
Loss on sale of property and equipment 38,915 226,809
Dry holes, abandoned property and impaired assets - 326,512
Unrealized loss on derivative instruments 1,394,706 1,150,402
Increase in accounts receivable - trade, net (1,010,646) (449,463)
(Increase ) decrease in prepaid expenses (92,212) 58,446
Decrease in accounts payable and accrued expenses (1,979,197) (1,098,150)
----------------- -----------------
Net cash used in operating activities (530,387) (2,023,885)
----------------- -----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment 101,491 -
Capital expenditures (6,431,925) (975,513)
----------------- -----------------
Net cash used in investing activities (6,330,434) (975,513)
----------------- -----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of preferred stock, net 38,212,517 3,393,601
Proceeds from common stock warrants exercised 200 -
Payments on debt (31,815,988) (17,176,706)
Proceeds from debt issuance 1,820,000 18,830,258
Debt issue cost (2,640) (1,748,910)
Dividends paid (681,341) -
----------------- -----------------
Net cash provided by financing activities 7,532,748 3,298,243
----------------- -----------------
INCREASE IN CASH AND CASH EQUIVALENTS 671,927 298,845
CASH AND CASH EQUIVALENTS,
Beginning of period 411,377 483,618
----------------- -----------------
CASH AND CASH EQUIVALENTS,
End of period $ 1,083,304 $ 782,463
================= =================
CASH PAID FOR INTEREST $ 718,768 $ 1,506,352
================= =================
The Notes to Consolidated Financial Statements are
an integral part of these statements.
6
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2005 AND 2004
(UNAUDITED)
1. BASIS OF PRESENTATION
During interim periods, we follow the accounting policies set forth in our
Annual Report on Form 10-K filed with the Securities and Exchange
Commission. Users of financial information produced for interim periods are
encouraged to refer to the footnotes contained in the Annual Report when
reviewing interim financial results.
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.
The accompanying financial statements include the Company and its
wholly-owned subsidiaries: RigWest Well Service, Inc. formed September 5,
1996; GulfWest Texas Company formed September 23, 1996; DutchWest Oil
Company formed July 28, 1997; Southeast Texas Oil and Gas Company, L.L.C.
acquired September 1, 1998; SETEX Oil and Gas Company formed August 11,
1998; GulfWest Oil & Gas Company formed February 8, 1999; LTW Pipeline Co.
formed April 19, 1999; GulfWest Development Company formed November 9,
2000; GulfWest Oil & Gas Company (Louisiana) LLC formed July 31, 2001; and,
S.G.C. Transmission, LLC formed December 30, 1993. All material
intercompany transactions and balances are eliminated upon consolidation.
As a result of our April 27, 2004 refinancing we recorded $11,884,145 in
forgiveness of debt and a hedging liability of $591,467 was eliminated. At
December 31, 2004 we reclassified the eliminated hedging liability to
forgiveness of debt. This reclassification is reflected in the June 30,
2004 periods. Certain other prior period amounts have also been
reclassified to conform with current year presentations.
In management's opinion, the accompanying interim financial statements
contain all material adjustments, consisting only of normal recurring
adjustments necessary to present fairly the financial condition, the
results of operations, and the cash flows of Crimson Exploration Inc. for
the interim periods.
2. NON-CASH INVESTING AND FINANCING ACTIVITIES
During the six month period ended June 30, 2005 we settled $350,163 in
dividends by issuing 377,917 shares of common stock and we issued 29,100
shares of common stock to satisfy and record 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 common stock to directors under the new Director
Compensation Plan. Also, on March 30, 2005 one of our employees exercised
25,000 common stock options for $11,250 which is recorded as an account
receivable. Under our cashless exercise procedures, the stock has been
posted for sale by a broker and the receivable will be settled when the
stock is sold. During the period, we invested $23,006 in an oil and gas
partnership by contributing our cost basis in undrilled oil and gas leases.
In addition, we financed new field trucks for the $45,724 cost.
During the six month period ended June 30, 2004, we issued a note payable
for $600,000 in exchange for an account payable for $538,954 and $61,046 in
related interest expense was recorded. Also, in conjunction with the
refinancing of debt in April 2004; we issued common stock warrants valued
7
at $916,029 which were recorded as a note discount, we issued $500,000 of
preferred stock of a wholly owned subsidiary as a commission to a financial
advisor, we recorded a $360,000 payable for a loan termination fee and we
obtained and recorded $12,475,612 in debt forgiveness.
3. DERIVATIVE INSTRUMENTS
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 June 30,
2005 or were added subsequent to that date and are effective for the
production periods shown.
Fair Value
Asset
Crude Oil Volume/ Month Average Price/ Unit (Liability)
--------- ------------- ------------------- -----------
May 2004 thru October 2005 Swap 10,000 Bbls $32.00 $ ( 1,277,168)
April 2005 thru June 2005 Swap 2,000 Bbls $56.50 $ 161
July 2005 thru October 2005 Swap 1,000 Bbls $56.50 $ (6,131)
November 2005 thru December 2005 Swap 11,000 Bbls $56.50 $ (59,078)
January 2006 thru March 2006 Collar 10,000 Bbls Floor $50.00-$59.00 Ceiling $ (114,183)
April 2006 thru December 2006 Collar 9,000 Bbls Floor $50.00-$59.00 Ceiling $ (290,889)
January 2007 thru December 2007 Collar 3,000 Bbls Floor $45.00-$59.45 Ceiling $ (156,046)
Fair Value
Asset
Natural Gas Volume/ Month Average Price/ Unit (Liability)
----------- ------------- ------------------- -----------
June 2004 thru October 2005 Swap 60,000 MMBTU $5.15 $ ( 431,230)
April 2005 thru June 2005 Swap 20,000 MMBTU $7.45 $ -
July 2005 thru October 2005 Swap 10,000 MMBTU $7.45 $ 19,639
November 2005 thru December 2005 Swap 70,000 MMBTU $7.45 $ (19,668)
January 2006 thru December 2006 Collar 70,000 MMBTU Floor $6.00-$8.25 Ceiling $ (367,919)
January 2007 thru December 2007 Collar 20,000 MMBTU Floor $6.00-$6.95 Ceiling $ (202,123)
These volumes represent approximately 75% of the estimated production (for
both oil and natural gas) on current proved producing properties for the
remainder of 2005 and for 2006 and approximately 30% of estimated
production for 2007.
We also had the following put options in place at June 30, 2005, for the
months reflected.
Fair Value
Asset
Crude Oil Monthly Volume Price per Bbl (Liability)
--------- -------------- ------------- -----------
November 2005 thru April 2006 7,000 Bbls $25.75 put $ 212
May 2006 thru October 2006 6,000 Bbls $25.75 put $ 1,288
November 2006 thru April 2007 5,000 Bbls $25.75 put $ 2,902
8
The following puts on natural gas were terminated effective April 1, 2005.
Natural Gas Monthly Volume Price per MMBTU
----------- -------------- ---------------
November 2005 thru April 2006 50,000 MMBTU $4.50 put
May 2006 thru October 2006 40,000 MMBTU $4.50 put
November 2006 thru April 2007 30,000 MMBTU $4.50 put
At the end of each reporting period we are required by SFAS 133 to record
on our balance sheet the marked to market valuation of our derivative
instruments. These valuations are based on the NYMEX strip prices for those
future periods, as of the balance sheet date. As a result of these
agreements, we recorded a non-cash charge to earnings, for unsettled
contracts, of $1,394,706 for the six month period ended June 30, 2005 and a
charge of $1,150,402 for the six month period ended June 30, 2004. For
settled contracts, during the six month periods we realized a cash charge
to earnings of $1,469,718 for the six month period ended June 30, 2005 and
$702,649 for the six month period ended June 30, 2005, which are included
in oil and gas sales.
The estimated change in fair value of the derivatives is reported in Other
Income and Expense as unrealized (gain) loss on derivative instruments.
4. STOCK BASED COMPENSATION
In October 1995, SFAS No. 123, "Stock Based Compensation," (SFAS 123) was
issued. This statement requires that we choose between two different
methods of accounting for stock options and warrants. The statement defines
a fair-value-based method of accounting for stock options and warrants but
allows an entity to continue to measure compensation cost for stock options
and warrants using the accounting prescribed by APB Opinion No. 25 (APB
25), "Accounting for Stock Issued to Employees." Use of the APB 25
accounting method results in no compensation cost being recognized if
options are granted at an exercise price at the current market value of the
stock on the date of grant or higher. We will continue to use the intrinsic
value method under APB 25 but are required by SFAS 123 to make pro forma
disclosures of net income (loss) and earnings (loss) per share as if the
fair value method had been applied in our 2005 and 2004 financial
statements.
We use the Black Sholes option pricing model to estimate the fair value of
the options. If we had used the fair value method required by SFAS 123, our
net loss and per share information would approximate the following amounts:
Three Months 2005 2004
----------------------- ------------------------------ ------------------------------
As Reported Proforma As Reported Proforma
SFAS 123
compensation cost $ $ 624,204 $ $ 5,250
APB 25
compensation cost $ (50,580) $ 50,580 $ $
Net income (loss) $ (79,362) $ (754,146) $ 9,323,281 $ 9,318,031
Income (loss) per
common share,
Basic $ (.00) $ (.03) $ .50 $ .50
Diluted $ (.00) $ (.03) $ .29 $ .29
----------------------------------------------------------------------------------------
9
Six Months 2005 2004
----------------------- ------------------------------ ------------------------------
As Reported Proforma As Reported Proforma
SFAS 123
compensation cost $ $ 765,729 $ $ 5,250
APB 25
compensation cost $ 19,670 $ (19,670) $ $
Net income (loss) $(3,626,807) $(4,372,866) $ 9,020,278 $9,015,028
Income (loss) per
common share,
Basic $ (.15) $ (.18) $ .49 $ .49
Diluted $ (.15) $ (.18) $ .34 $ .34
---------------------------------------------------------------------------------------
On December 16, 2004, the Financial Accounting Standards Board (FASB)
issued FASB Statement No. 123 (revised 2004), Share-Based Payments which is
a revision of FASB No. 123, Accounting for Stock-Based Compensation.
Statement 123 (R) supercedes APB opinion No. 25, Accounting for Stock
Issued to Employees, and amends FASB Statement No. 95, Statement of Cash
Flows. Generally, the approach in Statement 123 (R) is similar to the
approach described in Statement 123. However, Statement 123 (R) requires
all share-based payments to employees, including grants of employee stock
options, to be recognized in the income statement based on their fair
values. Pro forma disclosure will no longer be an alternative. The
effective date of this statement will be our first quarter of 2006.
5. FINANCING ACTIVITY
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 will be 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.
10
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 will be subject to a borrowing base
limitation based on our current proved oil and gas reserves. The initial
borrowing base is set at $20 million and will be subject to semi-annual
redeterminations, with the first redetermination to be December 1, 2005.
The facility will be 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. On
August 15, 2005, the outstanding balance under our facility was $1.5
million.
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
11
the time of the credit extension. Eurodollar loans of one, three and six
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 June
30, 2005 we were in compliance with the aforementioned financial covenants.
6. NOTES PAYABLE
Notes payable and related party notes payable are as follows:
June 30, December 31,
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
12
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
Note payable to a related party, due July 2005, interest at 4.59%.
Retired July, 2005. 1,000,000
--------------- ---------------
$ 1,040,300 $ 7,056,568
=============== ===============
Long-term debt is as follows:
June 30, 2005 December 31
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. 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 9% to
13% per annum; secured by the related equipment; due various
dates through 2010. 122,020 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
13
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
--------------- ---------------
172,020 23,603,896
Less current portion 87,886 (22,798,446)
--------------- ---------------
Total long-term debt $ 84,134 $ 805,450
=============== ===============
7. TAXES
For the six month period ended June 30, 2005 we incurred a taxable loss of
approximately $2.8 million and tax differences of approximately $.9 million
resulting in an approximately $.8 million increase in our deferred tax
asset. We expect to fully utilize this increase in deferred tax assets in
the future. Deferred tax assets are shown net of a $2.5 million valuation
allowance. The valuation allowance was recorded because we expect we will
not be able to use net operating loss carryforwards of approximately $6.6
million due to the limitations of Internal Revenue Code Section 382.
8. STOCKHOLDERS EQUITY
The following table sets forth the changes in the stockholder's equity
during the period ended June 30, 2005.
NUMBER OF SHARES
------------------------------
PREFERRED COMMON COMMON PREFERRED ADDITIONAL RETAINED
STOCK STOCK STOCK STOCK PAID-IN CAPITAL DEFICIT
--------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2004 25,290 19,393,969 $19,394 $253 $34,062,502 $(15,405,506)
Common stock issued for services and fees 63,190 63 53,216
Preferred stock issued
Series A 2,000 20 1,499,980
Series G 81,000 810 36,711,706
Preferred stock conversions
Series A to common stock (3,250) 4,642,859 4,643 (33) (4,610)
Series F to common stock (340) 170,000 170 (3) (167)
Series H to common stock (1,450) 2,071,429 2,072 (14) (2,057)
Common stock dividends paid
Series A Preferred 356,250 356 330,956
Series H Preferred 21,667 22 18,828
Options and warrants exercised 2,063,224 2,063 9,387
Current year loss (1,929,026)
Dividends paid on preferred stock (1,031,503)
--------------------------------------------------------------------------------------
BALANCE JUNE 30, 2005 103,250 28,782,588 $28,783 $1,033 $72,679,741 $(18,366,035)
======================================================================================
Also during the period the holders of the remaining 6,700 shares of the
Series A Preferred Stock, of our wholly owned subsidiary GulfWest Oil and
Gas Company, converted to our Series H Preferred Stock.
14
Dividends on all classes of our preferred stock are cumulative until
declared as payable by our Board of Directors. Our Series E Preferred Stock
accumulates at 6% per annum payable in cash, Series G Preferred Stock
accumulates at 8% per annum payable in cash and Series H Preferred Stock
accumulates at 40 shares of our common stock per share of the Series H
Preferred Stock per annum.
The following table sets forth the accumulated value of undeclared
dividends of our preferred stock at June 30, 2005.
Series E Preferred Stock $ 90,986
Series G Preferred Stock 1,091,836
Series H Preferred Stock 56,499
-------------------
$ 1,239,321
===================
The Series E and Series G dividends are convertible to our common stock at
$.90 per common share. The Series H Preferred Stock has no conversion
feature for unpaid dividends. These dividends call for payment of 10 common
shares per quarter for each preferred share. Payments are current.
ITEM 2. 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. This represents over
98% of our gross revenues.
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, and (6) the level and success of acquiring or finding new
reserves, and the acquisition, finding and development costs incurred in
adding these reserves.
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 Securities and Exchange Commission and the Financial
Accounting Standards Board, which require that reserve estimates be
15
prepared under existing economic and operating conditions with no provision
for price and cost escalations over prices and costs existing at period
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 will change
in the future.
Comparative results of operations for the periods indicated are discussed
below.
Three-Month Period Ended June 30, 2005 compared to Three Month Period Ended
June 30, 2004.
Revenues
Oil and Gas Sales. During the second quarter, revenues from the sale of
crude oil and natural gas, net of realized losses from our hedging
instruments, increased 75% from $2,494,300 in 2004 to $4,367,800 in 2005.
Losses realized on our hedges during the 2005 quarter were $609,600 for oil
and $203,600 for gas, compared to $197,300 for oil and $129,100 for gas in
the 2004 quarter. The significant 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 the second quarter of 2005, our sales volumes were 47,771 barrels of
crude oil and 420,657 Mcf of natural gas, or 707,283 natural gas
equivalents (mcfe) compared to 41,613 barrels of crude oil and 230,247 Mcf
of natural gas, or 479,925 Mcfe in the second quarter of 2004. On a daily
basis we produced an average of 7,772 Mcfe in the second quarter of 2005
compared to a daily average of 5,274 Mcfe in the 2004 quarter. Higher
natural gas and crude oil sales volumes were a direct result of the
development program we began in late 2004, and expanded in 2005. The
development program included our drilling and completing 2 new gas wells in
east Texas in early 2005, the completion of workover and facility projects
at our Grand Lake and Lacassine fields in southwest Louisiana, and the
workover of gas wells in south Texas. These successful new oil and gas well
completions not only offset the loss of production from property sales in
2004, but also allowed us to achieve the 47% increase in production rate
from second quarter 2004 to second quarter 2005.
Oil and gas prices are reported net of the realized effect of our hedging
agreements. Prices realized were $37.26 per Bbl and $6.15 per Mcf in the
second quarter of 2005 compared to $30.41 per Bbl and $5.34 per Mcf in the
second quarter of 2004. Prices before the effects of the hedging agreements
were $50.02 per Bbl and $6.64 per Mcf in the second quarter of 2005
compared to $35.15 per Bbl and $5.90 per Mcf in the second quarter of 2004.
Operating Overhead and Other Income. Revenues from these activities
decreased from $40,900 in 2004 to $25,300 in 2005, due primarily to lower
overhead recoveries on company-operated properties.
Costs and Expenses
Lease Operating Expenses. Overall, lease operating expenses increased 6%
from $1,285,000 in 2004 to $1,365,000 in 2005. Considering the properties
sold in the third quarter of 2004, operating expenses increased 35% from
2004 to 2005. Approximately two-thirds of this increase was due to
increased production taxes, compression costs and salt water disposal costs
related to higher sales volumes. The remainder was due to higher vendor
prices.
16
On a per unit basis, expenses decreased from $2.68 per Mcfe in 2004, to
$1.93 per Mcfe in 2005. This decrease in lifting cost was due to the higher
sales volumes and the sale of the two higher lifting cost fields in the
third quarter of 2004.
Depreciation, Depletion and Amortization (DD&A). DD&A increased 91% from
$437,000 in 2004 to $835,200 in 2005 due to higher production volumes, and
from an increase in the DD&A rate per unit from $.91per Mcfe in 2004 to
$1.18 per Mcfe in 2005.
General and Administrative (G&A) Expenses. Our G&A expenses increased 98%
from $472,400 in 2004 to $934,900 in 2005 due to the recent additions to
our management team to carry out our growth plan. On a per unit basis,
expenses increased from $.98 per Mcfe in 2004 to $1.32 per Mcfe in 2005.
Interest Expense. Interest expense decreased 98% from $1,014,600 in 2004 to
$18,100 in 2005, primarily due to retirement of debt associated with our
February, 2005 recapitalization.
Six-Month Period Ended June 30, 2005 compared to Six- Month Period Ended
June 30, 2004.
Revenues
Oil and Gas Sales. During the six month period ended June 2005, revenues
from the sale of crude oil and natural gas, net of realized losses from our
hedging instruments, increased 60% from $4,995,000 in 2004 to $8,001,900 in
2005. Losses realized on our hedges during 2005 were $1,144,900 for oil and
$324,800 for gas, compared to $406,400 for oil and $296,200 for gas in the
2004. The significant increase in revenues was due to higher oil and gas
sales volumes and higher crude oil and natural gas prices, as further
described below.
For the period in 2005, our sales volumes were 92,479 barrels of crude oil
and 764,672 Mcf of natural gas, or 1,319,546 natural gas equivalents (mcfe)
compared to 86,797 barrels of crude oil and 484,003 Mcf of natural gas, or
1,004,785 Mcfe in the 2004 period. On a daily basis we produced an average
of 7,290 Mcfe in the six month period of 2005 compared to a daily average
of 5,551 Mcfe in the 2004 period. Higher natural gas and crude oil sales
volumes were a direct result of the development program we began in late
2004, and expanded in 2005. The development program included our drilling
and completing 2 new gas wells in east Texas in early 2005, the completion
of workover and facility projects at our Grand Lake and Lacassine fields in
southwest Louisiana, and the workover of gas wells in south Texas. These
successful new oil and gas well completions not only offset the loss of
production from property sales in 2004, but also allowed us to achieve the
31% increase in production rate from the period in 2004 to the period in
2005.
Oil and gas prices are reported net of the realized effect of our hedging
agreements. Prices realized were $36.57 per Bbl and $6.04 per Mcf for the
six month period of 2005 compared to $29.14 per Bbl and $5.09 per Mcf in
the 2004 period. Prices before the effects of the hedging agreements were
$48.95 per Bbl and $6.47 per Mcf for the six month period of 2005 compared
to $33.82 per Bbl and $5.71 per Mcf in the 2004 period.
Operating Overhead and Other Income. Revenues from these activities
decreased from $79,000 in 2004 to $55,000 in 2005, due primarily to lower
overhead recoveries on company-operated properties.
Costs and Expenses
Lease Operating Expenses. Overall, operating expenses increased 6% from
$2,599,300 in 2004 to $2,765,900 in 2005. Excluding property sales in the
third quarter 2004, operating expenses increased 30% from 2004 to 2005.
Approximately two-thirds of this increase was due to increased production
17
taxes, compression costs and salt water disposal costs related to higher
sales volumes. The remainder was due to higher vendor prices.
On a per unit basis, expenses decreased from $2.59 per Mcfe in 2004, to
$2.10 per Mcfe in 2005. This decrease in lifting cost was due to the higher
sales volumes and the sale of two higher lifting cost fields in third
quarter of 2004.
Depreciation, Depletion and Amortization (DD&A). DD&A increased 70% from
$876,200 in 2004 to $1,491,000 in 2005 due to higher production volumes,
and from an increase in the DD&A rate per unit from $.87 per Mcfe in 2004
to $1.13 per Mcfe in 2005.
General and Administrative (G&A) Expenses. Our G&A expenses increased 78%
from $873,600 in 2004 to $1,553,100 in 2005 due to the recent additions to
our management team to carry out our growth plan. On a per unit basis,
expenses increased from $.87 per Mcfe in 2004 to $1.18 per Mcfe in 2005.
Interest Expense. Interest expense decreased 37% from $1,934,800 in 2004 to
$1,216,600 in 2005, primarily due to retirement of debt associated with our
February, 2005 recapitalization.
Financial Condition and Capital Resources
-----------------------------------------
At June 30, 2005, our current liabilities exceeded our current assets by
$3,038,473, while at December 31, 2004 our current liabilities exceeded our
current assets by $35,034,675.The improvement was attributable to repayment
of debt with proceeds from the sale of the Series G Preferred Stock. For
the second quarter of 2005 we had a loss of $79,362 compared to a net
income of $9,323,281 for the same period in 2004. The net income generated
in 2004 was primarily attributed to $12.5 million in forgiveness of debt
income associated with our April, 2004 refinancing.
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 initial
borrowing base is set at $20 million and will be subject to semi-annual
redeterminations, with the first redetermination to be December 1, 2005.
The facility will be 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. On
August 15, 2005, the outstanding balance under our facility was $1.5
million. (See Note 5 "Financing Activity" in Notes to the Consolidated
Financial Statements on page 10.)
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
------- ----------------------------------------------------------
The following market rate disclosures should be read in conjunction with
the quantitative disclosures about market risk contained in our 2004 Annual
Report on Form 10-K, as well as with the consolidated financial statements
and notes thereto included in this quarterly report on Form 10-Q.
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 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
18
in interest rates and product prices. Accordingly, these hypothetical
changes may not be an indicator of probable future fluctuations.
Interest Rate Risk
At June 30, 2005, we had no variable rate debt.
Commodity Price Risk
We hedge a portion of price risk associated with our oil and natural gas
sales through contractual arrangements which are classified as derivative
instruments. As of June 30, 2005, these derivative instruments had an
estimated fair value liability of $2,900,233. A hypothetical change in oil
and gas prices could have an effect on oil and gas futures prices, which
are used to estimate the fair value of our derivative instruments. However,
it is not practicable to estimate the resultant change, if any, in the fair
value of our derivative instruments.
ITEM 4. CONTROLS AND PROCEDURES
------- -----------------------
As of June 30, 2005, our President, Chief Executive Officer and our Senior
Vice President, 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
Chief Executive Officer and the 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. There have been no
significant changes in our internal controls or in other factors that could
significantly affect internal controls subsequent to June 30, 2005.
19
PART II. OTHER INFORMATION
--------------------------
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
------- -----------------------------------------------------------
On April 1 and April 4, 2005, warrants issued to our former lenders in
connection with the completion of our April 2004 financing package,
exercisable for an aggregate of 2,035,621 shares of common stock at a price
of $0.01 per share, were exercised for an aggregate of 2,018,224 shares of
common stock by cashless exercise. Due to the nature of the transaction and
the relationship of the former lenders with us, we believe the exercises
were exempt under Section 4(2) of the Securities Act.
On April 22, 2005, two holders of the Series H Convertible Preferred Stock
elected to convert 1,250 shares into approximately 1.8 million shares of
common stock. Due to the nature of the transaction and the relationship of
such holders with us, we believe the conversions were exempt under Section
3(a)(9) or Section 4(2) of the Securities Act.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------- ---------------------------------------------------
The Company held its Annual Meeting of Shareholders on June 1, 2005 (the
"Annual Meeting"). The close of business on April 15, 2005 was fixed as the
record date for determining shareholders entitled to notice of, and to vote
at, the meeting or any adjournments or postponement thereof. On that date,
26,941,117 shares of our Class A Common Stock, par value $.001 per share
("Common Stock"), were outstanding and entitled to vote. Shares of our
Series G Convertible Preferred Stock, par value $.01 per share (the "Series
G "), and shares of our Series H Convertible Preferred Stock, par value
$.01 per share (the "Series H"), were entitled to vote on an as converted
basis with the Common Stock with respect to matters on which approval of
our shareholders was required. However, with respect to the election of
directors, holders of the Series G were entitled to elect a majority of our
directors, but not the remaining directors, which the holders of the Common
Stock and Series H were entitled to elect. Allan D. Keel, B. James Ford and
Skardon F. Baker were re-elected by the holders of the Series G and
continued their term of office after the meeting. On the record date,
81,000 shares of Series G, representing the voting power of 45,315,631
shares of Common Stock, and 6,500 shares of Series H, representing the
voting power of 9,285,716 shares of Common Stock, were outstanding. Each of
the following matters was approved by shareholders by the following votes:
Proposal 1 - To elect two directors to hold office until the next annual
meeting of shareholders and until their successors are duly elected and
qualified. Each of the two director nominees were elected by a plurality of
votes cast by holders of the Common Stock and Series H Preferred Stock
entitled to vote at the Annual Meeting.
For Withheld
--- --------
Lee B. Backsen 30,049,734 1,000
Lon McCain 30,049,734 1,000
20
Proposal 2 - To approve the merger of GulfWest Energy Inc. into a wholly
owned Delaware subsidiary, Crimson Exploration Inc., to effectuate the
change of our state of incorporation from Texas to Delaware and to increase
the number of authorized shares of common stock from 80 million to 200
million. Approval required the affirmative vote of (i) a majority of votes
entitled to be cast in respect of the shares of Common Stock, and Series G
and Series H (on an as converted basis) voting together as a single class
and (ii) a majority of each of the Common Stock, Series G and Series H,
each voting by itself separately as a class, with the Series G and Series H
voting preferred shares.
Collectively For Against Abstain Broker Non-Votes
------------ --- ------- ------- ----------------
Common Stock, 70,301,561 13,317 5,000 4,804,480
Series G and
Series H
Separately, as Class For Against Abstain Broker Non-Votes
-------------------- --- ------- ------- ----------------
Common Stock 16,035,984 13,317 5,000 4,804,480
Series G 80,400 0 0 N/A
Series H 6,500 0 0 N/A
Proposal 3 - To approve the 2004 Stock Option and Compensation Plan. The
affirmative vote of a majority of the votes cast on the matter by the
holders of the Common Stock, Series G and Series H at the Annual Meeting
was required for approval (although neither the Plan nor grants under the
Plan were contingent on shareholder approval).
Collectively For Against Abstain Broker Non-Votes
------------ --- ------- ------- ----------------
Common Stock, 69,872,069 455,909 10,700 4,815,680
Series G and
Series H
Proposal 4 - To approve the 2005 Stock Incentive Plan. The affirmative vote
of a majority of the votes cast on the matter by the holders of the Common
Stock, Series G and Series H at the Annual Meeting was required for
approval.
Collectively For Against Abstain Broker Non-Votes
------------ --- ------- ------- ----------------
Common Stock, 69,869,285 460,693 5,100 4,819,280
Series G and
Series H
21
ITEM 6. EXHIBITS.
------- ---------
Number Description
------ -----------
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.)
3.7 Agreement and Plan of Merger, dated June 28, 2005, between
GulfWest Energy Inc. and Crimson Exploration Inc. (Previously
filed on our current report on Form 8-K filed July 5, 2005.)
10.1 Form of Indemnification Agreement for directors and officers.
(Previously filed with our Form 8-K, Reg. No. 001-12108, filed
with the Commission on July 21, 2005.)
10.2 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.)
10.3 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.)
10.4 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.)
10.5 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.)
10.6 Summary terms of June 2005 Director Compensation Plan.
10.7 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.)
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10.8 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.)
10.9 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.)
22.1 Subsidiaries of the Registrant (included on page 7 of this
Quarterly Report).
31.1 Certification of Chief Executive Officer pursuant to Exchange
Rule 13a-14 (a) as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Exchange
Rule 13a-14 (a) as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32 Certification pursuant to 18 U.S.C. Section 1350 pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
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SIGNATURES
Pursuant to the requirements of 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.
(Registrant)
Date: August 15, 2005 By: /s/ Allan D. Keel
------------------------------------
Allan D. Keel
President and Chief Executive Officer
Date: August 15, 2005 By: /s/ E. Joseph Grady
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E. Joseph Grady
Senior Vice President and Chief Financial Officer
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