UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended: March 31, 2006
[ ] TRANSITION REPORT UNDER SECTION 13 OF 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
Commission file number 0-26321
GASCO ENERGY, INC.
(Exact name of registrant as specified in its charter)
Nevada 98-0204105
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
8 Inverness Drive East, Suite 100, Englewood, Colorado 80112
(Address of principal executive offices) (Zip Code)
(303) 483-0044
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year, if changed
since last report)
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
require 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 a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one):
Large accelerated filer __ Accelerated filer X Non-accelerated filer __
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes __ No X
Number of Common shares outstanding as of May 8, 2006: 85,776,830
ITEM I - FINANCIAL INFORMATION
PART 1 - FINANCIAL STATEMENTS
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2006 2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents $40,408,462 $62,661,368
Restricted investment 3,575,000 10,139,000
Short-term investments 30,000,000 15,000,000
Accounts receivable
Joint interest billings 3,065,919 1,792,038
Revenue 2,412,480 3,115,154
Inventory 4,572,897 1,182,982
Prepaid expenses 543,137 645,554
----------- -----------
Total 84,577,895 94,536,096
----------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests 95,796,379 83,972,300
Unproved mineral interests 13,892,137 13,323,712
Wells in progress 2,868,283 -
Gathering assets 6,243,162 4,831,050
Equipment 5,306,332 5,148,388
Furniture, fixtures and other 229,857 175,607
----------- -----------
Total 124,336,150 107,451,057
Less accumulated depreciation, depletion and amortization (9,805,274) (6,986,662)
----------- -----------
Total 114,530,876 100,464,395
------------ -----------
OTHER ASSETS
Restricted investment 3,602,243 3,565,020
Deferred financing costs 2,519,919 2,634,461
Debt issuance costs 208,051 -
----------- -----------
Total 6,330,213 6,199,481
----------- -----------
TOTAL ASSETS $ 205,438,984 $ 201,199,972
============= =============
The accompanying notes are an integral part of the
consolidated financial statements.
2
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
(Unaudited)
March 31, December 31,
2006 2005
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,167,045 $ 907,772
Revenue payable 1,326,593 1,658,141
Advances from joint interest owners 3,076,101 2,476,080
Accrued interest 1,737,849 844,098
Accrued expenses 3,843,141 2,571,047
----------- ---------
Total 11,150,729 8,457,138
----------- ---------
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes 65,000,000 65,000,000
Asset retirement obligation 243,669 223,947
Deferred rent expense 78,343 78,727
---------- ----------
Total 65,322,012 65,302,674
---------- ----------
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock - $.001 par value;
20,000 shares authorized; 763 shares issued and outstanding
with a liquidation preference of $335,720 in 2005 - 1
Common stock - $.0001 par value; 300,000,000 shares authorized;
85,675,256 shares issued and 85,601,556 outstanding in 2006
85,041,492 shares issued and 84,967,792 shares outstanding in 2005 8,572 8,504
Additional paid in capital 158,800,349 157,540,755
Deferred compensation - (443,579)
Accumulated deficit (29,712,383) (29,535,226)
Less cost of treasury stock of 73,700 common shares (130,295) (130,295)
------------ -----------
Total 128,966,243 127,440,160
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 205,438,984 $ 201,199,972
=============- =============
The accompanying notes are an integral part of the
consolidated financial statements.
3
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
March 31,
----------------------------------------
2006 2005
REVENUES
Gas $ 5,697,115 $ 714,732
Oil 232,562 76,795
Gathering 483,139 133,767
Interest income 846,706 360,053
--------- ---------
Total 7,259,522 1,285,347
--------- ---------
OPERATING EXPENSES
Lease operating 530,015 156,432
Gathering operations 387,793 224,747
Depletion, depreciation and amortization 2,826,542 372,236
General and administrative 2,684,036 1,223,798
Interest expense 1,008,293 1,008,262
--------- ---------
Total 7,436,679 2,985,475
--------- ---------
NET LOSS (177,157) (1,700,128)
Preferred stock dividends (1,393) (7,162)
---------- -----------
NET LOSS ATTRIBUTABLE TO COMMON
STOCKHOLDERS $ (178,550) $ (1,707,290)
=========== =============
NET LOSS PER COMMON SHARE - BASIC AND DILUTED $ (0.00) $ (0.02)
========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED 84,643,556 70,042,691
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
4
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
----------------------------------
2006 2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $(177,157) $ (1,700,128)
Adjustment to reconcile net loss to net cash used in operating activities
Depreciation, depletion and impairment expense 2,821,205 369,596
Accretion of asset retirement obligation 5,338 2,640
Stock compensation 989,417 125,400
Amortization of deferred rent (384) 13,735
Amortization of deferred financing costs 114,542 114,542
Changes in operating assets and liabilities:
Accounts receivable (571,207) (534,959)
Inventory (3,389,915) (498,282)
Prepaid expenses 102,417 126,403
Accounts payable 259,273 (1,136,233)
Revenue payable (331,548) 75,213
Advances from joint interest owners 600,021 333,535
Accrued interest 893,751 893,750
Accrued expenses (211,664) 1,294,736
--------- ----------
Net cash provided by (used in) operating activities 1,104,089 (520,052)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (56,843) (44,522)
Cash paid for acquisitions, development and exploration (15,174,942) (6,639,094)
Proceeds from property sales - 828,102
Increase in short-term investments (15,000,000) -
Proceeds from sale of short-term investments - 5,000,000
Cash designated as restricted (37,223) (105,617)
Cash undesignated as restricted 6,564,000 -
----------- ---------
Net cash used in investing activities (23,705,008) (961,131)
------------ ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (1,393) (6,809)
Exercise of options to purchase common stock 557,457 -
Cash paid for debt issuance costs (208,051) -
--------- -------
Net cash provided by (used in) financing activities 348,013 (6,809)
--------- -------
NET DECREASE IN CASH AND CASH EQUIVALENTS (22,252,906) (1,487,992)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 62,661,368 25,717,081
---------- ----------
END OF PERIOD $ 40,408,462 $ 24,229,089
============ ============
The accompanying notes are an integral part of the
consolidated financial statements.
5
6
GASCO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE MONTHS ENDED March 31, 2006 AND 2005
NOTE 1 - ORGANIZATION
Gasco Energy, Inc. ("Gasco" or the "Company") is an independent energy company
engaged in the exploration, development, acquisition and production of crude oil
and natural gas reserves in the western United States. "Our", "we", and "us" as
used herein also refer to Gasco Energy, Inc.
The unaudited financial statements included herein were prepared from the
records of the Company in accordance with generally accepted accounting
principles in the United States applicable to interim financial statements and
reflect all adjustments which are, in the opinion of management, necessary to
provide a fair statement of the results of operations and financial position for
the interim periods. Such financial statements conform to the presentation
reflected in the Company's Form 10-K filed with the Securities and Exchange
Commission for the year ended December 31, 2005. The current interim period
reported herein should be read in conjunction with the Company's Form 10-K for
the year ended December 31, 2005.
The results of operations for the three months ended March 31, 2006 are not
necessarily indicative of the results that may be expected for the year ending
December 31, 2006. All significant intercompany transactions have been
eliminated.
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements include Gasco and its wholly
owned subsidiaries.
Restricted Investment
The restricted investment balance as of March 31, 2006 represents $7,177,243
invested in U.S. government securities in an amount sufficient to provide for
the payment of three semi-annual scheduled interest payments on the Company's
outstanding 5.5% Convertible Notes ("Notes"). The current portion of restricted
investment represents the interest payments that are due within one year. The
non-current portion represents the interest payments that are due after one
year. This investment will be held until maturity and the cost of the investment
approximates its market value. The restricted cash balance at December 31, 2005
is comprised of $7,140,020 invested in U.S. government securities in an amount
sufficient to provide for the payment of four semi-annual scheduled interest
payments on the Company's outstanding Notes, and $6,564,000 of cash invested in
cash equivalents as collateral for a one year letter of credit. The letter of
credit was obtained in connection with one of the Company's long-term rig
contracts. The collateral for this letter of credit was released during the
first quarter of 2006 in connection with the Company's credit facility further
described in Note 5.
6
Short-term Investments
The Company's short-term investments consist primarily of preferred auction rate
securities, which are classified as available-for-sale. Preferred auction rate
securities represent preferred shares issued by closed end funds and are
typically traded at auctions that are held periodically where the dividend rate
for the next period is set. The Company invests in AAA/Aaa rated preferred
auctions that have a dividend rate period of 28 days or less. These securities
are stated at fair value based on quoted market prices. The income earned on
these investments is included in interest income in the accompanying financial
statements.
Property, Plant and Equipment
The Company follows the full cost method of accounting whereby all costs related
to the acquisition and development of oil and gas properties are capitalized
into a single cost center ("full cost pool"). Such costs include lease
acquisition costs, geological and geophysical expenses, overhead directly
related to exploration and development activities and costs of drilling both
productive and non-productive wells. Proceeds from property sales are generally
credited to the full cost pool without gain or loss recognition unless such a
sale would significantly alter the relationship between capitalized costs and
the proved reserves attributable to these costs. A significant alteration would
typically involve a sale of 25% or more of the proved reserves related to a
single full cost pool.
Depletion of exploration and development costs and depreciation of production
equipment is computed using the units of production method based upon estimated
proved oil and gas reserves. The costs of unproved properties are withheld from
the depletion base until it is determined whether or not proved reserves can be
assigned to the properties. The properties are reviewed quarterly for
impairment.
Total well costs are transferred to the depletable pool even when multiple
targeted zones have not been fully evaluated. For depletion and depreciation
purposes, relative volumes of oil and gas production and reserves are converted
at the energy equivalent rate of six thousand cubic feet of natural gas to one
barrel of crude oil.
Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes may not exceed an
amount equal to the present value, discounted at 10%, of estimated future net
revenues from proved oil and gas reserves plus the cost, or estimated fair
value, if lower of unproved properties. Should capitalized costs exceed this
ceiling, an impairment is recognized. The present value of estimated future net
revenues is computed by applying current prices of oil and gas to estimated
future production of proved oil and gas reserves as of period-end, less
estimated future expenditures to be incurred in developing and producing the
proved reserves assuming the continuation of existing economic conditions.
7
Wells in Progress
Wells in progress at March 31, 2006 represent the costs associated with the
drilling of two wells in the Riverbend area of Utah. Since the wells had not
reached total depth as of March 31, 2006, they were classified as wells in
progress and were withheld from the depletion calculation and the ceiling test
until the second quarter of 2006 when the wells reached total depth and were
cased.
Debt Issuance Costs
Debt issuance costs as of March 31, 2006 represent the costs incurred in
connection with the Company's credit facility, further described in Note 5.
These costs will be amortized on the straight -line method over five years.
Asset Retirement Obligation
The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations,
" which requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it was incurred if a reasonable
estimate of fair value could be made. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. The increase
in carrying value of a property associated with the capitalization of an asset
retirement cost is included in proved oil and gas properties in the consolidated
balance sheets. The Company depletes the amount added to proved oil and gas
property costs. The future cash outflows associated with settling the asset
retirement obligations that have been accrued in the accompanying balance sheets
are excluded from the ceiling test calculations. The Company also depletes the
estimated dismantlement and abandonment costs, net of salvage values, associated
with future development activities that have not yet been capitalized as asset
retirement obligations. These costs are also included in the ceiling test
calculation. The asset retirement liability will be allocated to operating
expense by using a systematic and rational method. The information below
reconciles the value of the asset retirement obligation for the periods
presented.
Three Months Ended March 31,
2006 2005
Balance beginning of period $223,947 $108,566
Liabilities incurred 14,384 10,156
Liabilities settled - -
Revisions in estimated cash flows - -
Accretion expense 5,338 2,640
-------- ---------
Balance end of period $ 243,669 $ 121,362
========== =========
Computation of Net Income (Loss) Per Share
Basic net income (loss) per share is computed by dividing net income (loss)
attributable to the common stockholders by the weighted average number of common
8
shares outstanding during the reporting period. The shares of restricted common
stock granted to certain officers, directors and employees of the Company are
included in the computation only after the shares become fully vested. Diluted
net income per common share includes the potential dilution that could occur
upon exercise of the options to acquire common stock computed using the treasury
stock method which assumes that the increase in the number of shares is reduced
by the number of shares which could have been repurchased by the Company with
the proceeds from the exercise of the options (which were assumed to have been
made at the average market price of the common shares during the reporting
period). The 5.50% Convertible Senior Notes due 2011 (the "Notes") and the
outstanding common stock options have been excluded from the computation of
diluted net income (loss) per share for all periods presented because their
inclusion would have been anti-dilutive.
Use of Estimates
The preparation of the financial statements for the Company in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
Off Balance Sheet Arrangements
The Company has no off balance sheet arrangements.
NOTE 3 - STOCK BASED COMPENSATION
Gasco has followed Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees", and related interpretations, through
December 31, 2005 which resulted in the accounting for grants of awards to
employees at their intrinsic value in the consolidated financial statements.
Accordingly, Gasco has recognized compensation expense in the financial
statement for awards granted to consultants which must be re-measured each
period under the mark-to-market. Gasco had previously adopted the provisions of
FAS No. 123, "Accounting for Stock-Based Compensation", as amended by FAS No.
148, "Accounting for Stock-Based Compensation --Transition and Disclosure",
through disclosure only.
On January 1, 2006, Gasco adopted FAS No. 123(R), "Accounting for Stock-Based
Compensation," using the modified prospective method, which results in the
provisions of FAS 123(R) being applied to the consolidated financial statements
on a going-forward basis. Prior periods have not been restated. FAS 123(R)
requires companies to recognize share-based payments to employees as
compensation expense on a fair value method. Under the fair value recognition
provisions of FAS 123(R), stock-based compensation cost is measured at the grant
date based on the fair value of the award and is recognized as expense over the
service period, which generally represents the vesting period. The expense
recognized over the service period is required to include an estimate of the
awards that will be forfeited. Previously, Gasco recorded the impact of
forfeitures as they occurred. Gasco is assuming no forfeitures going forward
9
based on the Company's historical forfeiture experience. The fair value of stock
options is calculated using the Black-Scholes option-pricing model and the fair
value of restricted stock is based on the fair market value of the stock on the
date of grant. In addition, the previously recognized unearned compensation
balance of $443,579, as of the date of adoption, which was included as a
component of stockholders' equity, was reclassified to additional paid-in
capital.
As of March 31, 2006, options to purchase an aggregate of 8,599,334 shares of
the Company's common stock and 796,069 shares of restricted stock were
outstanding. These options were granted during 2005, 2004, 2003, 2002 and 2001
to the Company's employees, directors and consultants at exercise prices ranging
from $1.00 to $7.39 per share. The options vest at varying schedules within two
years of their grant date and typically expire within ten years from the grant
date. Stock-based employee compensation expense was $981,816 and stock-based
non-employee compensation costs were $165,360 before tax for the three months
ending March 31, 2006. Of this amount, $7,601 was expensed and $157,759 was
capitalized. Stock-based employee compensation expense granted to employees of
the Company of $106,713 and $27,656 was charged to operations during the three
months ending March 31, 2005 and March 31, 2004, respectively. Stock-based
non-employee compensation expense granted to consultants of the Company of
$18,687 was charged to operations during the three months ending March 31, 2005.
For the three months ended March 31, 2006 under FAS 123(R), the Company
capitalized $157,759 of non-employee compensation expense as proved property
costs related to our drilling projects in the consolidated balance sheets. The
following table presents share-based compensation expenses included in the
Company's consolidated statement of operations:
Share-based compensation expense before tax $989,417
Income tax benefit (195,446)
Net stock-based compensation expense 793,971
Gasco had previously adopted the provisions of FAS No. 123, "Accounting for
Stock-Based Compensation", as amended by FAS No. 148, "Accounting for
Stock-Based Compensation --Transition and Disclosure", through disclosure only.
The following table illustrates the effect on net income and earnings per share
for the three months ended March 31, 2005 as if the Company had applied the fair
value recognition provisions of FAS No. 123(R) to stock based employee awards.
For the Three Months Ended March 31,
- ----------------------------------------------------- --------------------- ------------------
2005 2004
- ----------------------------------------------------- --------------------- ------------------
Net loss attributable to common shareholders:
As reported $(1,707,290) $(578,079)
Add: Stock-based employee compensation included in
net loss (a) 106,713 27,656
Less: Stock based employee compensation determined
under the fair value based method (376,872) (145,193)
Pro forma $(1,977,449) $(695,616)
Net loss per common share:
As reported $(0.02) $(0.01)
Pro forma (0.03) (0.01)
10
(a) Represents the compensation expense associated with the Company's restricted
stock awards.
The Company uses the Black-Scholes option-pricing model to estimate the fair
value of the options at the grant date. There were no option grants during the
three months ended March 31, 2006. The fair values of options granted during
2005 and 2004 were calculated using the following weighted-average assumptions:
2005 2004
Expected dividend yield -- --
Expected price volatility 75%-79% 79%-87%
Risk-free interest rate 3.7%-3.9% 3.2%-3.7%
Expected life of options 5 years 5 years
The weighted average grant-date fair value of options granted to employees
during 2005 and 2004 was $2.25 and $1.28, respectively.
The expected stock price volatility assumption was determined using the
historical volatility of the Company's common stock over the expected life of
the option.
Stock Options
The following table summarizes the stock option activity in the equity incentive
plans from January 1, 2006 through March 31, 2006:
Weighted-Average
Stock Options Exercise Price
---------------------------------- -------------------- ------------------
Outstanding at January 1, 2006 8,812,667 $2.29
---------------------------------- -------------------- ------------------
Granted - -
---------------------------------- -------------------- ------------------
Exercised 196,665 $2.83
---------------------------------- -------------------- ------------------
Forfeited 16,668 $3.39
---------------------------------- -------------------- ------------------
Cancelled - -
---------------------------------- -------------------- ------------------
Outstanding at March 31, 2006 8,599,334 $2.28
---------------------------------- -------------------- ------------------
Exercisable at March 31, 2006 6,974,685 $2.03
---------------------------------- -------------------- ------------------
11
The following table summarizes information related to the outstanding and vested
options as of March 31, 2006:
Outstanding Options Vested options
- -------------------------------- ----------------------- --------------------
Number of shares 8,599,334 6,974,685
- -------------------------------- ----------------------- --------------------
Weighted Average Remaining
Contractual Life 6.71 6.16
- -------------------------------- ----------------------- --------------------
Weighted Average Exercise Price $2.28 $2.03
- -------------------------------- ----------------------- --------------------
Aggregate intrinsic value $28,588,511 $24,900,523
- -------------------------------- ----------------------- --------------------
The aggregate intrinsic value in the table above represents the total pretax
intrinsic value, based on the Company's closing common stock price of $5.60 as
of March 31, 2006, which would have been received by the option holders had all
option holders exercised their options as of that date.
The following table summarizes the non-vested stock option activity in the
equity incentive plans from January 1, 2006 through March 31, 2006:
Weighted-Average
Stock Options Exercise Price
- -------------------------------------------- ------------------- ---------------
- -------------------------------------------- ------------------- ---------------
Nonvested stock options at January 1, 2006 2,238,386 $2.42
- -------------------------------------------- ------------------- ---------------
- -------------------------------------------- ------------------- ---------------
Granted - -
- -------------------------------------------- ------------------- ---------------
- -------------------------------------------- ------------------- ---------------
Forfeited 16,668 $3.39
- -------------------------------------------- ------------------- ---------------
- -------------------------------------------- ------------------- ---------------
Vested 597,069 $3.00
- -------------------------------------------- ------------------- ---------------
- -------------------------------------------- ------------------- ---------------
Nonvested stock options at March 31, 2006 1,624,649 $3.33
- -------------------------------------------------------------- -----------------
The total intrinsic value of options exercised during the three months ended
March 31, 2006, 2005, and 2004 was $593,783, $1,959,886, and $26,335,
respectively. The total cash received from employees as a result of stock option
exercises during the three months ended March 31, 2006, 2005 and 2004 was
approximately $557,457, $1,388,910 and $33,336, respectively. In connection with
these exercises, the tax benefits potentially realizable by the Company for the
three months ended March 31, 2006, 2005, and 2004 was $207,824, $685,960, and
$9,217, respectively. The Company is currently in an NOL position; therefore,
the tax benefit associated with the exercise of these options has not been
realized.
The total fair value of the shares vested during the three months ended March
31, 2006, 2005, and 2004 was $1,319,350, $253,338, and $65,232, respectively.
The Company settles employee stock option exercises with newly issued common
shares.
As of March 31, 2006, there was $3,834,828 of total unrecognized compensation
cost related to non-vested options granted under the Company's equity incentive
plans. That cost is expected to be recognized over a weighted-average period of
0.57 years.
12
Restricted Stock
The following table summarizes the restricted stock activity from January 1,
2006 through March 31, 2006:
Weighted-Average Fair
Restricted Stock Value
- ----------------------------------- ---------------------- --------------------
Outstanding at January 1, 2006 796,569 $1.40
- ----------------------------------- ---------------------- --------------------
Granted - -
- ----------------------------------- ---------------------- --------------------
Vested - -
- ----------------------------------- ---------------------- --------------------
Forfeited 500 $7.29
- ----------------------------------- ---------------------- --------------------
Outstanding at March 31, 2006 796,069 $1.40
- -------------------------------------------------------------------------------
As of March 31, 2006, there was $331,139 of total unrecognized compensation cost
related to non-vested restricted stock granted under the Company's stock plans.
That cost is expected to be recognized over a weighted-average period of 1.78
years.
NOTE 4 - STOCK TRANSACTIONS
During January 2006, certain holders of the Company's Series B Convertible
Preferred Stock ("Preferred Stock") converted the remaining 763 shares of
Preferred Stock outstanding into 479,599 shares of common stock.
During the first three months of 2006 the Company issued 196,665 shares of
common stock in connection with the exercise of options to purchase shares of
common stock at strike prices ranging from $1.61 per common share to $3.39 per
common share for total proceeds of $557,457.
NOTE 5 - CREDIT FACILITY
On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered
into a $250 million Credit Agreement (the "Credit Agreement") with JPMorgan
Chase Bank, N.A., as Administrative Agent and the other lenders named therein.
Borrowings made under the Credit Agreement are guaranteed by our subsidiaries
and secured by a pledge of the capital stock of our subsidiaries and mortgages
on substantially all of our oil & gas properties. We did not borrow any funds
under the Credit Agreement at the time of its execution.
The initial aggregate commitment of the lenders under the Credit Agreement is
$250,000,000, subject to a borrowing base which has initially been set at
$17,000,000. The Credit Agreement also provides for a $10,000,000 sublimit for
letters of credit which we may use for general corporate purposes. As of March
31, 2006 there were no loans outstanding, however, a $6,564,000 letter of credit
is considered usage for purposes of calculating availability and commitment
fees. Our aggregate borrowings and outstanding letters of credit under the
Credit Agreement may not at any time exceed the borrowing base. Interest on
borrowings is payable monthly and principal is due at maturity on March 29,
2010.
13
Interest on borrowings under the Credit Agreement accrues at variable interest
rates at either, at our election, a Eurodollar rate or an alternate base rate.
The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies
from 1.25% (for periods in which we have utilized less than 50% of the borrowing
base) to 2.00% (for periods in which we have utilized greater than 90% of the
borrowing base). The alternate base rate is calculated as (1) the greater of (a)
the Prime Rate or (b) the Federal Funds Effective Rate plus 1/2%, plus (2) an
applicable margin that varies from 0% (for periods in which we have utilized
less than 50% of the borrowing base) to 0.75% (for periods in which we have
utilized greater than 90% of the borrowing base). We elect the basis of the
interest rate at the time of each borrowing. In addition, we are obligated to
pay a commitment fee under the Credit Agreement quarterly in arrears based on a
percentage multiplied by the daily amount that the aggregate commitments exceed
borrowings under the agreement. The commitment fee percentage varies from 0.30%
to 0.50% based on the percentage of the borrowing base utilized.
The Credit Agreement requires us to comply with financial covenants that require
us to maintain (1) a Current Ratio (defined as current assets plus unused
availability under the Credit Facility divided by current liabilities excluding
the current portion of the Credit Facility), determined at the end of each
quarter, of not be less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX
(as such terms are defined in the Credit Agreement) for the most recent quarter
multiplied by four to be greater than 3.5:1 for each fiscal quarter. In
addition, the Credit Agreement contains covenants that restrict our ability to
incur other indebtedness, create liens or sell our assets, pay dividends on our
common stock and make certain investments.
The Company incurred $208,051 in debt issuance costs associated with this
facility. These costs have been recorded as an asset in the accompanying
financial statements and will be amortized using the straight-line method over
five years. The credit facility is available to provide funds for the
exploration, development and/or acquisition of oil and gas properties, to
refinance existing indebtedness and for working capital and other general
corporate purposes. The Credit Agreement provides for semi-annual evaluation of
the borrowing base, which will be determined as a percentage of the discounted
present value of the Company's oil and natural gas reserves.
NOTE 6 - UNPROVED OIL AND GAS PROPERTIES
The following table sets forth a summary of oil and gas property costs not being
depleted as of December 31, 2005, by the year in which such costs were incurred,
and related transfers to proved property and sales.
Balance Costs Incurred During Years Ended December 31,
-------------------------------------------------------------------
12/31/05 2005 2004 2003 Prior
-------- ---- ---- ---- -----
Acquisition costs $18,804,067 $ 283,114 $5,400,264 $284,653 $12,836,036
Exploration costs 2,874,090 791,914 219,936 667,850 1,194,390
Transfer of costs to proved (7,526,343) (5,372,544) (382,909) (1,725,000) (45,890)
Sales (828,102) (828,102) - - -
------------ ------------ ---------- ------------ -----------
Total $ 13,323,712 $ (5,125,618) $ 5,237,291 $ (772,497) $13,984,536
============ ============= =========== =========== ===========
14
The Company's drilling activities are located primarily in the Riverbend Area of
Utah, and the Company plans to drill approximately 32 gross (15 net) wells in
this area during 2006. The Company also plans to drill up to three wells in
Wyoming during 2006 and continues to consider several additional options for its
Wyoming acreage such as the farm-out of some of its acreage and other similar
type arrangements. The Company entered into a farm-out agreement under which an
unrelated entity has committed to drill one well on its acreage in California.
Under this agreement, Gasco will contribute the acreage and the unrelated entity
will pay the drilling and completion costs. Gasco will retain a 25% interest if
the well is successful.
NOTE 7 - STATEMENT OF CASH FLOWS
During the three months ended March 31, 2006, the Company's non-cash investing
and financing activities consisted of the following transactions:
- Recognition of an asset retirement obligation for the plugging and
abandonment costs related to the Company's oil and gas properties
valued at $14,384.
- Stock based compensation of $157,759 capitalized as proved property.
- Additions to oil and gas properties included in accrued expenses of
$1,483,758.
- Conversion of 763 shares of Preferred Stock into 479,599 shares of
common stock.
- Write-off of fully depreciated furniture and fixtures of $2,592.
During the three months ended March 31, 2005, the Company's non-cash investing
and financing activities consisted of the following transactions:
- Recognition of an asset retirement obligation for the plugging and
abandonment costs related to the Company's oil and gas properties
valued at $10,156.
- Conversion of 1,312 shares of Preferred Stock into 824,685 shares of
common stock.
There was no cash paid for interest or income taxes during the three months
ended March 31, 2006 and 2005.
NOTE 8 - CONSOLIDATING FINANCIAL STATEMENTS
On September 23, 2005, Gasco filed a Form S-3 shelf registration statement with
the Securities Exchange Commission which was subsequently amended in a Form
S-3/A that was filed on October 27, 2005. Under this registration statement,
which was declared effective on November 1, 2005, we may from time to time offer
and sell common stock, preferred stock, depositary shares and debt securities
that may be fully, irrevocably and unconditionally guaranteed by all of our
subsidiaries: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend
Gas Gathering, LLC and Myton Oilfield Rentals, LLC ("Guarantor Subsidiaries").
Set forth below are the condensed consolidating financial statements of Gasco,
the parent, and the Guarantor Subidiaries.
15
Condensed Consolidating Balance Sheet
As of March 31, 2006
(Unaudited)
Guarantor
Parent Subsidiaries Eliminations Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 38,962,560 $1,445,902 $ - $ 40,408,462
Restricted investment 3,575,000 - - 3,575,000
Short-term investments 30,000,000 - - 30,000,000
Accounts receivable - 5,478,399 - 5,478,399
Inventory - 4,572,897 - 4,572,897
Prepaid expenses 543,137 - 543,137
---------- ---------- --------- ----------
Total 73,080,697 11,497,198 - 84,577,895
---------- ---------- --------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests - 95,796,379 - 95,796,379
Unproved mineral interests 274,540 13,617,597 - 13,892,137
Wells in progress - 2,868,283 - 2,868,283
Gathering assets - 6,243,162 - 6,243,162
Equipment - 5,306,332 - 5,306,332
Furniture, fixtures and other 229,857 229,857
--------- ----------- -------- -----------
Total 504,397 123,831,753 - 124,336,150
Less accumulated depreciation, depletion and
amortization (57,213) (9,748,061) - (9,805,274)
--------- ----------- -------- -----------
Total 447,184 114,083,692 - 114,530,876
--------- ----------- -------- -----------
OTHER ASSETS
Restricted investment 3,602,243 - - 3,602,243
Deferred financing costs 2,519,919 - - 2,519,919
Debt issuance costs 208,051 - - 208,051
--------- ------------ -------- ---------
Total 6,330,213 - - 6,330,213
--------- ------------ -------- ---------
TOTAL ASSETS $ 79,858,094 $ 125,580,890 $205,438,984
============ ============= ======== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 152,223 $1,014,822 $ - $ 1,167,045
Revenue payable - 1,326,593 - 1,326,593
Advances from joint interest owners - 3,076,101 - 3,076,101
Accrued interest 1,737,849 - - 1,737,849
Accrued expenses 229,000 3,614,141 - 3,843,141
--------- --------- ------- ----------
Total 2,119,072 9,031,657 - 11,150,729
--------- --------- ------- ----------
NONCURRENT LIABILITES
5.5% Convertible Senior Notes 65,000,000 - - 65,000,000
Asset retirement obligation - 243,669 - 243,669
Deferred rent expense 78,343 - - 78,343
---------- ------- -------- ----------
Total 65,078,343 243,669 - 65,322,012
---------- ------- -------- ----------
STOCKHOLDERS' EQUITY
Common stock 8,572 - - 8,572
Other 12,652,107 116,305,564 - 128,957,671
---------- ----------- -------- -----------
Total 12,660,679 116,305,564 - 128,966,243
---------- ----------- -------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $79,858,094 $125,580,890 $ - $ 205,438,984
=========== ============ ======== =============
16
Condensed Consolidating Balance Sheet
As of December 31, 2005
(Unaudited)
Guarantor
Parent Subsidiaries Eliminations Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 59,314,343 $3,347,025 $ - $ 62,661,368
Restricted investment 10,139,000 - - 10,139,000
Short-term investments 15,000,000 - - 15,000,000
Accounts receivable - 4,907,192 - 4,907,192
Inventory - 1,182,982 - 1,182,982
Prepaid expenses 645,229 325 645,554
---------- --------- -------- ----------
Total 85,098,572 9,437,524 - 94,536,096
---------- --------- -------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests - 83,972,300 - 83,972,300
Unproved mineral interests 274,540 13,049,172 - 13,323,712
Gathering assets - 4,831,050 - 4,831,050
Equipment - 5,148,388 - 5,148,388
Furniture, fixtures and other 175,607 - - 175,607
------- ----------- ------- -----------
Total 450,147 107,000,910 - 107,451,057
Less accumulated depreciation, depletion and
amortization (46,064) (6,940,598) - (6,986,662)
-------- ----------- --------- -----------
Total 404,083 100,060,312 - 100,464,395
-------- ----------- -------- -----------
OTHER ASSETS
Restricted investment 3,565,020 - - 3,565,020
Deferred financing costs 2,634,461 2,634,461
Intercompany 103,081,444 (103,081,444) - -
----------- ------------- -------- ---------
Total 109,280,925 (103,081,444) - 6,199,481
----------- ------------- -------- ---------
TOTAL ASSETS $ 194,783,580 $ 6,416,392 $ $201,199,972
============= ============ ======= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 661,307 $ 246,465 $ - $ 907,772
Revenue payable - 1,658,141 - 1,658,141
Advances from joint interest owners - 2,476,080 - 2,476,080
Accrued interest 844,098 - - 844,098
Accrued expenses 507,066 2,063,981 - 2,571,047
--------- --------- ------ ---------
Total 2,012,471 6,444,667 - 8,457,138
--------- ---------- ------ ---------
NONCURRENT LIABILITES
5.5% Convertible Senior Notes 65,000,000 - - 65,000,000
Asset retirement obligation - 223,947 - 223,947
Deferred rent expense 78,727 - - 78,727
---------- --------- ------- ----------
Total 65,078,727 223,947 - 65,302,674
---------- --------- ------- ----------
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock 1 - - 1
Common stock 8,504 - - 8,504
Other 127,683,877 (252,222) - 127,431,655
----------- --------- ------- -----------
Total 127,692,382 (252,222) - 127,440,160
----------- ---------- ------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $194,783,580 $ 6,416,392 $ - $ 201,199,972
============ =========== ======= =============
17
Consolidating Statements of Operations
(Unaudited)
For the Three Months Ended March 31, 2006 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 5,929,677 $ - $ 5,929,677
Gathering - 1,027,339 (544,200) 483,139
Interest income 846,679 27 - 846,706
------- --------- ---------- ---------
Total 846,679 6,957,043 (544,200) 7,259,522
------- --------- ---------- ---------
OPERATING EXPENSES
Lease operating - 1,074,215 (544,200) 530,015
Gathering operations - 387,793 - 387,793
Depletion, depreciation and amortization 13,741 2,812,801 - 2,826,542
General and administrative 2,684,036 - - 2,684,036
Interest expense 1,008,293 - 1,008,293
--------- --------- ----------- ---------
Total 3,706,070 4,274,809 (544,200) 7,436,679
--------- --------- --------- ---------
NET INCOME (LOSS) (2,859,391) 2,682,234 - (177,157)
Preferred stock dividends (1,393) - - (1,393)
---------- ---------- -------- ----------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (2,860,784) $2,682,234 $ - $ (178,550)
============= ========== ====== ===========
For the Three Months Ended March 31, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 791,527 $ - $ 791,527
Gathering - 133,767 - 133,767
Interest income 360,053 - 360,053
------- ------- --------- ---------
Total 360,053 925,294 - 1,285,347
------- ------- --------- ---------
OPERATING EXPENSES
Lease operating - 156,432 - 156,432
Gathering operations - 224,747 - 224,747
Depletion, depreciation and amortization 11,401 360,835 - 372,236
General and administrative 1,223,798 - - 1,223,798
Interest expense 1,008,262 - - 1,008,262
--------- ------- --------- ---------
Total 2,243,461 742,014 - 2,985,475
--------- ------- --------- ---------
NET INCOME (LOSS) (1,883,408) 183,280 -
(1,700,128)
Preferred stock dividends (7,162) - - (7,162)
---------- ------- --------- ----------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (1,890,570) $ 183,280 $ - $(1,707,290)
============= ============= ========== ============
18
Consolidating Statements of Cash Flows
(Unaudited)
For the Three Months Ended March 31, 2006 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES $ (882,103) $1,986,192 $ - $1,104,089
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (56,843) - - (56,843)
Cash paid for acquisitions, development and exploration - (15,174,942) - (15,174,942)
Investment in sale of short-term investments (15,000,000) - - (15,000,000)
Cash designated as restricted (37,223) - - (37,223)
Cash undesignated as restricted 6,564,000 6,564,000
----------- ------------- ---------- ------------
Net cash used in investing activities (8,530,066) (15,174,942) - (23,705,008)
----------- ------------ ---------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (1,393) - - (1,393)
Exercise of options to purchase common stock 557,457 - - 557,457
Cash paid for debt issuance costs (208,051) (208,051)
Intercompany (11,287,627) 11,287,627 - -
------------ ---------- ------- --------
Net cash provided by (used in) financing activities (10,939,614) 11,287,627 - 348,013
------------ ---------- -------- --------
NET DECREASE IN CASH AND CASH
EQUIVALENTS (20,351,783) (1,901,123) - (22,252,906)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 59,314,343 3,347,025 62,661,368
---------- --------- --------- ----------
END OF PERIOD $ 38,962,560 $1,445,902 $ - $40,408,462
============ ========== ========= ===========
For the Nine Months Ended March 31, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS USED IN OPERATING ACTIVITIES
$(1,255,382) $ 735,330 $ - $ (520,052)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (44,522) - - (44,522)
Cash paid for acquisitions, development and exploration - (6,639,094) - (6,639,094)
Proceeds from property sales - 828,102 - 828,102
Proceeds from sale of short-term investments 5,000,000 - - 5,000,000
Cash designated as restricted (105,617) - - (105,617)
--------- ---------- ----------- ---------
Net cash provided by (used in) investing
activities 4,849,861 (5,810,992) - (961,131)
--------- ----------- ----------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (6,809) - - (6,809)
Intercompany (2,715,654) 2,715,654 - -
----------- ---------- ---------- ---------
Net cash provided by financing activities (2,722,463) 2,715,654 - (6,809)
----------- ---------- ---------- -------
NET DECREASE IN CASH AND CASH
EQUIVALENTS 872,016 (2,360,008) - (1,487,992)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 23,357,073 2,360,008 - 25,717,081
---------- ---------- --------- ----------
END OF PERIOD $24,229,089 $ - $ - $ 24,229,089
=========== ========== ======= ============
19
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward Looking Statements
Please refer to the section entitled "Cautionary Statement Regarding Forward
Looking Statements" at the end of this section for a discussion of factors which
could affect the outcome of forward looking statements used by the Company.
Overview
Gasco Energy, Inc. ("Gasco" or "the Company") is a natural gas and petroleum
exploitation, development and production company engaged in locating and
developing hydrocarbon resources, primarily in the Rocky Mountain region. Our
principal business strategy is to enhance stockholder value by using
technologies new to a specific area to generate and develop high-potential
exploitation resources in this area. Our principal business is the acquisition
of leasehold interests in petroleum and natural gas rights, either directly or
indirectly, and the exploitation and development of properties subject to these
leases. We are currently focusing our drilling efforts in the Riverbend Project
located in the Uinta Basin of northeastern Utah, targeting the Wasatch,
Mesaverde and Blackhawk formations.
The Company's corporate strategy is to grow through drilling projects. The
Company has been focusing its drilling efforts in the Riverbend Project located
in the Uinta Basin of northeastern Utah. The higher realized oil and gas prices
during 2005 and through the first quarter of 2006 due to factors such as
inventory levels of gas storage, different temperatures in parts of the country
and changing demand in the United States, combined with the continued
instability in the Middle East have increased the profitability of the Company's
drilling projects in this area. The increased drilling activity resulting from
the higher oil and gas prices has decreased the availability of drilling rigs
and experienced personnel in this area and may continue to do so in the future.
The Company also continues to incur higher drilling and operating costs
resulting from the increased fuel and steel costs and from the increased
drilling activity in this area.
Recent Developments
During the three months ended March 31, 2006, the Company spudded five gross
wells (approximately 3.4 net wells) and reached total depth on six gross wells
(approximately 3.5 net wells) in the Riverbend area. We also conducted initial
completion operations on four wells and re-entered seven wells to complete pay
zones that were behind pipe. As of March 31, 2006, we operated 45 gross wells.
Two additional wells are awaiting completion activities. We currently have three
drilling rigs operating in the Uinta Basin Riverbend project area and expect to
take delivery of our fourth rig in June 2006.
On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered
into a $250 million Credit Agreement (the "Credit Agreement") with JPMorgan
Chase Bank, N.A., as Administrative Agent and the other lenders named therein.
Borrowings made under the Credit Agreement are guaranteed by our subsidiaries
20
and secured by a pledge of the capital stock of our subsidiaries and mortgages
on substantially all of our oil & gas properties. We did not borrow any funds
under the Credit Agreement at the time of its execution.
The initial aggregate commitment of the lenders under the Credit Agreement is
$250,000,000, subject to a borrowing base which has initially been set at
$17,000,000. The Credit Agreement also provides for a $10,000,000 sublimit for
letters of credit which we may use for general corporate purposes. As of March
31, 2006 there were no loans outstanding, however, a $6,564,000 letter of credit
is considered usage for purposes of calculating availability and commitment
fees. Our aggregate borrowings and outstanding letters of credit under the
Credit Agreement may not at any time exceed the borrowing base. Interest on
borrowings is payable monthly and principal is due at maturity on March 29,
2010.
Interest on borrowings under the Credit Agreement accrues at variable interest
rates at either, at our election, a Eurodollar rate or an alternate base rate.
The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies
from 1.25% (for periods in which we have utilized less than 50% of the borrowing
base) to 2.00% (for periods in which we have utilized greater than 90% of the
borrowing base). The alternate base rate is calculated as (1) the greater of (a)
the Prime Rate or (b) the Federal Funds Effective Rate plus 1/2%, plus (2) an
applicable margin that varies from 0% (for periods in which we have utilized
less than 50% of the borrowing base) to 0.75% (for periods in which we have
utilized greater than 90% of the borrowing base). We elect the basis of the
interest rate at the time of each borrowing. In addition, we are obligated to
pay a commitment fee under the Credit Agreement quarterly in arrears based on a
percentage multiplied by the daily amount that the aggregate commitments exceed
borrowings under the agreement. The commitment fee percentage varies from 0.30%
to 0.50% based on the percentage of the borrowing base utilized.
The Credit Agreement requires us to comply with financial covenants that require
us to maintain (1) a Current Ratio (defined as current assets plus unused
availability under the Credit Facility divided by current liabilities excluding
the current portion of the Credit Facility), determined at the end of each
quarter, of not be less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX
(as such terms are defined in the Credit Agreement) for the most recent quarter
multiplied by four to be greater than 3.5:1 for each fiscal quarter. In
addition, the Credit Agreement contains covenants that restrict our ability to
incur other indebtedness, create liens or sell our assets, pay dividends on our
common stock and make certain investments.
The Company incurred $208,051 in debt issuance costs associated with this
facility. These costs have been recorded as an asset in the accompanying
financial statements and will be amortized using the straight-line method over
five years. The credit facility is available to provide funds for the
exploration, development and/or acquisition of oil and gas properties, to
refinance existing indebtedness and for working capital and other general
corporate purposes. The Credit Agreement provides for semi-annual evaluation of
the borrowing base, which will be determined as a percentage of the discounted
present value of the Company's oil and natural gas reserves.
21
Oil and Gas Production Summary
The following table presents the Company's production and price information
during the three months ended March 31, 2006 and 2005. The Mcfe calculations
assume a conversion of 6 Mcf for each Bbl of oil.
For the Three Months Ended
March 31,
2006 2005
----------- ------------
Natural gas production (Mcf) 876,571 137,838
Average sales price per Mcf $6.50 $5.19
Oil production (Bbl) 4,074 1,549
Average sales price per Bbl $57.08 $49.58
Production (Mcfe) 901,015 147,132
During the three months ended March 31, 2006, the Company's oil and gas
production increased by approximately 512% primarily due to the Company's
drilling projects, completions, and recompletions that took place during 2005
and 2006. The increased production was partially offset by normal production
declines in existing wells.
Liquidity and Capital Resources
The following table summarizes the Company's sources and uses of cash for each
of the three months ended March 31, 2006 and 2005.
For the Three Months Ended
March 31,
---------------------------------
2006 2005
---- ----
Net cash provided by (used in) operations $ 1,104,089 $ (520,052)
Net cash used in investing activities (23,705,008) (961,131)
Net cash provided by (used in) financing
activities 348,013 (6,809)
Net decrease in cash (22,252,906) (1,487,992)
The increase in cash provided by operations from 2005 to 2006 is primarily due
to a 512% increase in oil and gas production, a 25% increase in gas prices and a
15% increase in oil prices. The production increase is due to the Company's
drilling activity during 2005 and 2006.
The Company's investing activities during the three months ended March 31, 2006
and 2005 related primarily to the Company's development and exploration
activities. The 2006 activity also included investments in short-term
investments of $15,000,000. The 2005 investing activities were partially offset
22
by sales proceeds of $828,102 and proceeds from the Company's sale of short-term
investments of $5,000,000. The remaining investing activity during 2006 and 2005
consisted of changes in our restricted investments.
The financing activity during 2006 includes the exercise of 196,665 options to
purchase Gasco common stock for proceeds of $557,457 partially offset by the
payment of cash for debt issuance costs of $208,051 and the payment of preferred
dividends of $1,393. The financing activity during 2005 represented the payment
of preferred dividends of $6,809.
Capital Budget
The Board of Directors of Gasco approved a budget of $80 million for our 2006
capital expenditure program. The program will primarily cover the drilling and
completion of approximately 32 gross wells (15 net wells) on our Riverbend
Project and the drilling and completion of up to three wells in Wyoming. The
budget also includes expenditures for the installation of associated pipeline
infrastructure, distribution facilities and geophysical operations.
The budget will be funded primarily from cash on hand, cash from operating
activities and borrowings under our credit facility.
Schedule of Contractual Obligations
The following table summarizes the Company's obligations and commitments to make
future payments under its notes payable, operating leases, employment contracts,
consulting agreement and service contracts for the periods specified as of March
31, 2006.
Payments due by Period
Contractual Obligations Total 1 year 2-3 years 4-5 years After 5 years
Convertible Notes
Principal $65,000,000 $ - $ - $ - $ 65,000,000
Interest 19,712,153 3,575,000 7,150,000 7,150,000 1,837,153
Drilling Rig Contracts * 43,482,375 19,835,000 17,872,375 5,775,000 -
Operating Lease - office space 536,693 113,579 256,174 166,940 -
Employment Contracts 391,667 391,667 - - -
Consulting Agreements 160,000 160,000 - - -
---------- ---------- ---------- ---------- ----------
Total Contractual Cash
Obligations $129,282,888 $24,075,246 $25,278,549 $13,091,940 $66,837,153
============ =========== =========== =========== ===========
* The three year drilling contract for the new-build rig contains a
provision for the Company to terminate the contract for $12,000
per day for the number days remaining in the original contract.
The Company has not included asset retirement obligations as discussed in Note 2
of the accompanying financial statements, as the Company cannot determine with
accuracy the timing of such payments.
23
Critical Accounting Policies and Estimates
The preparation of the Company's consolidated financial statements in conformity
with generally accepted accounting principles in the United States requires
management to make assumptions and estimates that affect the reported amounts of
assets, liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. The
following is a summary of the significant accounting policies and related
estimates that affect the Company's financial disclosures.
Oil and Gas Reserves
Gasco follows the full cost method of accounting whereby all costs related to
the acquisition and development of oil and gas properties are capitalized into a
single cost center referred to as a full cost pool. Depletion of exploration and
development costs and depreciation of production equipment is computed using the
units of production method based upon estimated proved oil and gas reserves.
Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes may not exceed an
amount equal to the present value, discounted at 10%, of estimated future net
revenues from proved oil and gas reserves plus the cost, or estimated fair value
if lower, of unproved properties. Should capitalized costs exceed this ceiling,
an impairment would be recognized.
Estimated reserve quantities and future net cash flows have the most significant
impact on the Company because these reserve estimates are used in providing a
measure of the Company's overall value. These estimates are also used in the
quarterly calculations of depletion, depreciation and impairment of the
Company's proved properties.
Estimating accumulations of gas and oil is complex and is not exact because of
the numerous uncertainties inherent in the process. The process relies on
interpretations of available geological, geophysical, engineering and production
data. The extent, quality and reliability of this technical data can vary. The
process also requires certain economic assumptions, some of which are mandated
by the Securities and Exchange Commission ("SEC"), such as gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. The accuracy of a reserve estimate is a function of the quality and
quantity of available data; the interpretation of that data; the accuracy of
various mandated economic assumptions; and the judgment of the persons preparing
the estimate.
The most accurate method of determining proved reserve estimates is based upon a
decline analysis method, which consists of extrapolating future reservoir
pressure and production from historical pressure decline and production data.
The accuracy of the decline analysis method generally increases with the length
of the production history. Since most of the Company's wells have been producing
less than five years, their production history is relatively short, so other
(generally less accurate) methods such as volumetric analysis and analogy to the
production history of wells of other operators in the same reservoir were used
in conjunction with the decline analysis method to determine the Company's
estimates of proved reserves including developed producing, developed
24
non-producing and undeveloped. As the Company's wells are produced over time and
more data is available, the estimated proved reserves will be redetermined on an
annual basis and may be adjusted based on that data.
Actual future production, gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable gas and oil
reserves most likely will vary from the Company's estimates. Any significant
variance could materially affect the quantities and present value of the
Company's reserves. For example a decrease in price of $0.10 per Mcf for natural
gas and $1.00 per barrel of oil would result in a decrease in the Company's
December 31, 2005 present value of future net cash flows of approximately
$3,792,200. In addition, the Company may adjust estimates of proved reserves to
reflect production history, acquisitions, divestitures, ownership interest
revisions, results of exploration and development and prevailing gas and oil
prices. The Company's reserves may also be susceptible to drainage by operators
on adjacent properties.
Impairment of Long-lived Assets
The cost of the Company's unproved properties is withheld from the depletion
base as described above, until such a time as the properties are either
developed or abandoned. These properties are reviewed periodically for possible
impairment. During 2003, the Company's management reviewed the unproved property
located within the state of Wyoming and determined that it would not be
developing some of the acres that were not considered to be prospective. As a
result, the Company estimated the value of these acres for the purpose of
recording the related impairment. The impairment was estimated by calculating a
per acre value from the total unproved costs incurred for the Wyoming acreage
divided by the total net acres owned by the Company. This per acre estimate was
applied to the acres that the Company did not plan to develop to calculate the
impairment. As a result, $1,725,000 of costs associated with this acreage was
reclassified into the full cost pool during the year ended December 31, 2003.
During the year ended December 31, 2005, approximately $5,300,000 of unproved
lease costs related primarily to expiring acreage in Wyoming was reclassified to
proved property. A change in the estimated value of the acreage could have a
material impact on the total of the impairment recorded by the Company.
Revenue Recognition
The Company's revenue is derived from the sale of oil and gas production from
its producing wells. This revenue is recognized as income when the production is
produced and sold. The Company typically receives its payment for production
sold one to three months subsequent to the month the production is sold. For
this reason, the Company must estimate the revenue that has been earned but not
yet received by the Company as of the reporting date. The Company uses actual
production reports to estimate the quantities sold, and the Questar Rocky
Mountain spot price less marketing and transportation adjustments to estimate
the price of the production. Variances between our estimates and the actual
amounts received are recorded in the month the payment is received.
25
Results of Operations
The following table presents information regarding the production volumes,
average sales prices received and average production costs associated with the
Company's sales of natural gas for the periods indicated. The Mcfe calculations
assume a conversion of 6 Mcf for each Bbl of oil.
For the Three
Months Ended
March 31,
2006 2005
Natural gas production (Mcf) 876,571 137,838
Average sales price per Mcf $ 6.50 $5.19
Oil production (Bbl) 4,074 1,549
Average sales price per Bbl $ 57.08 $ 49.58
Production (Mcfe) 901,015 147,132
Expenses per Mcfe:
Lease operating $ 0.59 $ 1.06
Depletion and impairment $ 3.14 $ 2.53
The First Quarter of 2006 compared to the First Quarter of 2005
Oil and gas revenue increased $5,138,150 during the first quarter of 2006
compared with the first quarter of 2005 due to an increase in oil and gas
production of 2,525 bbls and 738,733 Mcf combined with an increase in the
average oil and gas prices of $7.50 per bbl and $1.31 per Mcf during 2006. The
$5,138,150 increase in oil and gas revenue during 2006 is comprised of
$4,945,961 related to the production increase and $192,189 related to the price
increase. The production increase is due to the Company's drilling, completion
and recompletion activity during 2005 and through the first quarter of 2006 and
is partially offset by normal production declines on all wells.
Gathering income and expense represents the income earned and expenses incurred
from the Riverbend area pipeline that was constructed by the Company during 2004
and 2005.The gathering income and expenses have increased by $349,372 and
$163,046, respectively during the first quarter of 2006 as compared with the
first quarter of 2005 due to the increased production resulting from the
Company's drilling activity in this area.
Interest income increased $486,653 during the first quarter of 2006 compared
with the first quarter of 2005 primarily due to higher interest rates and higher
average cash and cash equivalent and short-term investment balances during 2006
relating primarily to the net proceeds of approximately $79,000,000 from the
Company's common stock offering during November 2005.
Lease operating expense increased $373,583 during the first quarter of 2006
compared with the first quarter of 2005 primarily due to the increased number of
producing wells during 2006 resulting from the Company's drilling activity
described above.
26
Depletion, depreciation and amortization expense during the first quarter of
2006 is comprised of $2,739,000 of depletion expense related to the Company's
proved oil and gas properties, $82,204 of depreciation expense related to the
Company's equipment, furniture, fixtures and other assets and $5,338 of
accretion expense related the Company's asset retirement obligation. The
corresponding expense during the first quarter of 2005 consists of $356,000 of
depletion expense related to the Company's proved oil and gas properties,
$13,596 of depreciation expense related to the Company's equipment, furniture,
fixtures and other assets and $2,640 of accretion expense related the Company's
asset retirement obligation. The increase in depletion expense during 2006 as
compared with 2005 is due primarily to the increase in production and related
costs resulting from the Company's increased drilling and completion activity
discussed above.
General and administrative expense increased by $1,460,238 during the first
quarter of 2006 as compared with the first quarter of 2005. The increase is
primarily due to an increase in stock based compensation expense of $989,417 due
to the adoption of FAS 123R on January 1, 2006 as further discussed in Note 3 of
the accompanying financial statements, an increase in compensation and
consulting expense of approximately $250,000 related to the Company's overall
increased operational activity, approximately $75,000 in insurance expense
related to higher premiums during 2006, $35,000 in fees associated with the
Company's audit of internal controls as required under the Sarbanes Oxley Act of
2002, approximately $20,000 in higher office and rent expenses related to the
Company's move to larger office space during the second quarter of 2005. The
remaining increase in general and administrative expenses is due to the
fluctuation in numerous other expenses, none of which are individually
significant.
Interest expense during 2006 and 2005 consists of interest expense related to
the Company's outstanding Convertible Notes which were issued on October 20,
2004.
Cautionary Statement Regarding Forward-Looking Statements
In the interest of providing the stockholders with certain information regarding
the Company's future plans and operations, certain statements set forth in this
Form 10-Q relate to management's future plans and objectives. Such statements
are forward-looking statements within the meanings of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. All statements other than statements of historical
facts included in this report, including, without limitation, statements
regarding the Company's future financial position, business strategy, budgets,
projected costs and plans and objectives of management for future operations,
are forward-looking statements. In addition, forward-looking statements
generally can be identified by the use of forward-looking terminology such as
"may," "will," "expect," "intend," "project," "estimate," "anticipate,"
"believe," or "continue" or the negative thereof or similar terminology.
Although any forward-looking statements contained in this Form 10-Q or otherwise
expressed by or on behalf of the Company are, to the knowledge and in the
judgment of the officers and directors of the Company, believed to be
reasonable, there can be no assurances that any of these expectations will prove
correct or that any of the actions that are planned will be taken.
27
Forward-looking statements involve known and unknown risks and uncertainties
which may cause the Company's actual performance and financial results in future
periods to differ materially from any projection, estimate or forecasted result.
Important factors that could cause actual results to differ materially from the
Company expectations ("Cautionary Statements") include those discussed under the
caption "Risk Factors", in the Company's Form 10-K for the year ended December
31, 2004. All subsequent written and oral forward-looking statements
attributable to the Company, or persons acting on its behalf, are expressly
qualified in their entirety by the Cautionary Statements. The Company assumes no
duty to update or revise its forward-looking statements based on changes in
internal estimates or expectations or otherwise.
GLOSSARY OF NATURAL GAS AND OIL TERMS
The following is a description of the meanings of some of the natural
gas and oil industry terms used in this annual report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
this annual report in reference to crude oil or other liquid hydrocarbons.
Bbl/d. One Bbl per day.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production
of natural gas or oil, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable
to productive wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of natural gas or oil in another reservoir or to extend a
known reservoir. Generally, an exploratory well is any well that is not a
development well, a service well, or a stratigraphic test well.
Farm-in or farm-out. An agreement under which the owner of a working
interest in a natural gas and oil lease assigns the working interest or a
portion of the working interest to another party who desires to drill on the
28
leased acreage. Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."
Field. An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.
Lead. A specific geographic area which, based on supporting geological,
geophysical or other data, is deemed to have potential for the discovery of
commercial hydrocarbons.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBls. Million barrels of crude oil or other liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcf/d. One MMcf per day.
MMcfe. Million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interest
owned in gross acres or wells, as the case may be.
Net feet of pay. The true vertical thickness of reservoir rock
estimated to both contain hydrocarbons and be capable of contributing to
producing rates.
Present value of future net revenues or present value or PV-10. The
pretax present value of estimated future revenues to be generated from the
production of proved reserves calculated in accordance with SEC guidelines, net
of estimated production and future development costs, using prices and costs as
of the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and depreciation, depletion and amortization, and discounted using an
annual discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of the
production exceed production expenses and taxes.
29
Prospect. A specific geographic area which, based on supporting
geological, geophysical or other data and also preliminary economic analysis
using reasonably anticipated prices and costs, is deemed to have potential for
the discovery of commercial hydrocarbons.
Proved area. The part of a property to which proved reserves have been
specifically attributed.
Proved developed oil and gas 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 reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production responses that
increased recovery will be achieved.
Proved oil and gas reserves. The estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Reservoirs are considered proved
if economic producibility is supported by either actual production or conclusive
formation test. The area of a reservoir considered proved includes (a) that
portion delineated by drilling and defined by gas-oil and/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.
Estimates of proved reserves do not include the following: (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 from oil shales, coal, gilsonite and other such sources.
Proved properties. Properties with proved reserves.
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
are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
30
Proved undeveloped reserves may not include estimates attributable to any
acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by
actual tests in the area and in the same reservoir.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is separate from other reservoirs.
Service well. A well drilled or completed for the purpose of supporting
production in an existing field. Specific purposes of service wells include gas
injection, water injection, steam injection, air injection, salt-water disposal,
water supply for injection, observation, or injection for in-situ combustion.
Stratigraphic test well. A drilling effort, geologically directed, to
obtain information pertaining to a specific geologic condition. Such wells
customarily arc drilled without the intention of being completed for hydrocarbon
production. This classification also includes tests identified as core tests and
all types of expendable holes related to hydrocarbon exploration. Stratigraphic
test wells are classified as (a) "exploratory type," if not drilled in a proved
area, or (b) "development type," if drilled in a proved area.
Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage contains
proved reserves.
Unproved properties. Properties with no proved reserves.
Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and receive a
share of production.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risk relates to changes in the pricing applicable
to the sales of gas production in the Uinta Basin of northeastern Utah and the
Greater Green River Basin of west central Wyoming. This risk will become more
significant to the Company as more wells are drilled and begin producing in
these areas. Although the Company is not using derivatives at this time to
mitigate the risk of adverse changes in commodity prices, it may consider using
them in the future.
ITEM 4 - CONTROLS AND PROCEDURES
Our management has evaluated the effectiveness of our disclosure controls and
procedures as of March 31, 2006. Our disclosure controls and procedures are
designed to provide us with a reasonable assurance that the information required
to be disclosed in reports filed with the SEC is recorded, processed, summarized
and reported within the time periods specified in the SEC's rules and forms. The
31
disclosure controls and procedures are also designed to provide reasonable
assurance that such information is accumulated and communicated to our
management as appropriate to allow such persons to make timely decisions
regarding required disclosures.
Our management does not expect that our disclosure controls and procedures will
prevent all errors and all fraud. The design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Based on the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within the Company have been
detected. These inherent limitations include the realities that judgments in
decision-making can be faulty and that breakdowns can occur because of simple
errors or mistakes. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management
override of the controls. The design of any system of controls also is based in
part upon certain assumptions about the likelihood of future events. Therefore,
a control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met. Our disclosure controls and procedures are designed to provide such
reasonable assurances of achieving our desired control objectives, and our CEO
and CFO have concluded, as of March 31, 2006, that our disclosure controls and
procedures are effective in achieving that level of reasonable assurance. There
have not been any changes in the Company's internal control over financial
reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC
under the Securities Exchange Act of 1934) during the Company's most recently
completed fiscal quarter that have materially affected, or are reasonably likely
to materially affect, the Company's internal control over financial reporting.
32
PART II OTHER INFORMATION
Item 1 - Legal Proceedings
None.
Item 1A - Risk Factors
Information about material risks related to the Company's
business, financial condition and results of operations for three
months ended March 31, 2006, does not materially differ from that
set out in Part I, Item 1A of the Company's Annual Report on 10-K
for the year ended December 31, 2005.
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3 - Defaults Upon Senior Securities
None.
Item 4 - Submission of Matters to a Vote of Security Holders
None.
Item 5 - Other Information
None.
Item 6 - Exhibits
Exhibit Number Exhibit
3.1 Amended and Restated Articles of Incorporation (incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K dated December
31, 1999, filed on January 21, 2000).
3.2 Certificate of Amendment to Articles of Incorporation
(incorporated by reference to Exhibit 3.1 to the Company's Form
8-K/A dated January 31, 2001, filed on February 16, 2001).
3.3 Certificate of Amendment to Articles of Incorporation dated June
21, 2005 (incorporated by reference to Exhibit 3.3 to the
Company's Form 10-Q/A for the quarter ended June 30, 2005, filed
on August 9, 2005).
33
3.4 Amended and Restated Bylaws (incorporated by reference to Exhibit
3.4 to the Company's Form 10-Q for the quarter ended March 31,
2002, filed on May 15, 2002).
3.5 Certificate of Designation for Series B Preferred Stock
(incorporated by reference to Exhibit 3.5 to the Company's Form
S-1 Registration Statement, File No. 333-104592).
4.1 Form of Subscription and Registration Rights Agreement between
the Company and investors purchasing Common Stock in October 2003
(incorporated by reference to Exhibit 4.10 to the Company's Form
10-Q for the quarter ended September 30, 2003, filed on November
10, 2003).
4.2 Form of Subscription and Registration Rights Agreement between
the Company and investors purchasing Common Stock in February,
2004 (incorporated by reference to Exhibit 4.7 to the Company's
Form 10-K for the year ended December 31, 2003, filed on March
26, 2004.
4.3 Indenture dated as of October 20, 2004, between Gasco Energy,
Inc. and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.1 to the Company's
Current Report on Form 8-K filed on October 20, 2004).
4.4 Form of Global Note representing $65 million principal amount of
5.5% Convertible Senior Notes due 2011 (incorporated by reference
to Exhibit A to Exhibit 4.1 to the Company's Current Report on
Form 8-K filed on October 20, 2004).
4.5 Registration Rights Agreement dated October 20, 2004, among Gasco
Energy, Inc., J.P. Morgan Securities Inc. and First Albany
Capital Inc.
4.6 Credit Agreement dated as of March 29, 2006, among Gasco Energy,
Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as
Guarantors, the Lenders party thereto, JPMorgan Chase Bank, N.A.,
as Administrative Agent and JPMorgan Securities Inc., as Sole
Bookrunner and Lead Arranger (incorporated by reference to
Exhibit 4.1 to the Company's Current Report of Form 8-K filed on
March 31, 2006).
4.7 Pledge and Security Agreement entered into as of March 29, 2006,
by and among Grantors party thereto and JPMorgan Chase Bank,
N.A., as administrative agent (incorporated by reference to
Exhibit 4.2 to the Company's Current Report of Form 8-K filed on
March 31, 2006).
34
10.1 Joint Value Enhancement Agreement by and among Pannonian Energy
Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co.,
Red Oak Capital Management LLC and Schlumberger Technology
Corporation dated January 16, 2004 (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K filed on
January 21, 2004).
#10.2 Termination and Settlement Agreement, dated as of December 23,
2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A.
Erickson (incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed on January 31, 2005).
*#10.3 W. King Grant Amended and Restated Employment Contract dated
February 14, 2003.
*31 Rule 13a-14(a)/15d-14(a) Certifications.
*32 Section 1350 Certifications
* Filed herewith.
# Identifies management contracts and compensating plans or
arrangements.
35
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
GASCO ENERGY, INC.
Date: May 9, 2006 By: /s/W. King Grant
W. King Grant, Executive Vice President
Principal Financial and Accounting Officer
36