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: September 30, 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 November 7, 2006: 85,968,265
ITEM I - FINANCIAL INFORMATION
PART 1 - FINANCIAL STATEMENTS
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2006 2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents $19,998,698 $62,661,368
Restricted investment 3,575,000 10,139,000
Short-term investments 21,000,000 15,000,000
Accounts receivable
Joint interest billings 5,356,925 1,792,038
Revenue 1,924,849 3,115,154
Inventory 3,265,841 1,182,982
Prepaid expenses 324,766 645,554
----------- -----------
Total 55,446,079 94,536,096
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests 132,694,399 83,972,300
Unproved mineral interests 10,747,706 13,323,712
Wells in progress 3,631,845 -
Gathering assets 11,688,160 4,831,050
Facilities and equipment 7,069,119 5,148,388
Furniture, fixtures and other 235,880 175,607
----------- -----------
Total 166,067,109 107,451,057
Less accumulated depletion, depreciation, amortization and impairment (65,925,502) (6,986,662)
------------ -----------
Total 100,141,607 100,464,395
------------ -----------
OTHER ASSETS
Restricted investment 1,878,132 3,565,020
Deferred financing costs 2,501,065 2,634,461
----------- -----------
Total 4,379,197 6,199,481
----------- -----------
TOTAL ASSETS $ 159,966,883 $ 201,199,972
============= =============
The accompanying notes are an integral part of the
consolidated financial statements.
2
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
(Unaudited)
September 30, December 31,
2006 2005
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 3,027,442 $ 907,772
Revenue payable 1,599,767 1,658,141
Advances from joint interest owners 3,813,799 2,476,080
Accrued interest 1,737,851 844,098
Accrued expenses 6,238,520 2,571,047
----------- ---------
Total 16,417,379 8,457,138
----------- ---------
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes 65,000,000 65,000,000
Asset retirement obligation 650,788 223,947
Deferred rent expense 75,176 78,727
---------- ----------
Total 65,725,964 65,302,674
---------- ----------
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock - $.001 par value; 20,000
shared 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;
85,941,965 shares issued and 85,868,265 outstanding in 2006 and
85,041,492 shares issued and 84,967,792 shares outstanding in 2005 8,594 8,504
Additional paid-in capital 161,480,466 157,540,755
Deferred compensation - (443,579)
Accumulated deficit (83,535,225) (29,535,226)
Less cost of treasury stock of 73,700 common shares (130,295) (130,295)
------------ ------------
Total 77,823,540 127,440,160
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 159,966,883 $ 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
September 30,
-----------------------------------------
2006 2005
REVENUES
Gas $ 4,563,576 $ 3,793,771
Oil 336,963 166,727
Gathering 511,360 471,478
Interest income 646,834 264,751
--------- ---------
Total 6,058,733 4,696,727
--------- ---------
OPERATING EXPENSES
Lease operating 749,214 236,413
Gathering operations 1,065,658 267,792
Depletion, depreciation and amortization 2,206,328 1,211,550
General and administrative 1,768,788 1,323,376
Interest expense 1,055,504 1,008,293
--------- ---------
Total 6,845,492 4,047,424
--------- ---------
NET INCOME (LOSS) (786,759) 649,303
Preferred stock dividends - (6,212)
--------- ---------
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON
STOCKHOLDERS $ (786,759) $ 643,091
=========== =========
NET INCOME (LOSS) PER COMMON SHARE
BASIC $ (0.01) $ 0.01
========= =======
DILUTED $ (0.01) $ 0.01
========= =======
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC 85,609,137 70,991,812
========== ==========
DILUTED 85,609,137 75,838,798
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
4
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Nine Months Ended
September 30,
-------------------------------------------
2006 2005
REVENUES
Gas $ 14,573,596 $ 6,268,928
Oil 866,692 354,963
Gathering 1,363,755 927,375
Interest income 2,298,540 979,708
--------- ---------
Total 19,102,583 8,530,974
---------- ---------
OPERATING EXPENSES
Lease operating 2,145,978 598,115
Gathering operations 1,825,034 684,320
Depletion, depreciation and amortization 7,976,401 2,351,256
Impairment 51,000,000 -
General and administrative 7,041,831 3,922,097
Interest expense 3,113,338 3,024,878
---------- ----------
Total 73,102,582 10,580,666
---------- ----------
NET LOSS (53,999,999) (2,049,692)
Preferred stock dividends (1,393) (27,433)
----------- -----------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (54,001,392) $ (2,077,125)
============== =============
NET LOSS PER COMMON SHARE - BASIC AND DILUTED $ (0.63) $ (0.03)
========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED 85,384,515 70,661,070
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
5
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
-------------------------------------
2006 2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $(53,999,999) $ (2,049,692)
Adjustment to reconcile net loss to net cash provided by (used in)
operating activities
Depletion, depreciation, amortization and impairment expense 58,941,433 2,341,819
Accretion of asset retirement obligation 34,968 9,437
Stock compensation 3,198,834 539,378
Amortization of deferred rent (3,551) 39,897
Amortization of deferred financing costs 373,658 343,626
Landlord incentive payment - 30,000
Changes in operating assets and liabilities:
Accounts receivable (2,374,582) (1,414,058)
Inventory (2,082,859) (826,140)
Prepaid expenses 320,788 207,136
Accounts payable 2,119,670 (988,953)
Revenue payable (58,374) 1,006,120
Advances from joint interest owners 1,337,719 343,306
Accrued interest 893,753 1,042,710
Accrued expenses 428,742 1,545,737
--------- ---------
Net cash provided by operating activities 9,130,200 2,170,323
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (62,866) (85,388)
Cash paid for acquisitions, development and exploration (55,109,912) (35,356,065)
Proceeds from property sales - 828,102
Increase in short-term investments (6,000,000) -
Proceeds from sale of short-term investments - 17,000,000
Cash designated as restricted (100,612) (208,331)
Cash undesignated as restricted 8,351,500 1,638,542
----------- -----------
Net cash used in investing activities (52,921,890) (16,183,140)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (1,393) (21,501)
Exercise of options to purchase common stock 1,370,675 968,239
Cash paid for debt issuance costs (240,262) -
--------- ----------
Net cash provided by financing activities 1,129,020 946,738
--------- ----------
NET DECREASE IN CASH AND CASH EQUIVALENTS (42,662,670) (13,066,079)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 62,661,368 25,717,081
---------- ----------
END OF PERIOD $ 19,998,698 $ 12,651,002
============ ============
The accompanying notes are an integral part of the
consolidated financial statements.
6
GASCO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005
(Unaudited)
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 normal recurring 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
financial statements and summary of significant accounting policies and notes
included in the Company's Form 10-K for the year ended December 31, 2005.
The results of operations for the nine months ended September 30, 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 September 30, 2006 represents $5,453,132
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 investment 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.
7
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
consolidated 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. During the nine months ended September 30, 2006 approximately
$3,786,000 of unproved lease costs related to expiring acreage in Wyoming was
reclassified to proved property and was included in the ceiling test and
depletion calculations.
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 (full cost pool) may
not exceed an amount equal to the present value, discounted at 10%, of estimated
future net revenues from proved oil and gas reserves less the future cash
outflows associated with the asset retirement obligations that have been accrued
in the balance sheet plus the cost, or estimated fair value, if lower of
unproved properties and the costs of any properties not being amortized, if any.
Should the full cost pool exceed this ceiling, an impairment is recognized. The
present value of estimated future net revenues is computed by applying current
oil and gas prices to estimated future production of proved oil and gas reserves
8
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. However, subsequent commodity price increases may
be utilized to calculate the ceiling value.
As of September 30, 2006, based on oil and gas prices of $52.41 per barrel and
$3.05 per mcf, the full cost pool would have exceeded the above described
ceiling by $33,000,000. However, subsequent to the quarter end, oil and gas
prices increased; and using these prices, the Company's full cost pool would not
have exceeded the ceiling limitation. As a result of the increase in the ceiling
amount using subsequent prices, the Company has not recorded an impairment of
its oil and gas prices at September 30, 2006. As of June 30, 2006, the Company's
full cost pool exceeded the ceiling limitation based on oil and gas prices of
$59.87 per barrel and $5.42 per mcf. Subsequent commodity price increases were
not sufficient to eliminate the need for the impairment and therefore,
impairment expense of $51,000,000 was recorded during the quarter ended June 30,
2006.
Wells in Progress
Wells in progress at September 30, 2006 represent the costs associated with the
drilling of three wells in the Riverbend area of Utah and two wells in the
Greater Green River Basin in Wyoming. Since the wells had not reached total
depth as of September 30, 2006, they were classified as wells in progress and
were withheld from the depletion calculation and the ceiling test. The costs for
these wells will be transferred into proved property when the wells reach total
depth and are cased and will become subject to depletion and the ceiling test
calculation in future periods.
Deferred Financing Costs
Deferred financing costs include the costs associated with the Company's
issuance of $65,000,000 of Convertible Notes during October 2004, which are
being amortized over the seven year life of the notes; and the debt issuance
costs incurred in connection with the Company's credit facility, further
described in Note 5; which are being amortized over the four year term of the
credit facility.
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. Gasco's asset retirement obligation consists of costs related to
9
the plugging of wells, removal of facilities and equipment and site restoration
on its oil and gas properties. 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.
Nine Months Ended September 30,
2006 2005
Balance beginning of period $223,947 $108,566
Liabilities incurred 322,340 71,587
Liabilities settled - (21,845)
Revisions (a) 69,533 -
Accretion expense 34,968 9,437
--------- ---------
Balance end of period $ 650,788 $ 167,745
========== =========
(a) Revisions represent our annual reassessment of the expected cash flows
and assumptions inherent in the calculation of the asset retirement
liability.
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
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") 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. The
outstanding common stock options have been excluded from the computation of
diluted net loss per share during the quarter and nine months ended September
30, 2006 and during the nine months ended September 30, 2005 because their
inclusion would have been anti-dilutive. The table below reconciles the basic
weighted average common shares outstanding to the diluted weighted average
common shares outstanding for the quarter ended September 30, 2005. The basic
and diluted weighted average common shares outstanding are the same for all
other periods presented.
Basic weighted average common shares outstanding 70,991,812
Options to purchase common stock 4,846,986
-----------
Diluted weighted average common shares outstanding 75,838,798
===========
10
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.
Recently Issued Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS
No. 155, "Accounting for Certain Hybrid Financial Instruments-an amendment of
FASB Statements No. 133 and 140." SFAS No. 155 amends SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities," and also resolves issues addressed in SFAS No. 133 Implementation
Issue No. D1, "Application of Statement 133 to Beneficial Interests in
Securitized Financial Assets." SFAS No. 155 was issued to eliminate the
exemption from applying SFAS No. 133 to interests in securitized financial
assets so that similar instruments are accounted for in a similar fashion,
regardless of the instrument's form. The Company does not believe that its
financial position, results of operations or cash flows will be impacted by SFAS
No. 155 as the Company does not currently hold any hybrid financial instruments.
In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes ("FIN 48"). The interpretation clarifies the
accounting for uncertainty in income taxes recognized in a company's financial
statements in accordance with Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a
recognition threshold and a measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. The interpretation also provides guidance on the related
derecognition, classification, interest and penalties, accounting for interim
periods, disclosure and transition of uncertain tax positions. The
interpretation is effective for fiscal years beginning after December 15, 2006.
The adoption of FIN 48 is expected to have an immaterial impact on the Company's
consolidated financial position, results of operations or cash flows.
In September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157, "Fair Value Measurements" ("FAS 157"). This Statement defines fair
value as used in numerous accounting pronouncements, establishes a framework for
measuring fair value in generally accepted accounting principles and expands
disclosure related to the use of fair value measures in financial statements.
The Statement is to be effective for the Company's financial statements issued
in 2008; however, earlier application is encouraged. The Company is currently
evaluating the timing of adoption and the impact that adoption might have on its
financial position or results of operations.
In September 2006, the Securities and Exchange Commission ("SEC") issued Staff
Accounting Bulletin No. 108 ("SAB 108"). Due to diversity in practice among
11
registrants, SAB 108 expresses SEC staff views regarding the process by which
misstatements in financial statements are evaluated for purposes of determining
whether financial statement restatement is necessary. SAB 108 is effective for
fiscal years ending after November 15, 2006, and early application is
encouraged. The Company does not believe SAB 108 will have a material impact on
its financial position or results from operations.
NOTE 3 - STOCK BASED COMPENSATION
Gasco had 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 consolidated
financial statements for awards granted to consultants which must be re-measured
each period under the mark-to-market accounting method. Gasco had previously
adopted the provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation", as amended by SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure", through disclosure only.
On January 1, 2006, Gasco adopted SFAS No. 123(R), "Accounting for Stock-Based
Compensation," using the modified prospective method, which results in the
provisions of SFAS 123(R) being applied to the consolidated financial statements
on a going-forward basis. Prior periods have not been restated. SFAS 123(R)
requires companies to recognize share-based payments to employees as
compensation expense using a fair value method. Under the fair value recognition
provisions of SFAS 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 for employee
awards going forward based on the Company's historical forfeiture experience.
For non-employee awards, Gasco is assuming a 3% forfeiture rate for the 3 months
ending September 30, 2006. 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.
As of September 30, 2006, options to purchase an aggregate of 9,701,838 shares
of the Company's common stock and 251,210 shares of restricted stock were
outstanding. These awards were granted during the years from 2001 through 2006
to the Company's employees, directors and consultants. The options have exercise
prices ranging from $1.00 to $5.69 per share. The options vest at varying
schedules within three years of their grant date and expire within ten years
from the grant date. Stock-based employee compensation expense was $933,627 and
$3,203,928 and stock-based non-employee compensation expense or (reduction in)
expense was $(47,780) and $10,224 before tax for the three and nine months
ending September 30, 2006, respectively. Of this $(47,780) and $10,224 of total
calculated compensation expense for non-employees for the three and nine months
ending September 30, 2006, respectively, $(10,859) and $(4,326) was expensed and
$(36,921) and $14,550 was capitalized relating to drilling personnel.
The Company recognized the full impact of its equity incentive plans in the
consolidated statements of operations for the three and nine months ended
September 30, 2006 under FAS 123(R) and did not capitalize any such costs on the
consolidated balance sheets, as such costs that qualified for capitalization
were not significant.
12
The adoption of SFAS 123R increased the Company's basic and diluted net loss
attributable to common stockholders per share by $(.01) and $(.04) for the three
and nine month periods ending September 30, 2006, respectively. The Company did
not recognize a tax benefit from share-based compensation expense because the
Company considers it more likely than not that the related deferred tax assets,
which have been reduced by a full valuation allowance, will not be recognized.
The table below summarizes the effect on net loss and net loss per share for the
three and nine months ended September 30, 2005 as if the Company had applied the
fair value recognition of FAS No. 123(R) to the employee stock based awards.
For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
2005 2005
---- ----
Net income (loss) attributable to common shareholders:
As reported $643,091 $ (2,077,125)
Add: Stock-base employee compensation
included in net loss (a) 69,940 277,698
Less: Stock based employee compensation
determined under the fair value based method (944,474) (1,952,021)
Pro forma $(231,443) $ (3,751,448)
Basic net income (loss) per common share:
As reported $ 0.01 $ (0.03)
Pro forma (0.01) (0.05)
Diluted net income (loss) per common share:
As reported $ 0.01 $ (0.03)
Pro forma (0.01) (0.05)
The Company uses the Black-Scholes option-pricing model to estimate the fair
value of the options at the grant date. The fair value of options granted during
the nine months ended September 30, 2006 and 2005 were calculated using the
following assumptions:
Employee Options
2006 2005
------------ ---------
Expected dividend yield -- --
Expected price volatility 87-88% 75%-79%
Risk-free interest rate 4.85-5.08% 3.7-3.9%
Expected life of options 6 years 5 years
The weighted average grant-date fair value of options granted to employees
during the nine months ended September 30, 2006 was $4.10.
13
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 September 30, 2006:
Weighted-Average
Stock Options Exercise Price
----------------------------------------------------- --------------------
Outstanding at January 1, 2006 8,812,667 $2.29
----------------------------------------------------- --------------------
Granted 1,550,000 $5.48
----------------------------------------------------- --------------------
Exercised 479,161 $2.86
----------------------------------------------------- --------------------
Forfeited 169,168 $4.90
----------------------------------------------------- --------------------
Cancelled 12,500 $3.70
----------------------------------------------------- --------------------
Outstanding at September 30, 2006 9,701,838 $2.72
----------------------------------------------------- --------------------
Exercisable at September 30, 2006 7,442,640 $2.09
----------------------------------------------------- --------------------
The following table summarizes information related to the outstanding and vested
options as of September 30, 2006:
Outstanding Options Vested options
- --------------------------------------------------------------------------------
Number of shares 9,701,838 7,442,640
- --------------------------------------------------------------------------------
Weighted Average Remaining Contractual Life 6.82 6.07
- --------------------------------------------------------------------------------
Weighted Average Exercise Price $2.72 $2.09
- --------------------------------------------------------------------------------
Aggregate intrinsic value $6,041,752 $6,041,752
- --------------------------------------------------------------------------------
The aggregate intrinsic value in the table above represents the total pretax
intrinsic value, based on the Company's closing common stock price of $2.70 as
of September 30, 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 September 30, 2006:
Weighted-Average
Stock Options Exercise Price
-------------------------------------------------------------------------------
Nonvested stock options at January 1, 2006 2,238,386 $2.42
-------------------------------------------------------------------------------
Granted 1,550,000 $5.48
-------------------------------------------------------------------------------
Forfeited 169,168 $4.90
-------------------------------------------------------------------------------
Vested 1,360,021 $2.99
-------------------------------------------------------------------------------
Nonvested stock options at September 30, 2006 2,259,197 $4.80
-------------------------------------------------------------------------------
14
The total intrinsic value of options exercised during the three and nine months
ended September 30, 2006 was $9,563 and $1,128,201, respectively. The total cash
received from employees as a result of employee stock option exercises during
the three and nine months ended September 30, 2006 was approximately $94,688 and
$1,370,675, respectively. In connection with these exercises, the tax benefits
potentially realizable by the Company for the three and nine months ended
September 30, 2006 was $3,347 and $394,840. The Company has accumulated net
operating losses sufficient to offset its taxable income, 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 and nine months ended
September 30, 2006 was $375,568 and $2,889,976, respectively.
The Company settles employee stock option exercises with newly issued common
shares.
As of September 30, 2006, there was $7,911,521 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 1.15 years.
Restricted Stock
The following table summarizes the restricted stock activity from January 1,
2006 through September 30, 2006:
Weighted-Average Fair
Restricted Stock Value
------------------------------------------------------------------------------
Outstanding at January 1, 2006 565,380 $1.52
------------------------------------------------------------------------------
Granted - -
------------------------------------------------------------------------------
Vested 304,170 $0.93
------------------------------------------------------------------------------
Forfeited 10,000 $2.43
------------------------------------------------------------------------------
Outstanding at September 30, 2006 251,210 $2.20
------------------------------------------------------------------------------
As of September 30, 2006, there was $123,375 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
1.13 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 nine months of 2006, the Company granted 1,550,000 options to
purchase shares of common stock to its employees, directors and outside
consultants at exercise prices ranging from $3.05 to $5.69 per share. 95,000 of
the options vest 16 2/3% at the end of each four-month period after the issuance
date. The remaining options vest 16 2/3% at the end of each four-month period
commencing on the one year anniversary of the date of grant. All of the options
issued expire within ten years from the grant date.
15
During the first nine months of 2006, 57,787 shares of the Company's common
stock were cancelled in satisfaction of the income tax liability of $199,288
associated with the vesting of restricted stock.
During the first nine months of 2006, the Company issued 479,161 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 $3.70 per
common share for total proceeds of $1,370,675.
NOTE 5 - CREDIT FACILITY
On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered
into a $250,000,000 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 and gas properties. We have not borrowed any
funds under the Credit Agreement since 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 borrowing base was subsequently increased to $25,000,000 during
October 2006. 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
September 30, 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
16
quarter, of not 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 not 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 is currently in
compliance with each of the covenants contained in the credit agreement.
The Company incurred $240,262 in debt issuance costs associated with this
facility. These costs have been recorded as deferred financing costs in the
accompanying financial statements and are being amortized over the four year
term of the credit facility. 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 - ACQUISITIONS
Gasco acquired certain gathering assets and producing properties associated with
the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of
$4,875,000, plus settlement for production from effective date. The acquisition
included approximately 21 miles of 4" to 8" mainline gathering pipelines and 24
oil and gas wells. In the transaction, Gasco acquired approximately 1.6 billion
cubic feet equivalent of proved reserves. The acquisition has no effect on gross
acreage leasehold positions and a negligible effect on net acreage leasehold
totals. The transaction closed on August 14, 2006, with an effective date of
July 1, 2006.
On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy
Corporation ("Brek") for equity consideration of approximately 11,000,000 shares
of common stock valued at approximately $30,000,000 based on the closing price
of Gasco's stock on September 20, 2006. As a result of the acquisition, Gasco
will acquire approximately 17,095 net acres in the Uinta Basin of Utah and
approximately 12,495 net acres in the Green River Basin of Wyoming. The
acquisition is expected to simplify Gasco's acreage portfolio by absorbing a
working interest partner that previously owned approximately 14% of Gasco's
undeveloped acreage in Utah and Wyoming. Gasco does not expect to incur any
additional overhead expenses as a result of the acquisition. The boards of
directors of both Brek and Gasco have each approved the terms of the
transaction, which is expected to close during the first quarter of 2007. The
completion of the transaction is subject to the approval of the stockholders of
Brek and the completion of a distribution of certain subsidiaries of Brek to its
stockholders.
Under the terms of the transaction, a wholly owned subsidiary of Gasco will
merge with and into Brek. As a result of the merger, Brek will become a wholly
owned subsidiary of Gasco and each stockholder of Brek will receive a number of
shares of common stock of Gasco equal to 11,000,000 divided by the total number
of shares of common stock of Brek outstanding on the date of the merger,
calculated on a fully diluted basis. As part of the transaction, the directors
of Brek, who collectively own approximately 24% of Brek's outstanding stock,
have entered into an agreement to vote their shares in favor of the transaction.
In addition, Brek's President and CEO, who owns approximately 18% of the
outstanding common stock of Brek, has agreed to deposit 550,000 shares of Gasco
common stock acquired in the transaction in escrow to satisfy any claims with
respect to breaches of representations and warranties of Brek.
17
NOTE 7 - UNPROVED OIL AND GAS PROPERTIES
The following table sets forth a summary of oil and gas property costs not being
amortized as of December 31, 2005, by the year in which such costs were
incurred.
Costs Incurred During Years Ended December 31,
Balance -------------------------------------------------------------------
12/31/05 2005 2004 2003 Prior
-------- ---- ---- ---- -----
Acquisition costs $ 11,160,824 $ 283,114 $ 5,400,264 $284,653 $ 5,192,793
Exploration costs 2,162,888 791,914 219,936 667,850 483,188
----------- --------- --------- --------- ---------
Total $ 13,323,712 $ 1,075,028 $ 5,620,200 $ 952,503 $ 5,675,981
============ =========== =========== ========= ===========
The Company's drilling activities are located primarily in the Riverbend Area of
Utah, and the Company plans to drill approximately 28 to 30 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
remaining acreage in Wyoming and its acreage in California and Nevada such as
the farm-out of some of its acreage and other similar type arrangements.
NOTE 8 - STATEMENT OF CASH FLOWS
During the nine months ended September 30, 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 $322,340.
- Stock based compensation of $14,550 capitalized as proved property.
- Additions to oil and gas properties included in accrued expenses of
$3,039,444.
- Conversion of 763 shares of Preferred Stock into 479,599 shares of
common stock.
- Cancellation of 57,787 shares of common stock in satisfaction of the
income tax liability of $199,288 associated with the vesting of
restricted stock.
- Write-off of fully depreciated furniture and fixtures of $2,592.
During the nine months ended September 30, 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 $71,587. Reduction in the asset retirement obligation of
$21,845 representing the plugging and abandonment activity during the
first nine months of 2005.
18
- Conversion of 1,492 shares of Preferred Stock into 937,825 shares of
common stock.
- Write-off of fully depreciated furniture and fixtures of $58,652.
Cash paid for interest during the nine months ended September 30, 2006 and 2005
was $1,787,500 and $1,638,542, respectively. There was no cash paid for income
taxes during the nine months ended September 30, 2006 and 2005.
NOTE 9- 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 by 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.
19
Condensed Consolidating Balance Sheet
As of September 30, 2006
(Unaudited)
Guarantor
Parent Subsidiaries Eliminations Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 19,043,564 $955,134 $ - $ 19,998,698
Restricted investment 3,575,000 - - 3,575,000
Short-term investments 21,000,000 - - 21,000,000
Accounts receivable - 7,281,774 - 7,281,774
Inventory - 3,265,841 - 3,265,841
Prepaid expenses 324,766 - - 324,766
---------- ----------- -------- ----------
Total 43,943,330 11,502,749 - 55,446,079
---------- ---------- --------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests 14,551 132,679,848 - 132,694,399
Unproved mineral interests 274,540 10,473,166 - 10,747,706
Wells in progress - 3,631,845 - 3,631,845
Gathering assets - 11,688,160 - 11,688,160
Facilities and equipment - 7,069,119 - 7,069,119
Furniture, fixtures and other 235,880 - - 235,880
--------- ------------ -------- -----------
Total 524,971 165,542,138 166,067,109
-
Less accumulated depreciation, depletion and amortization (87,082) (65,838,420) - (65,925,502)
-------- ------------ -------- ------------
Total 437,889 99,703,718 - 100,141,607
--------- ------------ -------- -----------
OTHER ASSETS
Restricted investment 1,878,132 - - 1,878,132
Deferred financing costs 2,501,065 - - 2,501,065
Intercompany 142,858,873 (142,858,873) - -
----------- ------------- ------- ----------
Total 147,238,070 (142,858,873) - 4,379,197
----------- ------------- ------- ---------
TOTAL ASSETS $191,619,289 $ (31,652,406) - $159,966,883
============ =============== ------- ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 141,855 $2,885,587 $ - $ 3,027,442
Revenue payable - 1,599,767 - 1,599,767
Advances from joint interest owners - 3,813,799 - 3,813,799
Accrued interest 1,737,851 - - 1,737,851
Accrued expenses 538,000 5,700,520 - 6,238,520
--------- ---------- ------ ----------
Total 2,417,706 13,999,673 - 16,417,379
--------- ---------- ------ -----------
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes 65,000,000 - - 65,000,000
Asset retirement obligation - 650,788 - 650,788
Deferred rent expense 75,176 - - 75,176
---------- --------- ------ ----------
Total 65,075,176 650,788 - 65,725,964
---------- --------- ------- ----------
STOCKHOLDERS' EQUITY
Common stock 8,594 - - 8,594
Other 124,117,813 (46,302,867) - 77,814,946
----------- ------------ ------- ----------
Total 124,126,407 (46,302,867) - 77,823,540
----------- ------------ ------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $191,619,289 $(31,652,406) $ - $ 159,966,883
============ ============= ======= =============
20
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 LIABILITIES
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
============ =========== ====== =============
21
Consolidating Statements of Operations
(Unaudited)
For the Three Months Ended September 30, 2006 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil, gas and liquids $ - $ 4,900,539 $ - $ 4,900,539
Gathering - 977,622 (466,262) 511,360
Interest income 646,162 672 - 646,834
-------- --------- ---------- ---------
Total 646,162 5,878,833 (466,262) 6,058,733
-------- --------- ----------- ---------
OPERATING EXPENSES
Lease operating - 1,215,476 (466,262) 749,214
Gathering operations - 1,065,658 - 1,065,658
Depletion, depreciation and amortization 46,863 2,159,465 - 2,206,328
General and administrative 1,768,788 - - 1,768,788
Interest expense 1,055,504 - 1,055,504
---------- --------- --------- ---------
Total 2,871,155 4,440,599 (466,262) 6,845,492
---------- ---------- --------- ---------
NET INCOME (LOSS) (2,224,993) 1,438,234 - (786,759)
Preferred stock dividends - - - -
----------- ---------- --------- ---------
NET (INCOME) LOSS ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (2,224,993) $1,438,234 $ - $ (786,759)
============= ========== ====== ===========
For the Three Months Ended September 30, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 3,960,498 $ - $ 3,960,498
Gathering - 780,872 (309,394) 471,478
Interest income 264,721 30 264,751
------- ---------- ---------- ----------
Total 264,721 4,741,400 (309,394) 4,696,727
------- ---------- ---------- ----------
OPERATING EXPENSES
Lease operating - 545,807 (309,394) 236,413
Gathering operations - 267,792 - 267,792
Depletion, depreciation and amortization 11,566 1,199,984 - 1,211,550
General and administrative 1,323,376 - - 1,323,376
Interest expense 1,008,293 - - 1,008,293
--------- --------- ---------- ---------
Total 2,343,235 2,013,583 (309,394) 4,047,424
--------- --------- ---------- ---------
NET INCOME (LOSS) (2,078,514) 2,727,817 - 649,303
Preferred stock dividends (6,212) - - (6,212)
---------- ---------- ---------- ---------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (2,084,726) $2,727,817 $ - $ 643,091
============= ========== ========= =========
22
Consolidating Statements of Operations
(Unaudited)
For the Nine Months Ended September 30, 2006 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil, gas and liquids $ - $15,440,288 $ $ 15,440,288
Gathering - 2,885,057 (1,521,302) 1,363,755
Interest income 2,297,814 726 - 2,298,540
--------- ---------- ---------- ----------
Total 2,297,814 18,326,071 (1,521,302) 19,102,583
--------- ---------- ----------- ------------
OPERATING EXPENSES
Lease operating - 3,667,280 (1,521,302) 2,145,978
Gathering operations - 1,825,034 - 1,825,034
Depletion, depreciation and amortization 88,433 7,887,968 - 7,976,401
Impairment - 51,000,000 - 51,000,000
General and administrative 7,041,831 - - 7,041,831
Interest expense 3,113,338 - - 3,113,338
--------- ---------- ----------- ----------
Total 10,243,602 64,380,282 (1,521,302) 73,102,582
---------- ---------- ----------- ----------
NET LOSS (7,945,788) (46,054,211) - (53,999,999)
Preferred stock dividends (1,393) - - (1,393)
---------- ----------- ----------- -----------
NET LOSS ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (7,947,181) $(46,054,211) $ - $ (54,001,392)
============= ============= =============== ==============
For the Nine Months Ended September 30, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
REVENUES
Oil and gas $ - $ 6,623,891 $ - $ 6,623,891
Gathering - 1,354,182 (426,807) 927,375
Interest income 979,617 91 979,708
------- ---------- --------- -----------
Total 979,617 7,978,164 (426,807) 8,530,974
------- ---------- ---------- -----------
OPERATING EXPENSES
Lease operating - 1,024,922 (426,807) 598,115
Gathering - 684,320 - 684,320
Depletion, depreciation and amortization 37,705 2,313,551 - 2,351,256
General and administrative 3,895,366 26,731 - 3,922,097
Interest expense 3,024,878 - - 3,024,878
--------- ---------- -------- ---------
Total 6,957,949 4,049,524 (426,807) 10,580,666
--------- ---------- --------- ----------
NET INCOME (LOSS) (5,978,332) 3,928,640 - (2,049,692)
Preferred stock dividends (27,433) - - (27,433)
---------- --------- -------- ----------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ (6,005,765) $3,928,640 $ - $ (2,077,125)
============= ========== =========== =============
23
Consolidating Statements of Cash Flows
(Unaudited)
For the Nine Months Ended September 30, 2006 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES $ (3,810,792) $12,940,992 $ - $9,130,200
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (62,866) - - (62,866)
Cash paid for acquisitions, development and exploration - (55,109,912) - (55,109,912)
Investment in sale of short-term investments (6,000,000) - - (6,000,000)
Cash designated as restricted (100,612) - - (100,612)
Cash undesignated as restricted 8,351,500 - 8,351,500
---------- ------------ --------- -----------
Net cash provided by (used in) investing activities 2,188,022 (55,109,912) - (52,921,890)
--------- ------------ -------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (1,393) - - (1,393)
Exercise of options to purchase common stock 1,370,675 - - 1,370,675
Cash paid for debt issuance costs (240,262) (240,262)
Intercompany (39,777,029) 39,777,029 - -
------------ ---------- ------- ---------
Net cash provided by (used in) financing activities (38,648,009) 39,777,029 - 1,129,020
------------ ---------- ------- ---------
NET DECREASE IN CASH AND CASH
EQUIVALENTS (40,270,779) (2,391,891) - (42,662,670)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 59,314,343 3,347,025 - 62,661,368
---------- ---------- ------- -----------
END OF PERIOD $ 19,043,564 $955,134 $ - $19,998,698
============ =========== ========= ===========
For the Nine Months Ended September 30, 2005 Guarantor
Parent Subsidiaries Eliminations Consolidated
CASH FLOWS USED IN OPERATING ACTIVITIES $ (30,687,565) $32,857,888 $ - $2,170,323
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (85,388) - - (85,388)
Cash paid for acquisitions, development and exploration - (35,356,065) - (35,356,065)
Proceeds from property sales - 828,102 - 828,102
Proceeds from sale of short-term investments 17,000,000 - - 17,000,000
Cash designated as restricted (208,331) - - (208,331)
Cash undesignated as restricted 1,638,542 - - 1,638,542
----------- ------------ --------- ------------
Net cash provided by (used in) investing activities 18,344,823 (34,527,963) - (16,183,140)
----------- ----------- --------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (21,501) - - (21,501)
Intercompany 968,239 - - 968,239
---------- ------------ ---------- ----------
Net cash provided by financing activities 946,738 - - 946,738
---------- ------------ --------- ----------
NET DECREASE IN CASH AND CASH
EQUIVALENTS (11,396,004) (1,670,075) - (13,066,079)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 23,357,073 2,360,008 - 25,717,081
---------- --------- ----------- ----------
END OF PERIOD $ 11,961,069 $ 689,933 $ - $12,651,002
============ ========= ========== ===========
-
24
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. Our realized gas prices during the
first nine months were lower than those realized during the year ended December
31, 2005 due primarily to higher inventory levels of gas storage, milder
temperatures during the past winter and changing demand in the United States.
Our realized oil prices have remained relatively stable during 2005 and the
first nine months of 2006. We continue to experience higher drilling and
operating costs resulting from increased fuel and steel costs and from increased
drilling activity in this area.
Recent Developments
During the nine months ended September 30, 2006, the Company spudded 22 gross
wells (approximately 13.4 net wells) and reached total depth on 20 gross wells
(approximately 11.7 net wells) in the Riverbend area. We also conducted initial
completion operations on 15 wells (8.9 net wells) and re-entered 14 wells (7.3
net wells) to complete pay zones that were behind pipe. As of September 30,
2006, we operated 72 gross wells with five additional wells awaiting completion
activities. We currently have four drilling rigs operating in the Uinta Basin
Riverbend project, having taken delivery of our fourth rig in August 2006.
Gasco entered into a farmout agreement with an industry partner that will drill
to earn acreage in our Daniel Anticline Prospect in Wyoming. Under the terms of
the farmout agreement, we will pay 25% of the well costs and will earn 25 % of
the first well which is planned to be a Hilliard Shale test. In subsequent
wells, we will receive a 25% carried working interest and will pay 25% of the
well costs until the cumulative carry is $10,000,000 to Gasco. The agreement
allows our industry partner to earn 50% of our Daniel Anticline Prospect to all
25
depths. We will retain operations of the wells in the project. We have also
established an area of mutual interest (AMI) covering this prospect. The AMI
will allow both parties to jointly test the productive potential in the core
area and to later implement a plan of development. Gasco and its partner are
currently drilling the first well in this area which is permitted to a proposed
total depth of 16,500 feet, with a total cost estimate to drill and complete of
$8,000,000 ($2,000,000 net to Gasco).
Gasco is also currently drilling a well in the Muddy Creek Prospect in Wyoming
to test natural gas potential in two formations to a revised proposed depth of
14,400 feet. Intermediate casing was set at approximately 9,600 feet, and the
rig has been released and drilling operations have been suspended due to winter
lease stipulations. Drilling operations on this well are expected to resume in
July 2007. The costs to drill and complete this well are estimated to be
approximately $5,500,000 and Gasco has a 100% working interest.
During the nine months ended September 30, 2006 approximately $3,786,000 of
unproved lease costs related primarily to expiring acreage in Wyoming were
reclassified to proved property.
We utilize the full cost method of accounting, under which capitalized oil and
gas property costs less accumulated depletion, net of deferred income taxes
(full cost pool) may not exceed an amount equal to the present value, discounted
at 10%, of estimated future net revenues from proved oil and gas reserves less
the future cash outflows associated with the asset retirement obligations that
have been accrued in the balance sheet plus the cost, or estimated fair value,
if lower of unproved properties and the costs of any properties not being
amortized, if any. Should the full cost pool exceed this ceiling, an impairment
is recognized. This impairment is recorded as non-cash expense and is not
permitted to be reversed in future periods in the event that oil and gas prices
subsequently increase resulting in a higher ceiling. 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. However, subsequent commodity price increases may be utilized to
calculate the ceiling value.
As of September 30, 2006, based on oil and gas prices of $52.41 per barrel and
$3.05 per mcf, the full cost pool would have exceeded the above described
ceiling by $33,000,000. However, subsequent to the quarter end, oil and gas
prices increased; and using these prices, the Company's full cost pool would not
have exceeded the ceiling limitation. As a result of the increase in the ceiling
amount using subsequent prices, the Company has not recorded an impairment of
its oil and gas prices at September 30, 2006. As of June 30, 2006, the Company's
full cost pool exceeded the ceiling limitation based on oil and gas prices of
$59.87 per barrel and $5.42 per mcf. Subsequent commodity price increases were
not sufficient to eliminate the need for the impairment and therefore,
impairment expense of $51,000,000 was recorded during the quarter ended June 30,
2006.
Gasco acquired certain gathering assets and producing properties associated with
the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of
$4,875,000, plus settlement for production from effective date. The gathering
assets and properties are located entirely within Gasco's existing Riverbend
leasehold allowing the Company to further capitalize on economies of scale and
operating efficiencies. The transaction closed on August 14, 2006, with an
effective date of July 1, 2006.
26
The Company assigned a value of approximately $2,500,000 to the gathering
assets, which include 21 miles of 4" to 8" mainline gathering pipelines. The
acquired gathering assets should provide more timely and cost-effective tie-in
of the existing Wilkin Ridge and West Desert systems to Gasco's Riverbend gas
processing facility. Gasco now controls over 80 miles of mainline gathering and
a 50 MMcf/d gas processing facility in the Riverbend Project.
Gasco previously announced an $80 million 2006 capital budget that included $5.0
million to connect its Wilkin Ridge and West Desert gathering systems to its
Riverbend gas processing plant. The gathering lines acquired in this transaction
may be tied into these systems at an estimated cost of $1.5 million, allowing
the company to potentially realize a savings of $1.0 million versus amounts
previously budgeted.
Also included in the acquisition are 24 oil and gas wells producing 400 thousand
cubic feet equivalent per day (Mcfe/d) gross (320 Mcfe/d net). In the
transaction, Gasco acquired approximately 1.6 billion cubic feet equivalent of
proved reserves. The acquisition has no effect on gross acreage leasehold
positions and a negligible effect on net acreage leasehold totals.
A number of the wells are producing oil and associated gas from the shallow
Green River Formation. Some of the existing well pads will lend themselves to
also be used as locations for deeper Spring Canyon (Blackhawk) wells which
should yield savings on building a new drilling pad and access road of $50,000
to $100,000 per location.
On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy
Corporation ("Brek") for equity consideration of approximately 11,000,000 shares
of common stock valued at approximately $30,000,000 based on the closing price
of Gasco's stock on September 20, 2006. As a result of the acquisition, Gasco
will acquire approximately 17,095 net acres in the Uinta Basin of Utah and
approximately 12,495 net acres in the Green River Basin of Wyoming. The
acquisition is expected to simplify Gasco's acreage portfolio by absorbing a
working interest partner that previously owned approximately 14% of Gasco's
undeveloped acreage in Utah and Wyoming. Gasco does not expect to incur any
additional overhead expenses as a result of the acquisition. The boards of
directors of both Brek and Gasco have each approved the terms of the
transaction, which is expected to close during the first quarter of 2007. The
completion of the transaction is subject to the approval of the stockholders of
Brek and the completion of a distribution of certain subsidiaries of Brek to its
stockholders.
Under the terms of the transaction, a wholly owned subsidiary of Gasco will
merge with and into Brek. As a result of the merger, Brek will become a wholly
owned subsidiary of Gasco and each stockholder of Brek will receive a number of
shares of common stock of Gasco equal to 11,000,000 divided by the total number
of shares of common stock of Brek outstanding on the date of the merger,
calculated on a fully diluted basis. As part of the transaction, the directors
of Brek, who collectively own approximately 24% of Brek's outstanding stock,
have entered into an agreement to vote their shares in favor of the transaction.
In addition, Brek's President and CEO, who owns approximately 18% of the
outstanding common stock of Brek, has agreed to deposit 550,000 shares of Gasco
common stock acquired in the transaction in escrow to satisfy any claims with
respect to breaches of representations and warranties of Brek.
27
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 have not borrowed any funds
under the Credit Agreement since 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 borrowing base was subsequently increased to $25,000,000 during
October 2006. 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
September 30, 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 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 not 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. As of September 30, 2006, we were in
compliance with each of the covenants contained in the Credit Facility.
The Company incurred $240,262 in debt issuance costs associated with this
facility. These costs have been recorded as deferred financing costs in the
28
accompanying financial statements and are being amortized over the four year
term of the credit facility. 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.
Oil and Gas Production Summary
The following table presents the Company's production and price information
during the three and nine months ended September 30, 2006 and 2005. The Mcfe
calculations assume a conversion of 6 Mcf for each Bbl of oil.
For the Three Months Ended For the Nine Months
September 30, Ended September 30,
2006 2005 2006 2005
------------ ----------- ----------- ---------
Natural gas production (Mcf) 912,776 473,220 2,622,071 898,478
Average sales price per Mcf $5.00 $8.02 $ 5.56 $ 6.98
Oil production (Bbl) 5,677 2,672 14,754 6,346
Average sales price per Bbl $59.36 $62.40 $ 58.74 $ 55.93
Production (Mcfe) 946,838 489,252 2,710,595 936,554
During the three and nine months ended September 30, 2006, the Company's oil and
gas production increased by approximately 94% and 189% 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 from wells drilled during earlier periods.
Liquidity and Capital Resources
The following table summarizes the Company's sources and uses of cash for each
of the nine months ended September 30, 2006 and 2005.
For the Nine Months Ended
September 30,
--------------------------------------
2006 2005
---- ----
Net cash provided by operations $ 9,130,200 $ 2,170,323
Net cash used in investing activities (52,921,890) (16,183,140)
Net cash provided by financing activities 1,129,020 946,738
Net decrease in cash (42,662,670) (13,066,079)
The increase in cash provided by operations from 2005 to 2006 is primarily due
to an 192% increase in oil and gas production and a 5% increase in oil prices,
29
partially offset by a 21% decrease in gas prices. The production increase is due
to the Company's drilling activity during 2005 and 2006. As of September 30,
2006 we had 72 wells on production versus 35 wells at Septmber 30, 2005.
The Company's investing activities during the nine months ended September 30,
2006 and 2005 related primarily to the Company's development and exploration
activities. The 2006 activity also included investments in short-term
investments of $6,000,000. The 2005 investing activities were partially offset
by sales proceeds of $828,102 and proceeds from the Company's sale of short-term
investments of $17,000,000. The remaining investing activity during 2006 and
2005 consisted of changes in our restricted investments.
The financing activity during 2006 includes the exercise of 479,161 options to
purchase Gasco common stock for proceeds of $1,370,675 partially offset by the
payment of cash for debt issuance costs of $240,262 and the payment of preferred
dividends of $1,393. The financing activity during 2005 included the proceeds of
$968,239 from the exercise of 533,240 options to purchase common stock and the
payment of preferred dividends of $21,501.
Capital Budget
The Board of Directors of Gasco initially approved a budget of $80 million for
our 2006 capital expenditure program. The program was expected to primarily
cover the drilling and completion of approximately 32 gross wells (15 net wells)
in our Riverbend Project and the drilling and completion of up to three wells in
Wyoming. The budget also included $5 million in expenditures for the
installation of associated pipeline infrastructure, distribution facilities and
geophysical operations. As discussed above, Gasco acquired certain gathering
assets and producing properties associated with the Riverbend Project in the
Uinta Basin of Utah for a cash purchase price of $4,875,000, plus settlement for
production from the effective date of the acquisition. The gathering lines
acquired in this transaction may be tied into these systems at an estimated cost
of $1.5 million, allowing the company to potentially realize a savings of $1.0
million versus amounts previously budgeted.
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
September 30, 2006.
30
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 17,924,653 3,575,000 7,150,000 7,150,000 49,653
Drilling Rig Contracts * 36,517,125 24,108,125 12,409,000 - -
Operating Lease - office space 518,838 132,128 285,836 100,874 -
Employment Contracts 156,667 156,667 - - -
Consulting Agreements 76,000 76,000 - - -
----------- ---------- ----------- ---------- ----------
Total Contractual Cash
Obligations $120,193,283 $28,047,920 $19,844,836 $7,250,874 $65,049.653
============ =========== =========== ========== ===========
* The three year drilling contract for the new-build rig contains a
provision that permits 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.
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, the full cost pool (consisting of
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 less the future cash outflows associated with drilling asset retirement
obligations that have been accrued on the balance sheet plus the cost, or
estimated fair value if lower, of unproved properties and the costs of any
properties not being amortized, if any. Should the full cost pool exceed this
ceiling, an impairment would be recognized.
As of September 30, 2006, based on oil and gas prices of $52.41 per barrel and
$3.05 per mcf, the full cost pool would have exceeded the above described
ceiling by $33,000,000. However, subsequent to the quarter end, oil and gas
31
prices increased; and using these prices, the Company's full cost pool would not
have exceeded the ceiling limitation. As a result of the increase in the ceiling
amount using subsequent prices, the Company has not recorded an impairment of
its oil and gas prices at September 30, 2006. As of June 30, 2006, the Company's
full cost pool exceeded the ceiling limitation based on oil and gas prices of
$59.87 per barrel and $5.42 per mcf. Subsequent commodity price increases were
not sufficient to eliminate the need for the impairment and therefore,
impairment expense of $51,000,000 was recorded during the quarter ended June 30,
2006.
Estimated reserve quantities and future net cash flows have the most significant
impact on the Company because these reserve estimates are used in providing a
measure of the Company's overall value. These estimates are also used in the
quarterly calculations of depletion, depreciation and impairment of the
Company's proved properties.
Estimating accumulations of gas and oil is complex and is not exact because of
the numerous uncertainties inherent in the process. The process relies on
interpretations of available geological, geophysical, engineering and production
data. The extent, quality and reliability of this technical data can vary. The
process also requires certain economic assumptions, some of which are mandated
by the Securities and Exchange Commission ("SEC"), such as gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. The accuracy of a reserve estimate is a function of the quality and
quantity of available data; the interpretation of that data; the accuracy of
various mandated economic assumptions; and the judgment of the persons preparing
the estimate.
The most accurate method of determining proved reserve estimates is based upon a
decline analysis method, which consists of extrapolating future reservoir
pressure and production from historical pressure decline and production data.
The accuracy of the decline analysis method generally increases with the length
of the production history. Since most of the Company's wells have been producing
less than five years, their production history is relatively short, so other
(generally less accurate) methods such as volumetric analysis and analogy to the
production history of wells of other operators in the same reservoir were used
in conjunction with the decline analysis method to determine the Company's
estimates of proved reserves including developed producing, developed
non-producing and undeveloped. As the Company's wells are produced over time and
more data is available, the estimated proved reserves will be redetermined on an
annual basis and may be adjusted based on that data.
Actual future production, gas and oil prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable gas and oil
reserves most likely will vary from the Company's estimates. Any significant
variance could materially affect the quantities and present value of the
Company's reserves. In addition, the Company may adjust estimates of proved
reserves to reflect production history, acquisitions, divestitures, ownership
interest revisions, results of exploration and development and prevailing gas
and oil prices. The Company's reserves may also be susceptible to drainage by
operators on adjacent properties.
32
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 the nine months ended September 30, 2006, approximately
$3,786,000 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.
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 For the Nine
Months Ended Months Ended
September 30, September 30,
2006 2005 2006 2005
Natural gas production (Mcf) 912,776 473,220 2,622,071 898,478
Average sales price per Mcf $ 5.00 $ 8.02 $5.56 $6.98
Oil production (Bbl) 5,677 2,672 14,754 6,346
Average sales price per Bbl $ 59.36 $ 64.20 $ 58.74 $ 55.93
Production (Mcfe) 946,838 489,252 2,710,595 936,554
Expenses per Mcfe:
Lease operating $ 0.79 $ 0.48 $ 0.79 $ 0.64
Depletion and impairment $ 2.33 $ 2.47 $ 21.76 $ 2.51
The Third Quarter of 2006 compared to the Third Quarter of 2005
The increase in oil and gas revenue of $940,041 during the third quarter of 2006
compared with the third quarter of 2005 is comprised of an increase in oil and
gas production of 3,005 bbls and 439,556 Mcf partially offset by a decrease in
the average oil price of $4.84 per bbl and a decrease in the average gas price
of $3.02 per Mcf during 2006. The $940,041 increase in oil and gas revenue
during the third quarter of 2006 represents an increase of $2,384,609 related to
the production increase combined with a decrease of $1,444,568 related to the
oil and gas price decline. The production increase is due to the Company's
drilling, completion and recompletion activity during 2005 and through the first
nine months 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 increased by $39,882 during the third quarter of
2006 as compared with the third quarter of 2005 due to the increased production
resulting from the Company's drilling activity in this area. Approximately
$203,719 of the $797,866 increase in gathering expense is due to the
33
installation of additional compression to the system. The remaining increase in
gathering expense of $594,147 is the result of the Company's decision to revise
its methodology for calculating charges related to compressor fuel. The
additional expense resulting from this change represents amounts that will be
refunded to the outside working interest and royalty owners in the Company's
producing wells.
Interest income increased $382,083 during the third quarter of 2006 compared
with the third 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 $512,801 during the third quarter of 2006
compared with the third quarter of 2005. The increase is primarily due to the
increase in the number of producing wells from 35 wells at September 30, 2005 to
72 wells at September 30, 2006 as well as increased water hauling and disposal
costs. Additionally lease operating expense during the third quarter of 2006
includes approximately $100,000 of costs related to workovers performed on five
of our wells in the Riverbend area in order to restore efficient operating
conditions on these wells.
Depletion, depreciation and amortization expense during the third quarter of
2006 is comprised of depletion expense related to the Company's oil and gas
properties, depreciation expense of furniture, fixtures and equipment and
accretion expense related to the asset retirement obligation. The increase of
$994,778 is due primarily to the increase in oil and gas production and related
capital costs resulting from the Company's increased drilling and completion
activity discussed above, partially offset by the $51,000,000 reduction in the
full cost pool due to the impairment recorded during the second quarter of 2006.
General and administrative expense increased by $445,412 during the third
quarter of 2006 as compared with the third quarter of 2005. The increase is
primarily due to an increase in stock based compensation expense of $923,000 due
to the adoption of SFAS 123(R) on January 1, 2006 as further discussed in Note 3
of the accompanying financial statements, partially offset by the capitalization
of certain drilling and completion overhead related to specific projects during
the third quarter of 2006.
Interest expense during 2006 and 2005 consists of interest expense related to
the Company's outstanding Convertible Senior Notes which were issued on October
20, 2004.
The First Nine Months of 2006 Compared to the First Nine Months of 2005
The comparisons for the nine months ended September 30, 2006 and the nine months
ended September 30, 2005 are consistent with those discussed in the third
quarter of 2006 compared to the third quarter of 2005 except as discussed below:
The increase in oil and gas revenue of $8,816,397 during the first nine months
of 2006 compared with the first nine months of 2005 is comprised of an increase
in oil and gas production of 8,408 bbls and 1,723,593 Mcf combined with an
increase in the average oil price of $2.81 per bbl partially offset by a
decrease in the average gas price of $1.42 per Mcf during 2006. The $8,816,397
34
increase in oil and gas revenue during the first nine months of 2006 represents
an increase of $10,073,993 related to the production increase and a decrease of
$1,257,596 related to the decrease in oil and gas prices. The production
increase is due to the Company's drilling, completion and recompletion activity
during 2005 and through the first nine months of 2006 and is partially offset by
normal production declines on all wells.
Impairment expense during the nine months ended September 30, 2006 represents
the impairment recorded as of June 30, 2006 because the present value of Gasco's
future net revenue discounted at 10% exceeded the Company's full cost pool based
on current oil and gas prices of $59.87 per barrel and $5.42 per mcf.
Recently Issued Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS
No. 155, "Accounting for Certain Hybrid Financial Instruments-an amendment of
FASB Statements No. 133 and 140." SFAS No. 155 amends SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities," and also resolves issues addressed in SFAS No. 133 Implementation
Issue No. D1, "Application of Statement 133 to Beneficial Interests in
Securitized Financial Assets." SFAS No. 155 was issued to eliminate the
exemption from applying SFAS No. 133 to interests in securitized financial
assets so that similar instruments are accounted for in a similar fashion,
regardless of the instrument's form. The Company does not believe that its
financial position, results of operations or cash flows will be impacted by SFAS
No. 155 as the Company does not currently hold any hybrid financial instruments.
In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes ("FIN 48"). The interpretation clarifies the
accounting for uncertainty in income taxes recognized in a company's financial
statements in accordance with Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a
recognition threshold and a measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. The interpretation also provides guidance on the related
derecognition, classification, interest and penalties, accounting for interim
periods, disclosure and transition of uncertain tax positions. The
interpretation is effective for fiscal years beginning after December 15, 2006.
The adoption of FIN 48 is expected to have an immaterial impact on the Company's
consolidated financial position, results of operations or cash flows.
In September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157, "Fair Value Measurements" ("FAS 157"). This Statement defines fair
value as used in numerous accounting pronouncements, establishes a framework for
measuring fair value in generally accepted accounting principles and expands
disclosure related to the use of fair value measures in financial statements.
The Statement is to be effective for the Company's financial statements issued
in 2008; however, earlier application is encouraged. The Company is currently
evaluating the timing of adoption and the impact that adoption might have on its
financial position or results of operations.
35
In September 2006, the Securities and Exchange Commission ("SEC") issued Staff
Accounting Bulletin No. 108 ("SAB 108"). Due to diversity in practice among
registrants, SAB 108 expresses SEC staff views regarding the process by which
misstatements in financial statements are evaluated for purposes of determining
whether financial statement restatement is necessary. SAB 108 is effective for
fiscal years ending after November 15, 2006, and early application is
encouraged. The Company does not believe SAB 108 will have a material impact on
its financial position or results from operations.
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.
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, 2005. 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.
36
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
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.
37
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.
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
38
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.
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.
39
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.
40
ITEM 4 - CONTROLS AND PROCEDURES
Our management has evaluated the effectiveness of our disclosure controls and
procedures as of September 30, 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
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 September 30, 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.
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 the
nine months ended September 30, 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.
41
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds
The following table presents information about repurchases of our common stock
during the three months ended September 30, 2006:
Total Number of Maximum Number
Total Shares Purchased of Shares That May
Number Average as Part of Publicly Yet Be Purchased
Period of Shares Price Paid Announced Plans Under the Plans
Purchased(a) Per Share(a) or Programs or Programs
--------------- -------------------------------------------------------------
July 1, 2006 through July 31, 2006 22,061 $ 3.85 -- --
August 1, 2006 through August 31, 2006 35,726 3.00 -- --
------
Total 57,787 $ 3.32 -- --
=============== ============= ============= ==============
[GRAPHIC OMITTED]
(a) Represents the surrender to the Company of 57,787 shares of common stock to
pay withholding taxes in connection with the vesting of employee restricted
stock.
Working capital restrictions and other limitations upon the payment of dividends
are reported in Note 5 of the accompanying financial statements.
Item 3 - Defaults Upon Senior Securities
None.
Item 4 - Submission of Matters to a Vote of Security Holders
None.
Item 5 - Other Information
None.
42
Item 6 - Exhibits
Exhibit Number Exhibit
2.1 Agreement and Plan of Merger, dated as of September 20, 2006, by
and among Gasco Energy, Inc., Gasco Acquisition, Inc. and Brek
Energy Corporation (incorporated by reference to Exhibit 2.1 to
the Company's Current Report on Form 8-K filed on September 21,
2006).
3.1 Amended and Restated Articles of Incorporation (incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K dated December
31, 1999, filed on January 21, 2000).
3.2 Certificate of Amendment to Articles of Incorporation
(incorporated by reference to Exhibit 3.1 to the Company's Form
8-K/A dated January 31, 2001, filed on February 16, 2001).
3.3 Certificate of Amendment to Articles of Incorporation dated June
21, 2005 (incorporated by reference to Exhibit 3.3 to the
Company's Form 10-Q/A for the quarter ended June 30, 2005, filed
on August 9, 2005).
3.4 Amended and Restated Bylaws (incorporated by reference to Exhibit
3.4 to the Company's Form 10-Q for the quarter ended March 31,
2002, filed on May 15, 2002).
3.5 Certificate of Designation for Series B 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).
43
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).
4.8 Voting Agreement, dated September 20, 2006, by and among Gasco
Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson,
Michael L. Nazmack, Eugene Sweeney and Shawn Malone (incorporated
by reference to Exhibit 4.1 to the Company's Current Report on
Form 8-K filed on September 21, 2006).
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. (incorporated by reference to Exhibit 10.3 to
the Company's Form 10-Q for the quarter ended March 31, 2006,
filed on May 10, 2006).
*31 Rule 13a-14(a)/15d-14(a) Certifications.
44
*32 Section 1350 Certifications
* Filed herewith.
# Identifies management contracts and compensating plans or
arrangements.
45
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: November 7, 2006 By: /s/ W. King Grant
------------------
W. King Grant, Executive Vice President
Chief Financial Officer
By: /s/ Peggy A. Herald
---------------------
Peggy A. Herald, Chief Accouting Officer
and Controller
46