UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q/A
(Amendment No. 1)
(Mark One)
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended: June 30, 2005
[ ] TRANSITION REPORT UNDER SECTION 13 OF 15(d) OF THE EXCHANGE
ACT
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)
(303) 483-0044
(Registrant's telephone number, including area code)
14 Inverness Drive East, Suite H-236, Englewood, Colorado 80112
(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 an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
Number of Common shares outstanding as of August 9, 2005: 71,594,578
ITEM I - FINANCIAL INFORMATION
PART 1 - FINANCIAL STATEMENTS
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2005 2004
ASSETS
CURRENT ASSETS
Cash and cash equivalents $20,642,843 $ 25,717,081
Restricted investment 3,277,084 3,535,055
Short-term investments 13,000,000 27,000,000
Accounts receivable
Joint interest billings 4,015,253 429,779
Revenue 1,207,085 615,265
Inventory 566,440 1,009,914
Prepaid expenses 274,699 458,555
----------- ----------
Total 42,983,404 58,765,649
----------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests 46,554,580 29,811,483
Unproved mineral interests 17,945,375 18,449,330
Gathering assets 3,560,325 2,469,580
Equipment 97,398 89,900
Furniture, fixtures and other 168,886 158,590
---------- ----------
Total 68,326,564 50,978,883
---------- ----------
Less accumulated depreciation, depletion and amortization (3,322,087) (2,247,032)
----------- -----------
Total 65,004,477 48,731,851
----------- ----------
OTHER ASSETS
Restricted investment 5,556,489 6,778,040
Deferred financing costs 2,863,544 3,092,628
------------ ------------
Total 8,420,033 9,870,668
------------ ------------
TOTAL ASSETS $ 116,407,914 $ 117,368,168
============= =============
The accompanying notes are an integral part of the
consolidated financial statements.
2
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
(Unaudited)
June 30, December 31,
2005 2004
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,454,997 $ 1,447,149
Revenue payable 781,131 334,765
Advances from joint interest owners 2,508,560 891,999
Accrued interest 844,098 695,139
Accrued expenses 1,812,213 2,677,352
---------- ---------
Total 7,400,999 6,046,404
---------- ---------
NONCURRENT LIABILITES
5.5% Convertible Senior Notes 65,000,000 65,000,000
Asset retirement obligation 156,665 108,566
Deferred rent expense 53,724 -
---------- ----------
Total 65,210,389 65,108,566
---------- ----------
STOCKHOLDERS' EQUITY
Series B Convertible Preferred stock - $.001 par value; 20,000 shares
authorized; 943 shares issued and outstanding with a liquidation preference
of $414,920 in 2005 and 2,255 shares issued and
outstanding with a liquidation preference of $992,200 in 2004 1 2
Common stock - $.0001 par value; 300,000,000 shares authorized;
71,420,136 shares issued and 71,346,436 outstanding in 2005;
70,590,909 shares issued and 70,517,209 shares outstanding in 2004 7,142 7,059
Additional paid in capital 76,332,167 76,346,463
Deferred compensation (215,903) (512,440)
Accumulated deficit (32,196,586) (29,497,591)
Less cost of treasury stock of 73,700 common shares (130,295) (130,295)
----------- -----------
Total 43,796,526 46,213,198
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 116,407,914 $ 117,368,168
=============- =============
The accompanying notes are an integral part of the
consolidated financial statements.
3
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
June 30,
----------------------------------------
2005 2004
REVENUES
Gas $ 1,760,425 $ 731,163
Oil 111,441 45,992
Gathering 322,130 -
Interest income 354,904 33,148
--------- -------
Total 2,548,900 810,303
--------- -------
OPERATING EXPENSES
General and administrative 1,374,923 918,083
Lease operating 205,270 255,744
Gathering operations 191,781 -
Depletion, depreciation and amortization 767,470 264,204
Interest expense 1,008,323 93,253
--------- ---------
Total 3,547,767 1,531,284
--------- ---------
NET LOSS (998,867) (720,981)
Preferred stock dividends (14,050) (78,893)
------------- -----------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (1,012,917) $ (799,874)
============= ===========
NET LOSS PER COMMON SHARE - BASIC AND DILUTED $ (0.01) $ (0.01)
========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED 70,677,053 63,369,148
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
4
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Six Months Ended
June 30,
----------------------------------------
2005 2004
REVENUES
Gas $ 2,475,157 $ 1,432,787
Oil 188,236 95,886
Gathering 455,897 -
Interest income 714,957 48,405
--------- ---------
Total 3,834,247 1,577,078
--------- ---------
OPERATING EXPENSES
General and administrative 2,598,721 1,763,234
Lease operating 361,702 416,812
Gathering operations 416,528 -
Depletion, depreciation and amortization 1,139,706 501,339
Interest expense 2,016,585 160,760
--------- ---------
Total 6,533,242 2,842,145
--------- ---------
NET LOSS (2,698,995) (1,265,067)
Preferred stock dividends (21,212) (112,886)
------------- ------------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (2,720,207) $ (1,377,953)
============= =============
NET LOSS PER COMMON SHARE - BASIC AND DILUTED $ (0.04) $ (0.02)
========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED 70,128,560 59,271,972
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
5
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
----------------------------------
2005 2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $(2,698,995) $ (1,265,067)
Adjustment to reconcile net loss to net cash used in operating activities
Depreciation, depletion and impairment expense 1,133,707 491,676
Accretion of asset retirement obligation 5,999 9,663
Stock compensation 378,969 90,524
Amortization of beneficial conversion feature - 16,668
Non-cash rent expense 23,724 -
Landlord incentive payment 30,000
Amortization of deferred financing costs 229,084 18,620
Changes in operating assets and liabilities:
Accounts receivable (4,177,294) (589,504)
Inventory 443,474 (949,342)
Prepaid expenses 183,856 102,012
Accounts payable (67,586) 232,116
Revenue payable 446,366 484,233
Advances from joint interest owners 1,616,561 214,993
Accrued interest 148,959 -
Accrued expenses (865,139) (633,558)
----------- -----------
Net cash used in operating activities (3,168,315) (1,776,966)
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other (68,948) (37,551)
Cash paid for acquisitions, development and exploration (18,123,387) (7,461,894)
Proceeds from property sales 828,102 -
Proceeds from sale of short-term investments 14,000,000 -
---------- -----------
Net cash used in investing activities (3,364,233) (7,499,445)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends (21,212) (20,569)
Cash designated as restricted (159,020) -
Cash undesignated as restricted 1,638,542 250,000
Exercise of options to purchase common stock - 33,336
Proceeds from sale of common stock - 21,500,001
Cash paid for offering costs (1,429,659)
---------- -----------
Net cash provided by financing activities 1,458,310 20,333,109
--------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS (5,074,238) 11,056,698
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 25,717,081 3,081,109
------------ -----------
END OF PERIOD $ 20,642,843 $ 14,137,807
============ ============
6
The accompanying notes are an integral part of the
consolidated financial statements.
33
GASCO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE AND SIX MONTHS ENDED JUNE 30, 2005 AND 2004
NOTE 1 - ORGANIZATION
Gasco Energy, Inc. ("Gasco" or the "Company") is an independent energy company
engaged in the exploration, development, acquisition and production of crude oil
and natural gas reserves in the western United States. "Our", "we", and "us" as
used herein also refer to Gasco Energy, Inc.
The unaudited financial statements included herein were prepared from the
records of the Company in accordance with generally accepted accounting
principles in the United States applicable to interim financial statements and
reflect all adjustments which are, in the opinion of management, necessary to
provide a fair statement of the results of operations and financial position for
the interim periods. Such financial statements conform to the presentation
reflected in the Company's Form 10-K filed with the Securities and Exchange
Commission for the year ended December 31, 2004. The current interim period
reported herein should be read in conjunction with the Company's Form 10-K for
the year ended December 31, 2004.
The results of operations for the six months ended June 30, 2005 are not
necessarily indicative of the results that may be expected for the year ending
December 31, 2005. 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 represents funds invested in U.S. government
securities in an amount sufficient to provide for the payment of the first six
semi-annual scheduled interest payments on the Company's outstanding 5.5%
Convertible Notes ("Notes"). The current portion of restricted cash represents
the interest payments that are due within the current year and 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.
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
7
auctions that have a dividend rate period of 28 days or less. These securities
are stated at fair value based on quoted market prices. The income earned on
these investments is included in interest income in the accompanying financial
statements.
Property, Plant and Equipment
The Company follows the full cost method of accounting whereby all costs related
to the acquisition and development of oil and gas properties are capitalized
into a single cost center ("full cost pool"). Such costs include lease
acquisition costs, geological and geophysical expenses, overhead directly
related to exploration and development activities and costs of drilling both
productive and non-productive wells. Proceeds from property sales are generally
credited to the full cost pool without gain or loss recognition unless such a
sale would significantly alter the relationship between capitalized costs and
the proved reserves attributable to these costs. A significant alteration would
typically involve a sale of 25% or more of the proved reserves related to a
single full cost pool.
Depletion of exploration and development costs and depreciation of production
equipment is computed using the units of production method based upon estimated
proved oil and gas reserves. The costs of unproved properties are withheld from
the depletion base until it is determined whether or not proved reserves can be
assigned to the properties. The properties are reviewed quarterly for
impairment. Total well costs are transferred to the depletable pool even when
multiple targeted zones have not been fully evaluated. For depletion and
depreciation purposes, relative volumes of oil and gas production and reserves
are converted at the energy equivalent rate of six thousand cubic feet of
natural gas to one barrel of crude oil.
Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes may not exceed an
amount equal to the present value, discounted at 10%, of estimated future net
revenues from proved oil and gas reserves plus the cost, or estimated fair
value, if lower of unproved properties. Should capitalized costs exceed this
ceiling, an impairment is recognized. The present value of estimated future net
revenues is computed by applying current prices of oil and gas to estimated
future production of proved oil and gas reserves as of period-end, less
estimated future expenditures to be incurred in developing and producing the
proved reserves assuming the continuation of existing economic conditions.
Asset Retirement Obligation
The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations,
" which required 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
8
with future development activities that have not yet been capitalized as asset
retirement obligations. These costs are also included in the ceiling test
calculation. The asset retirement liability will be allocated to operating
expense by using a systematic and rational method. The information below
reconciles the value of the asset retirement obligation for the periods
presented.
Six Months Ended June 30,
2005 2004
Balance beginning of period $108,566 $ 142,806
Liabilities incurred 42,100 67,654
Liabilities settled - (13,442)
Revisions in estimated cash flows - -
Accretion expense 5,999 9,663
---------- ----------
Balance end of period $ 156,665 $ 206,681
========== =========
Revenue Recognition
Oil and gas revenue is recognized as income when the oil or gas is produced and
sold. The Company records revenues from the sales of natural gas and crude oil
when delivery to the customer has occurred and title has transferred. This
occurs when oil or gas has been delivered to a pipeline or a tank lifting has
occurred. The Company uses the sales method to account for gas imbalances. Under
this method, revenue is recorded on the basis of gas actually sold by the
Company. In addition, the Company records revenue for its share of gas sold by
other owners that cannot be volumetrically balanced in the future due to
insufficient remaining reserves. The Company also reduces revenue for other
owners' gas sold by the Company that cannot be volumetrically balanced in the
future due to insufficient remaining reserves. The Company's remaining over- and
under-produced gas balancing positions are considered in the Company's proved
oil and gas reserves. Gas imbalances during the periods presented in the
accompanying financial statements were not significant.
Computation of Net Loss Per Share
Basic net loss per share is computed by dividing net loss attributable to the
common stockholders by the weighted average number of common shares outstanding
during the reporting period. The shares of restricted common stock granted to
certain officers, directors and employees of the Company are included in the
computation only after the shares become fully vested. Diluted net income per
common share includes the potential dilution that could occur upon exercise of
the options to acquire common stock computed using the treasury stock method
which assumes that the increase in the number of shares is reduced by the number
of shares which could have been repurchased by the Company with the proceeds
from the exercise of the options (which were assumed to have been made at the
average market price of the common shares during the reporting period). The
Series B Convertible Preferred Stock ("Preferred Stock"), the 5.50% Convertible
Senior Notes due 2011 (the "Notes") and the outstanding common stock options
have not been included in the computation of diluted net loss per share during
all periods because their inclusion would have been anti-dilutive.
9
As of June 30, 2005, we had 71,346,436 shares of common stock outstanding. As of
such date, there were 9,262,250 shares of common stock issuable upon exercise of
outstanding options and conversion of our Series B Convertible Preferred Stock.
Additional options may be granted to purchase 1,556,721 shares of common stock
under our stock option plan and an additional 179,150 shares of common stock are
issuable under our restricted stock plan. As of December 31, 2004, and as of
December 31 of each succeeding year, the number of shares of common stock
issuable under our stock option plan automatically increases so that the total
number of shares of common stock issuable under such plan is equal to 10% of the
total number of shares of common stock outstanding on such date.
Assuming all of the Notes are converted at the applicable conversion prices, the
number of shares of our common stock outstanding would increase by approximately
16,250,000 shares to 87,596,436 shares (this number assumes no exercise of the
options or rights described above or conversion of the Series B Convertible
Preferred Stock).
Stock Based Compensation
The Company accounts for its stock-based compensation using Accounting
Principles Board Opinion No. 25 ("APB No. 25") and related interpretations.
Under APB 25, compensation expense is recognized for stock options with an
exercise price that is less than the market price on the grant date of the
option. For stock options with exercise prices at or above the market value of
the stock on the grant date, the Company adopted the disclosure-only provisions
of Statement of Financial Accounting Standards No. 123 "Accounting for
Stock-Based Compensation" ("SFAS 123") for the stock options granted to the
employees and directors of the Company. Accordingly, no compensation cost has
been recognized for these options. Compensation expense has been recognized in
the accompanying financial statements for stock options that were issued to our
outside consultants. Had compensation expense for the options granted to our
employees and directors been determined based on the fair value at the grant
date for the options, consistent with the provisions of SFAS 123, the Company's
net loss and net loss per share for the three and six months ended June 30, 2005
and 2004 would have been increased to the pro forma amounts indicated below:
For the Three Months Ended For the Six Months Ended
June 30, June 30,
2005 2004 2005 2004
---- ---- ---- ----
Net loss attributable to common shareholders:
As reported $(1,012,917) $(799,874) $ (2,720,207) $ (1,377,953)
Add: Stock-base employee compensation
included in net loss (a) 101,045 44,442 207,758 72,098
Less: Stock based employee compensation
determined under the fair value based method 625,341 161,979 1,002,213 379,270
Pro forma $(1,537,213) $ (917,411) $ (3,514,662) $ (1,685,125)
Net loss per common share:
As reported $ (0.01) $ (0.01) $ (0.04) $ (0.02)
Pro forma (0.02) (0.01) (0.05) (0.03)
10
(a) Represents the compensation expense associated with the Company's restricted
stock awards.
The fair value of the common stock options granted during 2005 and 2004, for
disclosure purposes was estimated on the grant dates using the Black Scholes
Pricing Model and the following assumptions.
2005 2004
Expected dividend yield -- --
Expected price volatility 75%-79% 79%-87%
Risk-free interest rate 3.7% 3.2%-3.7%
Expected life of options 5 years 5 years
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.
Recent Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which
is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No.
123(R) is effective for public companies for the first fiscal year beginning
after June 15, 2005, supersedes APB Opinion No. 25, Accounting for Stock Issued
to Employees, and amends SFAS No. 95, Statement of Cash Flows.
SFAS No. 123(R) requires all share-based payments to employees, including grants
of employee stock options, to be recognized in the income statement based on
their fair values. Pro-forma disclosure is no longer an alternative. The new
standard will be effective for the Company, beginning January 1, 2006. SFAS No.
123R permits companies to adopt its requirements using either a "modified
prospective" method, or a "modified retrospective" method. Under the "modified
prospective" method, compensation cost is recognized in the financial statements
beginning with the effective date, based on the requirements of SFAS No. 123R
for all share-based payments granted after that date, and based on the
requirements of SFAS No. 123 for all unvested awards granted prior to the
effective date of SFAS No. 123R. Under the "modified retrospective" method, the
requirements are the same as under the "modified prospective" method, but also
permits entities to restate financial statements of previous periods, either for
all prior periods presented or to the beginning of the fiscal year in which the
statement is adopted, based on previous pro forma disclosures made in accordance
with SFAS No. 123. The Company has not yet determined which of the methods it
will use upon adoption.
11
The Company has not yet completed its evaluation but expects the adoption SFAS
No. 123(R) to have an effect on the financial statements similar to the
pro-forma effects reported in the Stock Based Compensation disclosure above.
The Securities and Exchange Commission issued Staff Accounting Bulletin (SAB)
No. 106 in September 2004 regarding the application of SFAS No. 143, "Accounting
for Asset Retirement Obligations," for oil and gas producing entities that
follow the full cost accounting method. SAB No. 106, states that after adoption
of SFAS No. 143, the future cash outflows associated with settling asset
retirement obligations that have been accrued on the balance sheet should be
excluded from the present value of estimated future net cash flows used for the
full cost ceiling test calculation. The Company has calculated its ceiling test
computation in this manner since the adoption of SFAS No. 143 and, therefore,
SAB No. 106 had no effect on the Company's financial statements, effective in
the fourth quarter of 2004.
In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets,
which changes the guidance in APB 29, Accounting for Nonmonetary Transactions.
This Statement amends APB 29 to eliminate the exception for nonmonetary
exchanges of similar productive assets and replaces it with a general exception
for exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. SFAS
153 is effective during fiscal years beginning after June 15, 2005. We do not
believe the adoption of SFAS 153 will have a material impact on our financial
statements.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections ("SFAS 154"). This statement, which replaces APB Opinion No. 20,
Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in
Interim Financial Statements, requires that a voluntary change in accounting
principle be applied retrospectively to all prior period financial statements
presented, unless it is impracticable to do so. SFAS 154 also provides that a
change in method of depreciating or amortizing a long-lived non-financial asset
be accounted for as a change in estimate effected by a change in accounting
principle, and also provides that correction of errors in previously issued
financial statements should be termed a "restatement." SFAS 154 is effective for
fiscal years beginning after December 15, 2005. We do not believe the adoption
of SFAS 154 will have a material impact on our financial statements.
NOTE 3 - STOCK TRANSACTIONS
During the first six months of 2005, certain holders of the Company's Series B
Convertible Preferred Stock ("Preferred Stock") converted 1,312 shares of
Preferred Stock into 824,685 shares of common stock.
During January 2005, the Company granted 100,000 options to purchase shares of
common stock to one of its employees at an exercise price of $3.91 per share.
The options vest 16 2/3% at the end of each four-month period after the issuance
date. During June 2005, the Company granted an additional 2,205,000 options to
purchase shares of common stock to its employees, directors and outside
consultants at an exercise price of $3.39 per share. The options issued to the
12
Company's directors vest 25% at the end of each calendar quarter beginning
September 30, 2005 and the remaining options vest 16 2/3% at the end of each
four-month period after the issuance date. All of the options issued expire
within ten years from the grant date.
NOTE 4 - PROPERTY DISPOSITION
During 2004, the Company completed a disposition of net profits interests
between 18.75% and 25% in the 8 wells that have been drilled in the Riverbend
area in Utah during 2004 for total cash consideration of $4,314,984, net of
adjustments and commissions. The purpose of this transaction was to allow third
party investors to become a party to our service provider arrangements. The
consideration paid to the Company in this transaction represented the share of
such investor's development costs of the 8 wells. These investors have the
opportunity to continue to participate in the development program under the
service provider arrangement by funding 25% of future development costs.
The cash received by the Company consisted of $4,314,984, which represented the
purchase price for the transaction of $4,790,387 less adjustments of $327,227
for net revenue minus lease operating expense for the properties from June 2004
and $148,176, representing a commission to the purchasers' financial advisor,
which the Company agreed to pay.
The following unaudited pro forma consolidated results of operations are
presented as if the disposition occurred on January 1, 2004. The actual results
of operations are the same as the pro forma results for the three and six months
ended June 30, 2005 and for the three months ended June 30, 2004.
For the Six Months Ended
June 30,
2004
Revenue $ 1,727,449
Net Loss (1,195,970)
Net Loss Attributable to Common
Stockholders (1,288,201)
Net Loss per Common Share - Basic and Diluted $(0.02)
NOTE 5 - STATEMENT OF CASH FLOWS
During the six months ended June 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 $42,100.
- Conversion of 1,312 shares of Preferred Stock into 824,685 shares of
common stock.
13
- Write-off of fully depreciated furniture and fixtures of $58,652.
During the six months ended June 30, 2004, 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 $67,654. Reduction in the asset retirement obligation of
$13,442 representing the sale of 25% of the Company's interest in six
producing wells
- Conversion of 6,597 shares of Preferred Stock into 4,146,684 shares of
common stock.
- Issuance of 41,959 shares of common stock in payment of the June 30,
2004 Preferred Stock dividend.
- Issuance of 395,850 shares of restricted common stock to certain of
the Company's employees.
Cash paid for interest during the six months ended June 30, 2005 and 2004 was
$1,638,542 and $135,014, respectively. There was no cash paid for income taxes
during the six months ended June 30, 2005 and 2004.
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 is a natural gas and petroleum exploitation, development and production
company engaged in locating and developing hydrocarbon prospects, primarily in
the Rocky Mountain region. The Company's mission is to enhance shareholder value
by using new technologies to generate and develop high-potential exploitation
prospects in this area. The Company's principal business is the acquisition of
leasehold interests in petroleum and natural gas rights, either directly or
indirectly, and the exploitation and development of properties subject to these
leases.
The Company's corporate strategy is to grow through drilling projects. The
Company has been focusing its drilling efforts in the Riverbend Project located
in the Uinta Basin of northeastern Utah. The higher realized oil and gas prices
during 2004 and through the second quarter of 2005 due to factors such as
inventory levels of gas storage, different temperatures in parts of the country
and changing demand in the United States, combined with the continued
instability in the Middle East have increased the profitability of the Company's
14
drilling projects in this area. The increased drilling activity in the Company's
areas of operations resulting from the higher oil and gas prices has also
decreased the availability of drilling rigs and experienced personnel in this
area and may continue to do so.
Recent Developments
In January 2004, we entered into agreements, which were subsequently amended
during July 2004, with a group of industry service providers to accelerate the
development of our oil and gas properties by drilling up to 50 wells in our
Riverbend Project in Utah's Uinta Basin. The development of this project is
contemplated to proceed in increments of 10-well bundles to be approved by the
parties on an ongoing basis. To secure our obligations under the agreements, we
have pledged our interests in each of the wells that we drill. Under these
agreements, the service providers have the exclusive right to provide their
services in the development of the Riverbend acreage. Under these agreements, we
have agreed to fund approximately 30% of the development costs of each of the
wells drilled, with the service providers providing drilling and completion
services equivalent to 45% of the total development costs. The remaining
development costs are funded by third party investors that are also parties to
the agreements. Our interest in the production stream from each 10-well bundle
of wells, net of royalties, taxes and lease operating expenses, is estimated to
equal the proportion of the total well costs that we fund.
During the fourth quarter of 2004, the Service Parties agreed to proceed with
the second bundle of ten wells. The drilling of the second bundle commenced late
in 2004. The Company's capital budget for this area during 2005 is anticipated
to be $38,000,000 for the drilling of 20 wells in this area.
During the six months ended June 30, 2005, the Company spudded 11 gross wells
(approximately 6.8 net wells) and reached total depth on nine gross wells
(approximately 4.8 net wells) in the Riverbend area. We also conducted initial
completion operations on 12 wells and re-entered eight wells to complete pay
zones that were behind pipe. As of June 30, 2005, we had 30 gross wells on
production and one well flowing back frac fluid from recent completion
operations. We currently have three drilling rigs operating in the Uinta Basin
Riverbend project area.
During December 2004, the Company completed the acquisition of approximately
16,000 net acres in the Riverbend Area for a purchase price of approximately
$3,432,000. Pursuant to an existing contract, an unrelated third party had the
right to purchase 25% of the acquired acreage at a price equal to 25% of the
purchase price. This right was exercised by the third party during January 2005
which had the effect of reducing the Company's interest in the acquired acreage
to 12,000 net acres and reducing the purchase price of the acquisition to
approximately $2,575,000.
The Company re-entered one of its wells in the Muddy Creek Project in the
Greater Green River Basin Area in Wyoming during 2004 and the well is currently
producing intermittantly. The Company continues to consider several options for
its properties in this area such as the farm-out or sale of some of its acreage
and other similar type transactions.
15
During the first six months of 2005 the Company entered into a farm-out
agreement under which an unrelated entity has committed to drill one well on our
acreage in the San Luis Obispo and Kern Counties California prior to November
2005. Under this agreement Gasco will contribute the acreage and the unrelated
entity will pay the drilling and completion costs. Gasco will retain a 25%
interest if the well is successful. The Company is also continuing to pay
leasehold rentals and other minimum geological expenses to preserve its acreage
positions on its remaining California prospects.
Oil and Gas Production Summary
The following table presents the Company's production and price information
during the three and six months ended June 30, 2005 and 2004. The Mcfe
calculations assume a conversion of 6 Mcf for each Bbl of oil.
For the Three Months Ended For the Six Months Ended
June 30, June 30,
2005 2004 2005 2004
---------- ------------ ------------ -----------------
Natural gas production (Mcf) 287,420 122,694 425,258 249,502
Average sales price per Mcf $6.12 $5.96 $5.82 $ 5.74
Oil production (Bbl) 2,125 1,265 3,674 2,785
Average sales price per Bbl $52.44 $36.36 $51.23 $ 34.34
Production (Mcfe) 300,170 130,840 447,302 266,212
During the three and six months ended June 30, 2005, the Company's oil and gas
production increased by approximately 129% and 68% primarily due to the
Company's drilling projects, completions, and recompletions that took place
during 2004 and 2005. The increased production was partially offset by decreased
production resulting from the Company's disposition of net profits interests of
between 18.75% and 25% in 8 wells in the Riverbend area of Utah during the third
quarter of 2004 and by normal production declines in existing wells.
Gasco's 2005 capital budget is approximately $38 million for the drilling,
completion and pipeline connection of 20 wells in the Riverbend Project. The
Company is currently drilling with three rigs in the Riverbend area and believes
that it is on track to drill and complete 20 gross wells (13 net wells) for the
full-year 2005. The Company anticipates an overall increase in its compensation
expense because it will have to hire additional personnel to manage the workload
associated with its operational plan for 2005. The Company also continues to
incur higher drilling and operating costs resulting from the increased drilling
activity in this area.
Liquidity and Capital Resources
The following table summarizes the Company's sources and uses of cash for each
of the six months ended June 30, 2005 and 2004.
16
For the Six Months Ended
June 30,
-----------------------------------
2005 2004
---- ----
Net cash used in operations $ (3,168,315) $ (1,776,966)
Net cash used in investing activities (3,364,233) (7,499,445)
Net cash provided by financing activities 1,458,310 20,333,109
Net increase (decrease) in cash (5,074,238) 11,056,698
Cash used in operations during 2004 was primarily comprised of the Company's
general and administrative expenses partially offset by gas revenue from the
Company's producing wells. The increase in cash used in operations during 2005
is primarily the result of the fluctuations in the Company's operating assets
and liabilities and cash paid for interest due to the Company's increased
drilling and completion activity and interest on the $65 million convertible
senior notes. See further discussion under "Results of Operations".
The Company's investing activities during 2005 and 2004 related primarily to the
Company's development and exploration activities. These activities consisted of
the Company's drilling projects in the Riverbend area and the costs associated
with the Company's acreage in Utah, Wyoming and California. The decrease in cash
used in investing activities during 2005 is primarily due to the proceeds from
the Company's sale of $14,000,000 of short term investments offsetting its net
property additions of $17,364,233.
The financing activity during 2004 consisted primarily of the sale of 14,333,334
shares of common stock for gross proceeds of $21,500,001, cash paid for offering
costs of $1,429,659, preferred dividends of $20,569 and $33,336 of proceeds from
the exercise of options to purchase common stock. The financing activity during
2005 is comprised of preferred dividends and the designation and undesignation
of restricted cash.
Capital Budget
In January 2004 the Company entered into agreements, which were subsequently
amended during July 2004, with a group of industry providers (together, the
"Service Parties") to accelerate the development of Gasco's oil and gas
properties by drilling up to 50 wells in Gasco's Riverbend Project in Utah's
Uinta Basin. Gasco has agreed that the Service Parties will have the exclusive
right to provide their services in the development of the Riverbend acreage. The
agreement provides for the group to initially proceed with the first 10-well
bundle, which approximates one year of drilling with a single rig, with the
drilling of additional 10-well bundles being subject to the approval of the
group. The Company is currently using three drilling rigs and has commenced
drilling of the second 10-well bundle under this project. If the group agrees,
drilling may be accelerated using additional rigs. One of the drilling rigs is
currently drilling the second 10-well bundle. Under this agreement, the Company
has agreed to fund approximately 30% of the development costs of each of the
wells drilled, with the service providers providing drilling and completion
services equivalent to 45% of the total development costs and an additional
capital partner providing 25% of the total development costs. The service
17
providers are not required to expend more than a total of $13.5 million for
development of a given bundle. Furthermore, the service providers are not
obligated to provide any services unless each is satisfied that we will be able
to meet our cash expenditure requirements. The Company's interest in the
production stream from each 10-well bundle of wells, net of royalties, taxes and
lease operating expenses, is estimated to equal the proportion of the total well
costs that we fund.
To secure its obligations under the agreement described above, the Company has
pledged its interests in each of the wells in each bundle.
During the fourth quarter of 2004, the Service Parties agreed to proceed with
the second bundle of ten wells. The drilling of the second bundle commenced upon
completion of the first bundle. The locations of the wells for the third 10-well
bundle are currently being determined by Gasco Management for future
presentation to the other Service Parties.
The Company's capital budget for 2005 is anticipated to be $38 million for the
drilling, completion and pipeline connection of 20 gross or 13 to 14 net wells
in Gasco's Riverbend Project in the Uinta Basin of Utah. Pending notification by
industry partners of their decision to participate in Gasco's proposed 2005
drilling program, the Company would expect to spend up to an additional $5
million to drill 10 gross and two net wells. The initial capital budget does not
include surface infrastructure costs associated with gathering system
improvements. The anticipated 2005 gathering system budget is $2 million to $3
million, or approximately $100,000 per well for compression and pipeline
hook-up. The Company plans to contract for a fourth drilling rig during the last
half of 2005.
Management believes it has sufficient capital for its 2005 operational budget,
but will need to raise additional capital for its capital budget in 2006. The
Company will consider several options for raising additional funds such as
entering into a revolving line of credit, selling securities, selling assets or
farm-outs or similar type arrangements. Any financing obtained through the sale
of Gasco equity will likely result in substantial dilution to the Company's
stockholders.
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
and consulting agreement for the periods specified as of June 30, 2005.
Payments due by Period
Contractual Obligations Total 1 year 2-3 years 4-5 years After 5 years
----- ------ --------- --------- -------------
Convertible Notes
Principal $65,000,000 $ - $ - $ - $ 65,000,000
Interest 22,393,403 3,575,000 7,150,000 7,150,000 4,518,403
Operating Lease - office space 380,138 83,250 151,608 145,280 -
Employment Contracts 274,167 274,167 - - -
Consulting Agreement 70,000 70,000 - - -
---------- ---------- --------- ---------- ----------
Total Contractual Cash
Obligations $ 88,117,708 $ 4,002,417 $7,301,608 $ 7,295,280 $69,518,403
============ =========== ========== =========== ===========
18
During the first quarter of 2005, the Company entered into a new office lease
which commenced May 23, 2005 and terminates on May 31, 2010. The Company's
previous office lease expires on August 30, 2005. The table above includes
future obligations that exist under both leases.
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 Properties and Reserves
Gasco follows the full cost method of accounting whereby all costs related to
the acquisition and development of oil and gas properties are capitalized into a
single cost center referred to as a full cost pool. Depletion of exploration and
development costs and depreciation of production equipment is computed using the
units of production method based upon estimated proved oil and gas reserves.
Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes may not exceed an
amount equal to the present value, discounted at 10%, of estimated future net
revenues from proved oil and gas reserves plus the cost, or estimated fair value
if lower, of unproved properties. Should capitalized costs exceed this ceiling,
an impairment is recognized.
Estimated reserve quantities and future net cash flows have the most significant
impact on the Company because these reserve estimates are used in providing a
measure of the Company's overall value. These estimates are also used in the
quarterly calculations of depletion, depreciation and impairment of the
Company's proved properties.
Estimating accumulations of gas and oil is complex and is not exact because of
the numerous uncertainties inherent in the process. The process relies on
interpretations of available geological, geophysical, engineering and production
data. The extent, quality and reliability of this technical data can vary. The
process also requires certain economic assumptions, some of which are mandated
by the Securities and Exchange Commission ("SEC"), such as gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. The accuracy of a reserve estimate is a function of the quality and
quantity of available data; the interpretation of that data; the accuracy of
various mandated economic assumptions; and the judgment of the persons preparing
the estimate.
19
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 two 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. 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, 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.
Revenue Recognition
The Company's revenue is derived from the sale of oil and gas production from
its producing wells. This revenue is recognized as income when the production is
produced and sold. The Company typically receives its payment for production
sold one to three months subsequent to the month the production is sold. For
this reason, the Company must estimate the revenue that has been earned but not
yet received by the Company as of the reporting date. The Company uses actual
production reports to estimate the quantities sold and the Questar Rocky
Mountain spot price less marketing and transportation adjustments to estimate
the price of the production. Variances between our estimates and the actual
amounts received are recorded in the month the payment is received.
Stock Based Compensation
The Company accounts for its stock-based compensation using the intrinsic value
recognition and measurement principles detailed in Accounting Principles Board's
Opinion No. 25 ("APB No. 25"). No stock-based compensation expense has been
reflected in the Company's financial statements for the options granted to its
employees as these options had exercise prices equal to or higher than the
market value of the underlying common stock on the date of grant. The Company
uses the Black-Scholes option valuation model to calculate the required
disclosures under SFAS 123. This model requires the Company to estimate a risk
free interest rate and the volatility of the Company's common stock price. The
use of a different estimate for any one of these components could have a
material impact on the amount of calculated compensation expense.
20
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 Six
Months Ended Months Ended
June 30, June 30,
2005 2004 2005 2004
Natural gas production (Mcf) 287,420 122,694 425,258 249,502
Average sales price per Mcf $ 6.12 $ 5.96 $ 5.82 $5.74
Oil production (Bbl) 2,125 1,265 3,674 2,785
Average sales price per Bbl $ 52.44 $ 36.36 $ 51.82 $ 34.43
Production (Mcfe) 300,170 130,284 447,302 266,212
Expenses per Mcfe:
Lease operating $ 0.68 $ 1.63 $ 0.81 $ 1.57
Depletion and impairment $ 2.56 $ 1.96 $ 2.55 $ 1.74
The Second Quarter of 2005 compared to the Second Quarter of 2004
Oil and gas revenue increased $1,094,711 during the second quarter of 2005
compared with the second quarter of 2004 due to an increase in gas production of
164,726 Mcf and an increase in oil production of 860 bbls during the second
quarter of 2005 combined with an increase in the average oil prices of $16.08
per bbl and an increase in the average gas price of $0.16 per Mcf during the
second quarter of 2005. The increase in production is primarily due to the
Company's drilling, completion and recompletion activity during 2004 and 2005.
The increase is partially offset by decreased production resulting from the
Company's disposition of approximately 50% of its revenue interest in two wells
during the first quarter of 2004 in accordance with its service party
arrangements as discussed above and by normal production declines on the
existing wells.
The gathering income of $322,130 and the gathering expense of $191,781 during
the quarter ended June 30, 2005 represents the income earned and expenses
incurred from the Riverbend area pipeline that was constructed by the Company
during 2004.
Interest income increased $321,756 during the second quarter of 2005 compared
with the second quarter of 2004 primarily due to higher average cash and cash
equivalent and short-term investment balances during 2005 relating primarily to
proceeds from the Company's $65,000,000 Convertible Note issuance during October
2004.
General and administrative expense increased by $456,840 during the second
quarter of 2005 as compared with the second quarter of 2004, primarily due to
the Company's increased operational activity. The increase in these expenses is
comprised of approximately $120,000 in salary expense and consulting fees
associated with the Company's increased operational activity, approximately
21
$34,000 in audit fees associated with the Company's audit of internal controls
as required under the Sarbanes Oxley Act of 2002, $192,000 in stock based
compensation primarily related to the Company's restricted stock issuance and
the issuance of stock options to consultants, approximately $25,000 in insurance
expense related to higher premiums during 2005, approximately $45,000 in higher
office and rent expenses related to the Company's move to larger office space
during the second quarter of 2005 and approximately $38,000 in costs related to
increased shareholder communications relating to the Company's expanded
operational activity. The remaining increase in general and administrative
expenses is due to the fluctuation in numerous other expenses, none of which are
individually significant.
Depletion, depreciation and amortization expense during the second quarter of
2005 is comprised of $750,000 of depletion expense related to the Company's
proved oil and gas properties, $14,111 of depreciation expense related to the
Company's equipment, furniture, fixtures and other assets and $3,359 of
accretion expense related the Company's asset retirement obligation. The
corresponding expense during the second quarter of 2004 consists of $245,100 of
depletion expense, $14,273 of depreciation expense and $4,831 of accretion
expense. The increase in depletion expense during 2005 as compared with 2004 is
due primarily to the increase in production resulting from the Company's
increased drilling and completion activity discussed above.
Interest expense during 2005 consists of interest expense related to the
Company's outstanding Convertible Notes which were issued on October 20, 2004.
Interest expense during 2004 consists of the interest on the Company's
outstanding Convertible Debentures that were converted into common stock during
October 2004.
The First Six Months of 2005 compared to the First Six Months of 2004
The comparisons for the six months ended June 30, 2005 and the six months ended
June 30, 2004 are consistent with those discussed in the second quarter of 2005
compared to the second quarter of 2004 except as discussed below.
Oil and gas revenue increased $1,134,720 during the first six months of 2005
compared with the first six months of 2004 due to an increase in gas production
of 175,756 Mcf and an increase in oil production of 889 bbls during 2005
combined with an increase in the average oil prices of $17.39 per bbl and an
increase in the average gas price of $0.08 per Mcf during 2005. The increase in
production is primarily due to the Company's drilling, completion and
recompletion activity during 2004 and 2005. The increase is partially offset by
decreased production resulting from the Company's disposition of approximately
50% of its revenue interest in two wells during the first quarter of 2004 in
accordance with its service party arrangements as discussed above and by normal
production declines on the existing wells.
Recent Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which
is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No.
123(R) is effective for public companies for the fiscal year beginning after
22
June 15, 2005, supersedes APB Opinion No. 25, Accounting for Stock Issued to
Employees, and amends SFAS No. 95, Statement of Cash Flows.
SFAS No. 123(R) requires all share-based payments to employees, including grants
of employee stock options, to be recognized in the income statement based on
their fair values. Pro-forma disclosure is no longer an alternative. The new
standard will be effective for the Company, beginning January 1, 2006. SFAS No.
123R permits companies to adopt its requirements using either a "modified
prospective" method, or a "modified retrospective" method. Under the "modified
prospective" method, compensation cost is recognized in the financial statements
beginning with the effective date, based on the requirements of SFAS No. 123R
for all share-based payments granted after that date, and based on the
requirements of SFAS No. 123 for all unvested awards granted prior to the
effective date of SFAS No. 123R. Under the "modified retrospective" method, the
requirements are the same as under the "modified prospective" method, but also
permits entities to restate financial statements of previous periods, either for
all prior periods presented or to the beginning of the fiscal year in which the
statement is adopted, based on previous pro forma disclosures made in accordance
with SFAS No. 123. The Company has not yet determined which of the methods it
will use upon adoption.
The Company has not yet completed its evaluation but expects the adoption of
SFAS No. 123(R) to have an effect on the financial statements similar to the
pro-forma effects reported in the Stock Based Compensation disclosure above.
The Securities and Exchange Commission issued Staff Accounting Bulletin (SAB)
No. 106 in September 2004 regarding the application of SFAS No. 143, "Accounting
for Asset Retirement Obligations," for oil and gas producing entities that
follow the full cost accounting method. SAB No. 106, states that after adoption
of SFAS No. 143, the future cash outflows associated with settling asset
retirement obligations that have been accrued on the balance sheet should be
excluded from the present value of estimated future net cash flows used for the
full cost ceiling test calculation. The Company has calculated its ceiling test
computation in this manner since the adoption of SFAS No. 143 and, therefore,
SAB No. 106 had no effect on the Company's financial statements, effective in
the fourth quarter of 2004.
In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets,
which changes the guidance in APB 29, Accounting for Nonmonetary Transactions.
This Statement amends APB 29 to eliminate the exception for nonmonetary
exchanges of similar productive assets and replaces it with a general exception
for exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. SFAS
153 is effective during fiscal years beginning after June 15, 2005. We do not
believe the adoption of SFAS 153 will have a material impact on our financial
statements.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections ("SFAS 154"). This statement, which replaces APB Opinion No. 20,
Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in
Interim Financial Statements, requires that a voluntary change in accounting
principle be applied retrospectively to all prior period financial statements
presented, unless it is impracticable to do so. SFAS 154 also provides that a
change in method of depreciating or amortizing a long-lived non-financial asset
be accounted for as a change in estimate effected by a change in accounting
principle, and also provides that correction of errors in previously issued
23
financial statements should be termed a "restatement." SFAS 154 is effective for
fiscal years beginning after December 15, 2005. We do not believe the adoption
of SFAS 154 will have a material impact on our financial statements.
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, 2004. All subsequent written and oral forward-looking statements
attributable to the Company, or persons acting on its behalf, are expressly
qualified in their entirety by the Cautionary Statements. The Company assumes no
duty to update or revise its forward-looking statements based on changes in
internal estimates or expectations or otherwise.
GLOSSARY OF NATURAL GAS AND OIL TERMS
The following is a description of the meanings of some of the natural
gas and oil industry terms used in this annual report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
this annual report in reference to crude oil or other liquid hydrocarbons.
Bbl/d. One Bbl per day.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
24
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.
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.
25
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
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
26
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.
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.
27
Unproved properties. Properties with no proved reserves.
Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and receive a
share of production.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risk relates to changes in the pricing applicable
to the sales of gas production in the Uinta Basin of northeastern Utah and the
Greater Green River Basin of west central Wyoming. This risk will become more
significant to the Company as more wells are drilled and begin producing in
these areas. Although the Company is not using derivatives at this time to
mitigate the risk of adverse changes in commodity prices, it may consider using
them in the future.
ITEM 4 - CONTROLS AND PROCEDURES
Our management has evaluated the effectiveness of our disclosure controls and
procedures as of June 30, 2005. Our disclosure controls and procedures are
designed to provide us with a reasonable assurance that the information required
to be disclosed in reports filed with the SEC is recorded, processed, summarized
and reported within the time periods specified in the SEC's rules and forms. The
disclosure controls and procedures are also designed to provide reasonable
assurance that such information is accumulated and communicated to our
management as appropriate to allow such persons to make timely decisions
regarding required disclosures.
Our management does not expect that our disclosure controls and procedures will
prevent all errors and all fraud. The design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Based on the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within the Company have been
detected. These inherent limitations include the realities that judgments in
decision-making can be faulty and that breakdowns can occur because of simple
errors or mistakes. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management
override of the controls. The design of any system of controls also is based in
part upon certain assumptions about the likelihood of future events. Therefore,
a control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met. Our disclosure controls and procedures are designed to provide such
reasonable assurances of achieving our desired control objectives, and our CEO
and CFO have concluded, as of June 30, 2005, that our disclosure controls and
procedures are effective in achieving that level of reasonable assurance.
The Company is in the process of evaluating the recently implemented changes it
believes are required to remediate the following previously reported material
weaknesses in internal control over financial reporting.
28
1. Insufficient segregation of duties with respect to the review of the
bank reconciliation of an account used for general and administrative
expenses and the review of certain other general corporate accounts,
such as prepaid and other assets. The individual responsible for
generating checks from our accounting system was also responsible for
reconciling this bank account.
2. Insufficient documentation with respect to the review of non-standard
journal entries. The Chief Financial Officer reviewed each of the
transactions that were recorded in non-standard journal entries,
however, the documentation of the review by our Chief Financial
Officer of the non-standard journal entries themselves did not exist
in all cases.
3. Insufficient documentation of our quarterly closing procedures. During
2004 we did not maintain a written checklist of procedures to be
carried out each quarter to close our accounting records for the
reporting period. We conducted procedures appropriate to properly
close our books, however; the documentation of the physical inventory
count at December 31, 2004 and the documentation of the review of the
calculations of the asset retirement obligation and equity
compensation does not exist.
4. Insufficient documentation of the controls with respect to the input
and output of transactions recorded by our outsourced accounting
function with respect to the revenue and joint interest billing
processes. We outsourced our accounting function during the third
quarter of 2004. Due to the timing of this change of accounting
procedures there were an insufficient number of transactions during
2004 available for testing.
New or additional control procedures were implemented by management during the
first quarter of 2005 with the intent to eliminate each of the material
weaknesses described above. These include assigning the responsibility of
checking account reconciliation to an employee not responsible for signing
checks, documenting the Chief Financial Officer's review of non-standard journal
entries and utilizing a written checklist of procedures for closing our
accounting records for each reporting period. Because these additional controls
have been recently implemented, there has not been sufficient time or a
sufficient number of transactions to evaluate the effectiveness of these
additional controls.
Other than the changes discussed above, 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.
29
PART II OTHER INFORMATION
Item 1 - Legal Proceedings
None.
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3 - Defaults Upon Senior Securities
None.
Item 4 - Submission of Matters to a Vote of Security Holders
The Company held its Annual Meeting ("Annual Meeting") of Stockholders on June
9, 2005. The meeting was held to elect eight directors to serve until the 2006
Annual Meeting of Stockholders, to approve the amendment to the Gasco Energy,
Inc. articles of incorporation to increase the number of authorized shares of
common stock from 100,000,000 to 300,000,000 shares and to ratify the selection
of Hein & Associates LLP as independent auditors of the Company for the year
ending December 31, 2005.
The "For" column represents the number of affirmative votes, and the "withheld"
column represents the number of abstentions and broker non-votes, by holders of
common and preferred stock represented by either proxy or at the Annual Meeting.
Only holders of preferred stock were permitted to vote for the Preferred Stock
Director, Richard Langdon. The results of the voting related to the elections of
the nominees for director were as follows:
Name For Withheld
Marc A. Bruner 49,631,182 14,948,757
Charles B. Crowell 63,865,500 714,439
Mark A. Erickson 49,743,982 14,835,957
Richard J. Burgess 63,876,400 703,539
Carmen J. (Tony) Lotito 63,845,850 734,089
Carl Stadelhofer 63,871,514 708,425
John Schmit 62,968,100 1,611,839
Preferred Stock Director
Richard S. Langdon 763 180
Stockholders voted 48,412,164 shares "for" and 16,096,234 shares "against" the
proposal to approve the amendment to the Gasco Energy, Inc. articles of
30
incorporation to increase the number of authorized shares of common stock from
100,000,000 to 300,000,000 shares, with 71,541 votes abstaining.
Stockholders voted 64,412,845 shares "for" and 124,333 shares "against" the
proposal to ratify the selection of Hein & Associates LLP as independent
auditors of the Company for the fiscal year ending December 31, 2005, with
42,761 votes abstaining.
Item 5 - Other Information
None.
Item 6 - Exhibits
Exhibit Number Exhibit
3.1 Amended and Restated Articles of Incorporation (incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K dated December
31, 1999, filed on January 21, 2000).
3.2 Certificate of Amendment to Articles of Incorporation
(incorporated by reference to Exhibit 3.1 to the Company's Form
8-K/A dated January 31, 2001, filed on February 16, 2001).
*3.3 Certificate of Amendment to Articles of Incorporation dated June
21, 2005.
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.
31
4.3 Indenture dated as of October 20, 2004, between Gasco Energy,
Inc. and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.1 to the Company's
Current Report on Form 8-K filed on October 20, 2004).
4.4 Form of Global Note representing $65 million principal amount of
5.5% Convertible Senior Notes due 2011 (incorporated by reference
to Exhibit A to Exhibit 4.1 to the Company's Current Report on
Form 8-K filed on October 20, 2004).
4.5 Registration Rights Agreement dated October 20, 2004, among Gasco
Energy, Inc., J.P. Morgan Securities Inc. and First Albany
Capital Inc.
*31 Rule 13a-14(a)/15d-14(a) Certifications.
*32 Section 1350 Certifications
* Filed herewith.
32
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: August 9, 2005 By: /s/W. King Grant
------------------------
W. King Grant, Executive Vice President
Principal Financial and Accounting Officer
33