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U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-QSB
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
or
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
Commission File Number 0-6580
[GRAPHIC OMITTED]
PEASE OIL AND GAS COMPANY
(Exact name of small business issuer as specified in its charter)
Nevada 87-0285520
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
751 Horizon Court, Suite 203
Grand Junction, Colorado 81506
(Address of principal executive offices)
(970) 245-5917
(Registrant's telephone number, including area code)
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 past 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No____
As of August 1, 1999 the registrant had 1,688,698 shares of its $0.10
par value Common Stock issued and outstanding.
Transitional Small Business Issuer Disclosure Format (check one):
Yes ____ No X
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<PAGE>
TABLE OF CONTENTS
PAGE
NUMBER
PART I - Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets
June 30, 1999 (unaudited) and December 31, 1998. .. . . . 3
Consolidated Statements of Operations (unaudited)
For the Three and Six Months Ended June 30, 1999
and 1998 . . . . . . . . . . . . . . . . . . . . 4
Consolidated Statements of Cash Flows (unaudited)
For the Three and Six Months Ended June 30, 1999 and 1998 . . 5
Notes to Consolidated Financial Statements . . . . . . . . . . . . 6
Item 2. Management's Discussion and Analysis . . . . . . . . . . . . . 7
Liquidity, Capital Expenditures and Capital Resources . . . . . . 7
Results of Operations . . . . . . . . . . . . . . . . . . . . . . 10
Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Divestment of Rocky Mountain Assets.. . . . . . . . . . . ..10
Total Revenue . . . . . . . . . . . . . . . . . . . . . . . . ..10
Oil and Gas . . . . . . . . . . . . . . . . . . . . . . . . . ..11
Gas Plant, Service and Supply . . . . . . . . . . . . . . . . ..12
Consulting Arrangement - Related Party . . . . . . . . . . . . 12
General and Administrative . . . . . . . . . . . . . . . . . ..13
Depreciation, Depletion and Amortization . . . . . . . . . . ..13
Interest Expense . . . . . . . . . . . . . . . . . . . . . . 13
Impairment Expense - Oil and Gas Properties. . . . . . . . 14
Dividends and Net Loss Per Common Share. . . . . . . . . . 14
Other Matters . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Disclosure Regarding Forward-Looking Statements. . . . . . 14
Year 2000 Issue . . . . . . . . . . . . . . . . . . . . . ..15
PART II - Other Information . . . . . . . . . . . . . . . . . . . . . . . . .16
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 16
Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . 16
Item 3. Defaults Upon Senior Securities . . . . . . . . . . . . . 17
Item 4. Submission of Matters to a Vote of Security Holders . . . 17
Item 5. Other Information . . . . . . . . . . . . . . . . . . . . 17
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . ..17
PART III - Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
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<PAGE>
PART 1 - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
1999 1998
-------------- -------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and equivalents $ 867,161 $ 1,049,582
Trade receivables 321,270 420,460
Prepaid expenses and other 100,838 170,687
Assets held for sale - 100,000
------------- -------------
Total current assets 1,289,269 1,740,729
------------ -------------
OIL AND GAS PROPERTIES, at cost (full cost method):
Unevaluated properties 3,054,482 2,816,475
Costs being amortized 17,040,537 16,834,274
----------- -------------
Total oil and gas properties 20,095,019 19,650,749
Less accumulated amortization (14,419,066) (13,883,174)
------------ -------------
Net oil and gas properties 5,675,953 5,767,575
------------ -------------
OTHER ASSETS:
Debt issuance costs, net 253,433 322,551
Office equipment and vehicles, net 64,540 74,623
Deposits and other 7,493 7,493
------------- --------------
Total other assets 325,466 404,667
------------- -------------
TOTAL ASSETS $ 7,290,688 $ 7,912,971
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 6,065 $ 5,825
Accounts payable, trade 182,358 310,447
Accrued expenses 240,651 322,569
------------- -----------
Total current liabilities 429,074 638,841
------------- -----------
LONG-TERM DEBT, less current maturities: 2,399,799 2,293,261
------------ ----------
STOCKHOLDERS' EQUITY:
Preferred Stock, par value $0.01 per share,
2,000,000 shares authorized, 105,828
and 107,336 shares of Series B 5% PIK
Cumulative Convertible Preferred Stock
issued and outstanding, respectively
(liquidation preference of $5,291,400 at
June 30, 1999) 1,058 1,073
Common Stock, par value $0.10 per share,
4,000,000 shares authorized, 1,688,698
and 1,601,062 shares issued and
outstanding, respectively 168,870 160,106
Additional paid-in capital 37,618,437 37,811,006
Accumulated deficit (33,326,550) (32,991,316)
------------ -------------
Total stockholders' equity 4,461,815 4,980,869
------------ -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 7,290,688 $ 7,912,971
============ ============
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
<TABLE>
<CAPTION>
For The Three Months For The Six Months
Ended June 30, Ended June 30,
-------------------- ------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
REVENUE:
<S> <C> <C> <C> <C>
Oil and gas sales .............................. $ 551,065 $ 655,660 $ 962,859 $ 1,247,268
Gas plant, service and supply .................. -- 152,095 -- 397,363
----------- ----------- ----------- ------------
Total revenue ............................. 551,065 807,755 962,859 1,644,631
----------- ----------- ----------- ------------
OPERATING COSTS AND EXPENSES:
Oil and gas production ......................... 86,958 389,467 171,434 710,107
Gas plant, service and supply .................. -- 177,274 -- 399,013
Consulting agreement-related party ............. -- 62,549 37,750 125,461
General and administrative ..................... 206,357 269,231 386,017 526,886
Depreciation, depletion and amortization ....... 284,614 398,994 547,989 752,131
Impairment expense - oil & gas properties ...... -- 161,000 -- 639,043
----------- ----------- ----------- ------------
Total operating costs and expenses .... 577,929 1,458,515 1,143,190 3,152,641
----------- ----------- ----------- ------------
LOSS FROM OPERATIONS .............................. (26,864) (650,760) (180,331) (1,508,010)
OTHER INCOME (EXPENSES):
Interest and other income ...................... 13,611 82,483 25,008 165,151
Interest expense ............................... (89,981) (269) (179,911) (516)
----------- ----------- ----------- ------------
NET LOSS .......................................... $ (103,234) $ (568,546) $ (335,234) $ (1,343,375)
=========== =========== =========== ============
NET LOSS APPLICABLE TO COMMON
STOCKHOLDERS ................................... $ (169,396) $ (949,587) $ (467,742) $ (2,577,755)
=========== =========== =========== ============
NET LOSS PER COMMON SHARE ......................... $ (0.10) $ (0.60) $ (0.28) $ (1.63)
=========== =========== =========== ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING ...................... 1,688,698 1,580,500 1,657,570 1,579,800
=========== =========== =========== ============
</TABLE>
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
<TABLE>
<CAPTION>
For The Six Months
Ended June 30,
1999 1998
CASH FLOWS FROM OPERATING ACTIVITIES:
<S> <C> <C>
Net loss $ (335,234) $(1,343,375)
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization .......... 547,989 752,131
Impairment expense ................................ -- 639,043
Amortization of debt discount and issuance costs .. 178,786 --
(Gain) Loss on sale of assets ..................... -- (497)
Changes in operating assets and liabilities:
(Increase) decrease in:
Trade receivables ..................... 99,190 261,095
Inventory ............................. -- 55,270
Prepaid expenses and other assets ..... (60) (79,730)
Increase (decrease) in:
Accounts payable ...................... (113,290) (67,853)
Accrued expenses ...................... (81,918) (142,063)
----------- -----------
Net cash provided by (used in) operating activities 295,463 74,021
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment ..... (461,084) (5,417,691)
Proceeds from sale of property and equipment ............... 100,000 987,150
Proceeds from redemption of certificate of deposit ......... 69,910 --
----------- -----------
Net cash provided by (used in) investing activities ..... (291,174) (4,430,541)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of warrants ......................... -- 939
Repayment of long-term debt ................................ (2,889) (3,788)
Payment of Series B Preferred Stock dividends .............. (132,508) (70,833)
Purchase and retirement of Series B Preferred Stock ........ (51,313) --
Offering costs ............................................. -- (146,765)
----------- -----------
Net cash provided by (used in) financing activities ..... (186,710) (220,447)
----------- -----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS .................. (182,421) (4,576,967)
CASH AND EQUIVALENTS, beginning of period .................... 1,049,582 6,547,804
----------- -----------
CASH AND EQUIVALENTS, end of period .......................... $ 867,161 $ 1,970,837
=========== -----------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid for interest ..................................... $ 138,774 $ 199,058
=========== ===========
Cash paid for income taxes ................................. $ -- $ --
=========== ===========
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES:
Increase (decrease) in payables for oil and gas ............ $ (14,805) $ (828,984)
exploration activities
Capitalized portion of amortized debt discount and issuance -- 264,094
costs
Debt incurred for purchase of vehicles ..................... -- 32,610
</TABLE>
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PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1 - Basis of Presentation:
The accompanying unaudited condensed consolidated financial statements have been
prepared in accordance with generally accepted accounting principles for interim
financial information. They do not include all information and notes required by
generally accepted accounting principles for complete financial statements.
However, except as disclosed herein, there has been no material change in the
information disclosed in the notes to consolidated financial statements included
in the Annual Report on Form 10-KSB of Pease Oil and Gas Company (the "Company")
for the year ended December 31, 1998. In the opinion of Management, all
adjustments (consisting of normal recurring accruals) considered necessary for a
fair presentation have been included. Operating results for the periods
presented are not necessarily indicative of the results that may be expected for
the full year.
The accounting policies followed by the Company are set forth in Note 1 to the
Company's financial statements in Form 10- KSB for the year ended December 31,
1998. It is suggested that these financial statements be read in conjunction
with the financial statements and notes included in the Form 10-KSB.
Note 2 - Dividends and Net Loss Per Common Share:
Net loss per common share is computed by dividing the net loss applicable to
common stockholders by the weighted average number of common shares outstanding
during the year. All potential common shares have been excluded from the
computations because their effect would be antidilutive.
The net loss applicable to common stockholders is determined by adding any
dividends accruing to the benefit of the preferred stockholders to the net loss.
The dividends included for this calculation include: 1) paid dividends; 2)
accrued but unpaid dividends; and 3) any imputed dividends attributable to the
beneficial conversion feature. Accordingly, the net loss applicable to common
stockholders includes the following charges associated with the Series B
Preferred Stock that was issued on December 31, 1998:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-------------------------- -----------------------
1999 1998 1999 1998
---------------- ----------- ----------
Dividends declared $ 66,162 $ 70,523 $ 132,508 $ 141,356
Imputed non-cash dividend - 310,518 - 1,093,024
-------- --------- ----------- -----------
Total $ 66,162 $381,041 $ 132,508 $ 1,234,380
======== =========== ========= ===========
The Series B Preferred Stock became convertible into common stock on April 1,
1998 at a conversion price equal to a 12% discount to the average trading price
of the common stock prior to conversion. This discount increased periodically
until it topped out at 25% (this discount is considered a "beneficial conversion
feature"). The additional non-cash imputed dividend charge included in the net
loss applicable to common stockholders represents the intrinsic value of the
discount applicable through the period presented. No additional non-cash
dividend charges will be incurred in future periods since the conversion
discount has previously topped out at 25%. The holders of the Series B Preferred
Stock are entitled to dividends equal to $2.50 per annum, payable quarterly in
cash or additional shares of Series B Preferred Stock at the option of the
Company.
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<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS
Liquidity, Capital Expenditures and Capital Resources
At June 30, 1999, the Company's cash balance was $867,161 with a positive
working capital position of $860,195, compared to a cash balance of $1,049,582
and a positive working capital position of $1,101,888 at December 31, 1998. The
change in the Company's cash balance is summarized as follows:
Cash balance at December 31, 1998 $ 1,049,582
Sources of Cash:
Cash provided by operating activities 295,463
Proceeds from the sale of property and equipment 100,000
Proceeds from redemption of certificate of deposit 69,910
Total Sources of Cash 465,373
Uses of Cash:
Capital expenditures for exploration activities (459,069)
Series B Preferred Stock dividends (132,508)
Purchase and retirement of Series B Preferred Stock (51,313)
Payments on long term debt (2,889)
Capital expenditures for office equipment (2,015)
--------------
Total uses of cash (647,794)
Cash balance at June 30, 1999 $ 867,161
As noted, most of the Company's uses of cash were deployed in exploration
activities in the Gulf Coast which are summarized as follows (the difference
between the total cash paid for exploration activities in the above table and
the amount illustrated below, related to the changes in accounts payable at
December 31, 1998 and June 30, 1999):
<TABLE>
<CAPTION>
PROGRAM OPERATOR
Category NEGX Parallel AHC Other Total %
- ------------------------------------ ------- ---------- --------- ---------- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Successful Wells ................. $ -- $ 29,287 $141,969 $ 1,494 $172,750 38%
Exploratory Dry Holes ............ -- 15,600 -- -- 15,600 2%
Land, G&G Costs on Seismic
Programs ................ 4,123 100,024 -- -- 104,147 26%
Capitalized Interest Costs ....... -- -- -- 137,981 137,981 31%
Other Exploration Costs .......... -- -- -- 13,786 13,786 3%
-------- -------- -------- -------- -------- ----
Total Exploration Costs ... $ 4,123 $144,911 $141,969 $153,261 $444,264 100%
======== ======== ======== ======== ====
Percent ................... 1% 33% 32% 34% 100%
</TABLE>
The anticipated capital requirements for 1999 related to the Company's Gulf
Coast exploration program are more thoroughly discussed in the Company's 1998
Annual Report on Form 10-KSB. There have been no significant changes in the
expected capital requirements as of the date of this report and under the
existing commitments, will be at least $260,000 for the remainder of 1999 and
additional capital requirements will be necessary in 2000 as discussed below.
In 1999 and continuing into 2000, the Company will focus its activities on
cultivating its existing exploration program in the Gulf Coast region,
principally in Louisiana and Texas. This activity will focus on what the Company
considers its three core areas in the Gulf Coast, which are:
1. The East Bayou Sorrel Area in Iberville Parish,
Louisiana, operated by National Energy Group, Inc.
("NEGX");
2. The Maurice Prospect in Fayetteville Parish,
Louisiana, operated by Amerada Hess Corporation
("AHC"); and
3. The Formosa, Texana and Ganado 3-D prospects
encompassing 130,000 acres in and around Jackson
County, Texas, operated by Parallel Petroleum
("Parallel").
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<PAGE>
Under the existing commitments related to these three areas, the following table
summarizes the range of expected capital requirements for the remainder of 1999
by program:
Estimated Investment
Operator Minimum Maximum
East Bayou Sorrel Area $ - $ 400,000
Formosa, Texana, and Ganado Prospects 55,000 355,000
Maurice Prospect 205,000 460,000
---------- -------------
Total $ 260,000 $ 1,215,000
========= ===========
If the above maximum anticipated capital requirements are not required in 1999,
it is expected they will be in 2000. Accordingly, given the potential future
capital requirements for the remainder of 1999 and 2000, the Company's current
and anticipated cash position may not be sufficient to cover the future working
capital and exploration obligations. The Company has vigorously explored various
alternatives for additional sources of capital. However, with the hyper-dilutive
potential of the outstanding Series B Preferred Stock (should the holders elect
to convert into common stock), the Company has been unable to attract additional
equity capital. For example, using the Company's recent common stock price of
$0.50, and applying the applicable discount of 25%, should all the holders of
the Series B Preferred Stock elect to convert into common stock, the Company
would be required to issue approximately 14.1 million shares in the conversion.
This would represent approximately 90% of the then outstanding common shares.
Presently, the Company has only 4.0 million shares of common stock authorized
and is obligated under the terms of the Preferred Stock Agreement to seek
approval of additional authorized shares at its next meeting of stockholders to
allow for conversion should the Preferred stockholders choose to do so. However,
it cannot be determined at this time whether or not additional common shares
will be authorized by the common shareholders and if not, what the consequences
may be.
Two holders of Series B Preferred Stock converted 1,497 shares of Series B
Preferred into 21,584 shares of Common Stock in 1998 and one holder converted
683 shares of Series B Preferred into 87,636 shares of Common Stock in the first
quarter of 1999. In addition, the Company repurchased 4,500 shares of Series B
Preferred from two holders in 1998 for $206,250 and 825 shares of Series B
Preferred from two holders for $51,313 in the first half of 1999. All holders of
Series B Preferred have agreed not to sell or convert outstanding shares of
Series B Preferred until the Carpatsky transaction described below is completed
or until November 15, 1999, whichever is earlier.
In December 1998 National Energy Group, Inc. filed an Involuntary Petition for
an Order and Relief under Chapter 11 of Title 11 of the United States Bankruptcy
Code in United States Bankruptcy Court for the Northern District of Texas,
Dallas Division. As operator of the East Bayou Sorrel field, which yields
approximately 50% of the Company's current production, the bankruptcy petition
might adversely affect future development or operation of the field; however,
the Company does not expect that its interest in the field or production from
currently existing wells will be affected.
The Company does have an unsecured claim in the bankruptcy proceeding for
various amounts which the Company believes were paid to National Energy Group,
Inc. as operator in connection with the drilling of existing wells. Collection
of these amounts may be delayed or may not occur, pending disposition of
National Energy Group, Inc.'s reorganization proceeding.
The total claim is approximately $60,000. However, no receivable has been
recorded in the financial statements as of June 30, 1999.
In addition, the Company has an unsecured claim in the bankruptcy proceeding of
TransTexas, the operator of 3 wells in which the Company owns a small
(approximately 2%) working interest. The amount of the claim is for
approximately $30,000 and is related to the pre-petition undistributed revenue
from production of the wells operated by TransTexas. The Company has been
receiving all of the corresponding post-petition production revenue. The Company
has not provided any allowance for the pre-petition amounts since it anticipates
it will collect the full amount of the receivable which is recorded on the
balance sheet at June 30, 1999.
In September 1998, the Company engaged San Jacinto Securities, Inc. ("SJS"), an
investment banking firm located in Dallas, Texas, to assist the Company in
pursuing various strategic alternatives. Their efforts have focused primarily on
seeking a potential merger candidate for the Company. As a result of their
efforts, the Company signed a letter of intent on May 30, 1999 with Carpatsky
Petroleum, Inc. ("Carpatsky"), a publicly held company traded on the Alberta
Stock Exchange under the symbol "KPY.AL". Carpatsky is engaged in production and
development of oil, gas and condensate in the Republic of Ukraine with proven
reserves much greater than those of the Company's. The transaction is still
conditioned upon, among other things,
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<PAGE>
the preparation and approval of a definitive merger agreement and regulatory and
shareholder approvals. Pursuant to the terms of the proposed merger transaction,
Pease will issue approximately 35 million shares of common stock to acquire all
the outstanding stock of Carpatsky. In addition, all of Pease's currently
outstanding Series B Preferred Stock will be exchanged for approximately 9
million shares of common stock at the close of the transaction. In exchange for
their services, SJS was paid a $150,000 non-refundable cash fee in 1998 and will
receive an additional 3% of the merger value in excess of $5.0 million should it
occur. In addition, should a merger occur, the Company will be obligated to pay
out of its existing working capital approximately $220,000 to the Company's
President/CFO in connection with the severance terms included in his employment
agreement.
The Carpatsky assets consist of interests in two separate fields: 1.) the
Rudovsko-Chervonozavodskoye field (a/k/a the "RC" field) located in the Poltava
District of Eastern Ukraine; and 2.) the Bitkov field located in southwest
Ukraine. In both areas, Carpatsky's planned operations will primarily focus on
exploitation activities -- drilling development wells and performing workovers
on existing wellbores -- in order to monetize proven reserves. Carpatsky has
reported that the 8/8's daily production from the RC field for July 1999 was in
excess of 30 million cubic feet of gas and 120 bbls of condensate from 3 wells.
Two other wells are in the final stages of completion and should be on
production during the third quarter of this year. In addition, one other well is
currently drilling and is expected to reach its proposed target depth of 18,000'
during the fourth quarter of this year. Carpatsky expects four to eight
additional development wells will be drilled in the RC field between now and the
end of 2000. Carpatsky's net revenue interest ("NRI") in the RC field is
approximately 20% as of June 30, 1999. However, pursuant to the terms of the
joint venture agreement, Carpatsky has the right to increase its NRI to 45% by
repaying $6.4 million advanced on its behalf by its joint venture partner. Since
this additional contribution would essentially be purchasing proved producing
reserves, Carpatsky intends making payments to increase its NRI sometime in the
near future. At the Bitkov field, the Carpatsky-Ukrainian joint venture is
producing in excess of 100 Bbls per day and 500-600 Mcf per day. Carpatsky owns
a 45% NRI in this field. A Ukrainian oil and gas agency estimates this field may
have gross reserves in excess of 700 million barrels of oil, of which only 60
million have been produced to date. A study is now underway to determine how
much of the field's reserves can be economically produced and the most efficient
way to do so.
Carpatsky was privately held until 1995 at which time it obtained its listing
through a reverse merger into a Canadian public corporation. Carpatsky, through
its joint ventures, currently employs nine people in Kiev, all of whom are
experienced oil and gas professionals. Les Texas, President and founder, is a
Hungarian born and educated geologist-geophysicist with extensive operational
experience in the US and abroad. In the early 1990's he returned to Eastern
Europe and initiated a dialogue with ranking officials in the Ukrainian energy
sector resulting in the conclusion of two joint venture arrangements and
associated licenses, which now comprise the Carpatsky assets. The relationships
developed by Les Texas within Ukraine's energy industry, combined with
Carpatsky's performance to date, have led the company's Ukrainian partner to
indicate that additional properties may be available sometime in the future.
Carpatsky's other executive personnel include Fred Hofheinz and David Melman.
Fred Hofheinz, a Houston attorney and prominent businessman, has been involved
in the oil and gas industry for more than thirty years. He is a former Mayor of
Houston. David Melman has become affiliated with the company to assist with
corporate finance, re-capitalization and investment banking initiatives and will
be joining Carpatsky as their CEO. Mr. Melman, an attorney, has held several
senior management positions in and served on several Boards of Directors of
publicly traded oil and gas companies. If the proposed merger transaction is
ultimately consummated, the corporate offices will be consolidated in Houston,
Texas and the reconstituted Board of Directors will consist of four members from
Carpatsky and one member from Pease.
If the proposed merger with Carpatsky is ultimately consummated, the newly
combined entity will be required to seek additional financing. For instance,
Carpatsky's capital requirements for drilling and development activities in the
Republic of Ukraine during 1999 and 2000 are expected to range between $5.0 and
$15.0 million (the $15.0 million includes the $6.4 million required to increase
their NRI to 45% in the RC field). Their projects are expected to fund
themselves sometime in 2000 through operating cash flows but exactly when, or
if, this will actually occur cannot be determined at this time. Therefore, the
amount of future capital that will be sought assuming the merger occurs, cannot
be determined at this time, but it can be reasonably assured to be at least $5.0
million. There can be no assurance given at this time that the necessary capital
can or will be raised under terms acceptable to the newly combined entity.
If the contemplated merger with Carpatsky cannot be consummated within a
reasonable period of time, then the Company itself may have to seek additional
financing. However, the Company's common stock was delisted from the Nasdaq
SmallCap electronic market system on January 14, 1999 for failure to maintain an
average bid price of at least $1.00 per share. The
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<PAGE>
stock is now listed on the over-the-counter market on the NASD Bulletin Board
(OTC BB). It is believed that this delisting will have a material negative
impact on the Company's ability to raise additional equity capital. Therefore,
it is unclear at this time what alternatives for future working capital will be
available, or to what extent the potential dilution to the existing shareholders
may be. If additional sources of financing are not ultimately available, the
company may have to consider other alternatives, including the sale of existing
assets, cancellation of existing exploration agreements, nonconsenting on
proposed wells or workovers, farmouts, joint ventures, restructuring under the
protection of the Federal Bankruptcy Laws and/or liquidation.
RESULTS OF OPERATIONS
Overview
The Company's largest source of operating revenue is from the sale of produced
oil, natural gas, and natural gas liquids. Therefore, the level of the Company's
revenues and earnings are affected by prices at which natural gas, oil and
natural gas liquids are sold. Accordingly, the Company's operating results for
any prior period are not necessarily indicative of future operating results
because of the fluctuations in natural gas, oil and natural gas liquid prices
and the lack of predictability of those fluctuations as well as changes in
production levels.
Divestment of Rocky Mountain Assets
As thoroughly discussed in the Company's 1998 Annual Report on Form 10-KSB, the
Company substantially completed the sale of its Rocky Mountain assets in 1998.
Accordingly, the Rocky Mountain revenues, costs, operating margins and cash
flows historically generated and discussed under the captions "Oil and Gas" and
"Gas Plant, Service and Supply" will no longer be part of the Company's future
operations. Since these assets included a significant portion of the Company's
historical operations, the sale of these assets has and will have an immediate
and material negative impact on the Company's future cash flows and results of
operations.
Total Revenue
Total Revenue from all operations was as follows:
For the Three Months Ended June 30,
1999 1998
---------- ----------
Amount % Amount %
Oil and gas sales ................... $ 551,065 100% $ 655,660 81%
Gas plant, service and supply ....... -- -- 152,095 19%
--------- ----- --------- ----
Total revenue .................. $ 551,065 100% $ 807,755 100%
========= ===== ========= ====
For the Six Months Ended June 30,
1999 1998
---------- --------------
Amount % Amount %
Oil and gas sales ................ $ 962,859 100% $1,247,268 76%
Gas plant, service and supply .... -- -- 397,363 24%
---------- ----- ---------- ----
Total revenue ............... $ 962,859 100% $1,644,631 100%
========== ===== ========== ====
The decrease in total revenue, along with any known trends or changes that
effect revenue on a line-by-line basis, are discussed in the following
paragraphs under their respective captions.
-9-
<PAGE>
Oil and Gas
Operating statistics for oil and gas production for the periods presented are as
follows:
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------------- ------------------------------
1999 1998 1999 1998
-------------- ---------- ---------- -----------
Production:
Oil (Bbls)
<S> <C> <C> <C> <C>
Rocky Mtns .................. -- 16,186 -- 34,981
Gulf Coast .................. 18,741 13,778 36,912 23,674
----------- ----------- ----------- -----------
Combined Total ......... 18,741 29,964 36,912 58,655
=========== =========== =========== ===========
Gas (Mcf)
Rocky Mtns .................. -- 72,450 -- 157,417
Gulf Coast .................. 105,696 76,357 213,052 107,312
----------- ----------- ----------- -----------
Combined Total ........ 105,696 148,807 213,052 264,729
=========== =========== =========== ===========
BOE (6:1)
Rocky Mtns .................. -- 28,261 -- 61,217
Gulf Coast .................. 36,357 26,504 72,421 41,559
----------- ----------- ----------- -----------
Combined Total ........ 36,357 54,765 72,421 102,776
=========== =========== =========== ===========
Average Collected Price:
Oil (per Bbl)
Rocky Mtns .................. $ -- $ 11.92 $ -- $ 12.73
Gulf Coast .................. $ 15.79 $ 13.47 13.37 14.02
----------- ----------- ----------- -----------
Combined Average ...... $ 15.79 $ 12.63 $ 13.37 $ 13.25
=========== =========== =========== ===========
Gas (per Mcf)
Rocky Mtns ................. $ -- $ 1.45 $ -- $ 1.44
Gulf Coast ................. $ 2.41 $ 2.26 2.20 2.26
----------- ----------- ----------- -----------
Combined Average ...... $ 2.41 $ 1.86 $ 2.20 $ 1.78
=========== =========== =========== ===========
Per BOE (6:1)
Rocky Mtns ................. $ -- $ 10.54 $ -- $ 10.99
Gulf Coast ................. $ 15.15 $ 13.50 13.30 13.82
----------- ----------- ----------- -----------
Combined Average ...... $ 15.15 $ 11.97 $ 13.30 $ 12.14
=========== =========== =========== ===========
Operating Margins:
Rocky Mtns:
Revenue -
Rocky Mtns. - Oil ....... $ -- $ 192,983 -- $ 445,403
Rocky Mtns. - Gas ....... -- 104,822 -- 227,461
----------- ----------- ----------- -----------
-- 297,805 -- 672,864
Cost ........................ -- (287,993) -- (580,698)
----------- ----------- ----------- -----------
Operating Margin ........ $ -- $ 9,812 -- $ 92,166
=========== =========== =========== ===========
Operating Margin % ...... -- 3% -- 14%
Gulf Coast:
Revenue -
Gulf Coast - Oil ........ $ 295,831 $ 185,535 $ 493,368 $ 331,852
Gulf Coast - Gas ........ 255,234 172,320 469,491 242,552
----------- ----------- ----------- -----------
551,065 357,855 962,859 574,404
Costs ....................... (86,958) (101,474) (171,434) (129,409)
----------- ----------- ----------- -----------
Operating Margin ........ $ 464,107 $ 256,381 $ 791,425 $ 444,995
=========== =========== =========== ===========
Operating Margin % ...... 84% 72% 82% 77%
Combined Totals:
Revenue ..................... $ 551,065 $ 655,660 $ 962,859 $ 1,247,268
Costs ....................... (86,958) (389,467) (171,434) (710,107)
----------- ----------- ----------- -----------
Operating Margin ........ $ 464,107 $ 266,193 $ 791,425 $ 537,161
=========== =========== =========== ===========
Operating Margin % ...... 84% 41% 82% 43%
Production Costs per BOE before DD&A:
Rocky Mtn Region ............ $ -- $ 10.19 $ -- $ 9.49
Gulf Coast Region ........... 2.39 3.83 2.37 3.11
----------- ----------- ----------- -----------
Combined Average ........ $ 2.39 $ 7.11 $ 2.37 $ 6.91
=========== =========== =========== ===========
Change in Revenue
Attributable to:
Production ........................ $ (219,421) $ (379,876)
Price ............................. 114,826 95,467
----------- -----------
Total Decrease in Revenue .......... $ (104,595) $ (284,409)
=========== ===========
</TABLE>
Substantially all of the Company's current oil and gas production is generated
from six of the nine wells in which the Company holds a working interest. Of the
six main producing wells, three are operated by National Energy Group, Inc., and
the other three are operated by Amerada Hess Corporation ("AHC"). All these
wells are deep, high pressure, water driven reservoirs that are inherently laden
with geologic, geophysical, and mechanical risks and uncertainties. The
unexpected loss of any one of these six wells would have a material negative
impact on the Company's estimated reserves, future production and future cash
flows.
In May 1999, the J.P. Owen well located in the Maurice Prospect in Fayetteville
Parish, Louisiana, operated by AHC, began experiencing significant water
production as a result of a very poor primary cement job in the completion
casing. Accordingly, in June 1999 the well was shut in and attempts are
currently underway by AHC to perform reasonable remedial operations to squeeze
the zones to shut off the water source and restore production. Given the nature
of the procedures being undertaken by AHC, the Company believes it is
problematic that the remedial operations will be successful. Should the remedial
operations not be successful, it may have a negative impact on the Company's
future production and cash flows. For instance, the Company's proportionate
share of production from this well totaled 13,360 Mcf of gas and 490 Bbls of oil
for the first six months of 1999, representing approximately 4% (on a BOE basis)
of the Company's total production through June 30, 1999. At December 31, 1998,
this well represented approximately 14.5% of the Company's estimated proven
reserves (PV-10). It is unknown at this time whether or not this well will be
successfully restored to production.
Gas Plant, Service and Supply
As previously discussed, the Company sold these assets in 1998. However, the
historical operating results are as follows:
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------------------- ---------------------------------
1999 1998 1999 1998
---------------- -------------- ------------ --------------
<S> <C> <C> <C> <C>
Revenue $ - $ 152,095 $ - $ 397,363
Costs - (177,274) - (399,013)
----------------- ----------- ------------ ------------
Net Operating Income $ - $ (25,179) $ - $ (1,650)
================ ============ ============ ===========
</TABLE>
Consulting Arrangement - Related Party
In March 1996 the Company entered into a three-year consulting agreement with
Beta Capital Group, Inc. ("Beta") located in Newport Beach, California. Beta's
chairman, Steve Antry, has been a director of the Company since August 1996. The
consulting agreement, which ended in February 1999, provided for minimum monthly
cash payments of $17,500 plus reimbursement for out-of-pocket expenses.
-10-
<PAGE>
General and Administrative
The decrease in general and administrative ("G&A") expenses of $140,869 during
the first half of 1999 when compared to the same period in 1998 is summarized as
follows:
$ 100,289 - Net reduction of payroll costs substantially attributed to the
elimination of administrative positions
30,000 - Legal and accounting.
9,722 - Travel costs.
858 - All other, net.
$ 140,869
The Company has and will take steps to significantly reduce future G&A costs,
and expects "core" G&A costs in 1999 to be approximately $60,000 to $70,000 per
month. However, it is expected additional amounts will be incurred in connection
with the efforts to consummate a merger transaction.
Depreciation, Depletion and Amortization
Depreciation, Depletion and Amortization ("DD&A") for the periods presented by
cost center consisted of the following:
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30 Ended June 30
-------------------------- -----------------------------
1999 1998 1999 1998
----------- --------- ------------ ------------
<S> <C> <C> <C> <C>
Oil and Gas Properties - Gulf Coast $ 278,801 $ 205,469 $ 535,892 $ 339,636
Oil and Gas Properties - Rocky Mtns. - 83,162 - 186,081
Gas Plant, Service and Supply
Operations - 97,136 - 201,095
Furniture and Fixtures 5,813 13,227 12,097 25,319
---------- ----------- ----------- -----------
Total $ 284,614 $ 398,994 $ 547,989 $ 752,131
========= ========== ========== =========
</TABLE>
DD&A for the oil and gas properties, per BOE, for the periods presented is as
follows:
<TABLE>
<S> <C> <C> <C> <C>
Rocky Mountains $ - $ 2.94 $ - $ 3.04
Gulf Coast $ 7.67 $ 7.75 $ 7.40 $ 8.17
Combined Total $ 7.67 $ 5.27 $ 7.40 $ 5.12
</TABLE>
DD&A for the oil and gas properties is computed based on one full cost pool
using the total estimated reserves at the end of each period presented and prior
to applying the ceiling test discussed later in this section under "Impairment
Expense". The estimated portion of DD&A for the Rocky Mountains and the Gulf
Coast are illustrated here for analysis purposes only.
Interest Expense
Total interest incurred, and its allocation, for the periods presented is as
follows:
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------ -----------------------
1999 1998 1999 1998
--------- ----------- --------- ----------
<S> <C> <C> <C> <C>
Interest paid or accrued ...................... $ 69,958 $ 99,372 $ 139,105 $ 197,633
Amortization of debt discount ................. 54,835 80,946 109,669 161,892
Amortization of debt issuance costs ........... 34,559 51,102 69,118 102,203
--------- --------- --------- ---------
Total interest incurred .............. 159,352 231,420 317,892 461,728
Interest capitalized for exploration activities (69,371) (231,151) (137,981) (461,212)
--------- --------- --------- ---------
Interest expense ................ $ 89,981 $ 269 $ 179,911 $ 516
========= ========= ========= =========
</TABLE>
The lower interest incurred in 1999 is substantially attributed to the reduction
of outstanding debt. In connection with the sale of the Rocky Mountain assets in
1998, the Company paid down $1.2 million (or 30%) of the outstanding convertible
debentures. This reduced the outstanding principal from $4.0 million to $2.8
million.
-11-
<PAGE>
Impairment Expense - Oil and Gas Properties
The Company uses the full cost method of accounting for oil and gas activities.
The full cost method regards all costs of acquisition, exploration, and
development activities as being necessary for the ultimate production of
reserves. All of those costs are incurred with the knowledge that many of them
relate to activities that do not result directly in finding and developing
reserves. However, the benefits obtained from the prospects that do prove
successful, together with benefits from past discoveries, may ultimately recover
the costs of all activities, both successful and unsuccessful. Thus, all costs
incurred in those activities are regarded as integral to the acquisition,
discovery, and development of reserves that ultimately result from the efforts
as a whole and are thereby associated with the Company's proved reserves.
Establishing a direct cause-and-effect relationship between costs incurred and
specific reserves discovered, which is the premise under the successful efforts
accounting method, is not relevant to the full cost concept. However, the costs
accumulated in the Company's full cost pool are subject to a "ceiling", as
defined by Regulation SX Rule 4-10(e)(4). As prescribed by the corresponding
accounting standards for full cost, all the accumulated costs in excess of the
ceiling, are to be expensed periodically by a charge to impairment. The Company
incurred an impairment charge of $639,043 during the first six months of 1998 as
a result of costs incurred with dry holes (which increased the accumulated
costs) and the continuing collapse of oil and gas prices between December 31,
1997 and June 30, 1998 that substantially lowered the "ceiling" of the full cost
pool. No impairment charge was recognized during the first half of 1999.
Dividends and Net Loss Per Common Share
Net loss per common share is computed by dividing the net loss applicable to
common stockholders by the weighted average number of common shares outstanding
during the year. All potential common shares have been excluded from the
computations because their effect would be antidilutive.
The net loss applicable to common stockholders is determined by adding any
dividends accruing to the benefit of the preferred stockholders to the net loss.
The dividends included for this calculation include: 1) paid dividends; 2)
accrued but unpaid dividends; and 3) any imputed dividends attributable to the
beneficial conversion feature. Accordingly, the net loss applicable to common
stockholders includes the following charges associated with the Series B
Preferred Stock that was issued on December 31, 1997:
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------- -----------------------
1999 1998 1999 1998
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Dividends declared ............. $ 66,162 $ 70,523 $ 132,508 $ 141,356
Non-cash imputed dividend charge -- 310,518 -- 1,093,024
---------- ---------- ---------- ----------
Total ................. $ 66,162 $ 381,041 $ 132,508 $1,234,380
========== ========== ========== ==========
</TABLE>
The Series B Preferred Stock became convertible into common stock on April 1,
1998 at a conversion price equal to a 12% discount to the average trading price
of the common stock prior to conversion. This discount increased periodically
until it topped out at 25% (this discount is considered a "beneficial conversion
feature"). The additional non-cash imputed dividend charge included in the net
loss applicable to common stockholders represents the intrinsic value of the
discount applicable through the period presented. No additional non-cash imputed
dividend charges will be incurred in future periods since the conversion
discount has previously topped out at 25%. The holders of the Series B Preferred
Stock are entitled to dividends equal to $2.50 per annum, payable quarterly in
cash or additional shares of Series B Preferred Stock at the option of the
Company.
OTHER MATTERS
Disclosure Regarding Forward-Looking Statements
This report on Form 10-QSB includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of historical
facts included in this report, including, without limitation, statements under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" regarding the Company's contemplated merger, financial position,
reserve quantities, plans and objectives of management of the Company for future
operations and capital expenditures, and statements regarding the planned
Carpatsky transactions and the Carpatsky assets are forward-looking statements
and the assumptions upon which such forward-looking statements are based are
-12-
<PAGE>
believed to be reasonable. The Company can give no assurance that such
expectations and assumptions will prove to be correct. Reserve estimates of oil
and gas properties are generally different from the quantities of oil and
natural gas that are ultimately recovered or found. This is particularly true
for estimates applied to exploratory prospects. Additionally, any statements
contained in this report regarding forward-looking statements are subject to
various known and unknown risks, uncertainties and contingencies, many of which
are beyond the control of the Company. Such risks and uncertainties may cause
actual results, performance, achievements or expectations to differ materially
from the anticipated results, performance, achievements or expectations. Factors
that may affect such forward-looking statements include, but are not limited to:
the contemplated merger not be consummated, the Company's ability to generate
additional capital to complete its planned drilling and exploration activities;
risks inherent in oil and gas acquisitions, exploration, drilling, development
and production; price volatility of oil and gas; competition; shortages of
equipment, services and supplies; U.S. and foreign government regulation;
environmental matters; implications to Carpatsky from conducting its operations
in Ukraine and related political and geographical risks; financial condition of
the other companies participating in the exploration, development and production
of oil and gas programs; and other matters beyond the Company's control. In
addition, since all of the prospects in the Gulf Coast are currently operated by
another party, the Company may not be in a position to control costs, safety and
timeliness of work as well as other critical factors affecting a producing well
or exploration and development activities. All written and oral forward- looking
statements attributable to the Company or persons acting on its behalf
subsequent to the date of this report are expressly qualified in their entirety
by this disclosure.
Year 2000 Issue
The Company has conducted a review of its computer systems to identify the
systems that could be affected by the "Year 2000" issue. The Year 2000 problem
is the result of computer programs being written using two digits rather than
four to define the applicable year. Any of the Company's programs that have
time-sensitive software may recognize a date using '00' as the year 1900 rather
than the year 2000. This could result in a major system failure or
miscalculations.
The Company does not believe that the Year 2000 problem will pose a material
operations problem for the Company. The Company's computer software providers
have assured the Company that all of the Company's software is or will be Year
2000 compliant (i.e. will function properly in the year 2000 and beyond). The
Company's accounting software providers have asserted they will provide written
assurance that its products are or will be Year 2000 compliant. To the Company's
knowledge, after investigation, no "imbedded technology" (such as microchips in
an electronic control system) of the Company poses a material Year 2000 problem.
Because the Company believes that it has no material internal Year 2000
problems, the Company has not expended and does not expect to expend a
significant amount of funds to address Year 2000 issues. It is Company policy to
continue to review its suppliers' Year 2000 compliance and require assurance of
Year 2000 compliance from new suppliers; however, such monitoring does not
involve a significant cost to the Company.
The Company is materially dependent on Plains Marketing, L.P. ("Plains"),
National Energy Group, Inc. ("NEG") and Amerada Hess Corporation ("AHC") for the
delivery and payment of the Company's oil and natural gas. These companies in
turn are dependent on various third party vendors for delivery and payment. The
Company has or will request written assurances from Plains, NEG and AHC that
they have examined their Year 2000 issues. However, as of the date of this
report, the Company has not received a response. The Company will continue to
request such assurance but it should be emphasized that no assurance can be
given at this time that Plains, NEG or AHC, or their third party vendors are or
will be Year 2000 compliant. In the event that one or more of the Company's
vendors, including Plains, NEG, AHC and their respective vendors, were to have a
material Year 2000 problem, the Company believes that the foreseeable
consequences would be a temporary delay in revenue collection caused by an
interruption in computerized billing (and not an interruption in the actual flow
of the Company's oil or natural gas), which may have a substantial impact on the
Company's ability to conduct operations. The Company does not have any
contingency plan to address this possibility.
-13-
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The Company may from time to time be involved in various claims, lawsuits,
disputes with third parties, actions involving allegations of discrimination, or
breach of contract incidental to the operation of its business. The Company is
not currently involved in any such incidental litigation which it believes could
have a materially adverse effect on its financial condition or results of
operations.
Item 2. Changes in Securities
(a) and (b): not applicable
(c) Recent sales of unregistered securities. The Company issued and sold
the following securities without registration under the Securities Act
of 1933, as amended ("Securities Act"), during the six months ended
June 30, 1999 and through the date of this Report.
1. On January 28,1999 the Company issued 16,209 shares of its
common stock upon conversion of 200 shares of Series B
Preferred Stock. The Certificates representing the shares
issued upon conversion bear a restrictive legend prohibiting
transfer without registration under the Securities Act or the
availability of an exemption from registration. The shares
issued upon conversion were registered by the Company for
resale by the holders in Registration No. 333-44305. The
Company relied upon Section 3(a)(9) of the Securities Act of
1933, as amended, in claiming exemption from the registration
requirements of the Securities Act for issuance of the
securities upon conversion.
2. On March 1, 1999 the Company issued 30,759 shares of its
common stock upon conversion of 233 shares of Series B
Preferred Stock. The Certificates representing the shares
issued upon conversion bear a restrictive legend prohibiting
transfer without registration under the Securities Act or the
availability of an exemption from registration. The shares
issued upon conversion were registered by the Company for
resale by the holders in Registration No. 333-44305. The
Company relied upon Section 3(a)(9) of the Securities Act of
1933, as amended, in claiming exemption from the registration
requirements of the Securities Act for issuance of the
securities upon conversion.
3. On March 23, 1999 the Company issued 40,668 shares of its
common stock upon conversion of 250 shares of Series B
Preferred Stock. The Certificates representing the shares
issued upon conversion bear a restrictive legend prohibiting
transfer without registration under the Securities Act or the
availability of an exemption from registration. The shares
issued upon conversion were registered by the Company for
resale by the holders in Registration No. 333-44305. The
Company relied upon Section 3(a)(9) of the Securities Act of
1933, as amended, in claiming exemption from the registration
requirements of the Securities Act for issuance of the
securities upon conversion.
In connection with the issuance of the above noted securities, the
Company relied upon Section 4(2) of the Securities Act in claiming
exemption for the registration requirement of the Securities Act. All
of the persons to whom the securities were issued had full information
concerning the business and affairs of the Company and acquired the
shares for investment purposes. Certificates representing the
securities issued bear a restrictive legend and stop transfer
instructions have been entered prohibiting transfer of the securities
except in compliance with applicable securities law.
-14-
<PAGE>
Item 3. Defaults Upon Senior Securities
(a) There has been no material default in the payment of principal,
interest, or any other material default, with respect to any
indebtedness of the small business issuer during the period covered by
this report.
(b) There has been no material default in the payment of dividends for any
class of preferred stock during the period covered by this report.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of Company's security holders during the
period covered by this report.
Item 5. Other Information
There is no information reportable under this item for the period covered by
this report.
Item 6. Exhibits and Reports on Form 8-K
(a) The following exhibits are filed with this report:
(1) Exhibit 27, "Financial Data Schedule" - for the quarter
ended June 30, 1999.
(b) The Company filed the following report on Form 8-K for the period
April 1, 1999 through the date of this report:
Item Reported Date Financial Statements
------------- ---- --------------------
(1) 5 June 4, 1999 None - Not Applicable
SIGNATURES
In accordance with Section 13 or 15 (d) of the Exchange Act, the Registrant
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
PEASE OIL AND GAS COMPANY
Date: August 13, 1999 By: /s/ Patrick J. Duncan
Patrick J. Duncan
President, Chief Financial Officer
and Principal Accounting Officer
-15-
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 867,161
<SECURITIES> 0
<RECEIVABLES> 334,915
<ALLOWANCES> 13,645
<INVENTORY> 0
<CURRENT-ASSETS> 1,289,269
<PP&E> 20,095,019
<DEPRECIATION> 14,419,066
<TOTAL-ASSETS> 7,290,688
<CURRENT-LIABILITIES> 429,074
<BONDS> 2,325,546
0
1,058
<COMMON> 168,870
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 7,290,688
<SALES> 962,859
<TOTAL-REVENUES> 962,859
<CGS> 171,434
<TOTAL-COSTS> 1,143,190
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 179,911
<INCOME-PRETAX> (335,324)
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (467,742)
<EPS-BASIC> (0.28)
<EPS-DILUTED> (0.28)
</TABLE>
