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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 QUARTER ENDED SEPTEMBER 30, 2000
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 November 14, 2000 the registrant had 1,731,398 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>
<CAPTION>
TABLE OF CONTENTS
PAGE
NUMBER
<S> <C>
PART I - Financial Information 3
Item 1. Unaudited Financial Statements 3
Consolidated Balance Sheets as of September 30, 2000
and December 31, 1999 3
Consolidated Statements of Operations For the Three
and Nine Months Ended September 30, 2000 and 1999 4
Consolidated Statements of Cash Flows for the Three
and Nine Months Ended September 30, 2000 and 1999 5
Notes to Consolidated Financial Statements 6-8
Item 2. Management's Discussion and Analysis 9
Liquidity, Capital Expenditures and Capital Resources 9-10
Results of Operations 11
Overview 11
Oil and Gas 11-13
Consulting Arrangement - Related Party 14
General and Administrative 14
Depreciation Depletion and Amortization 15
Interest Expense 15
PART II - Other Information 15
Item 1. Legal Proceedings 15
Item 2. Changes in Securities 16
Item 3. Defaults Upon Senior Securities 16
Item 4. Submission of Matters to a Vote of Security Holders 16
Item 5. Other Information 16
Item 6. Exhibits and Reports on Form 8-K 16
PART III - Signatures 16
</TABLE>
<PAGE>
PART 1- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------ ------------
ASSETS (unaudited)
CURRENT ASSETS:
<S> <C> <C>
Cash and equivalents ......................... $ 1,603,780 $ 724,354
Trade receivables, net ....................... 391,003 402,847
Prepaid expenses and other ................... 61,590 76,349
------------ ------------
Total current assets .................... 2,056,373 1,203,550
------------ ------------
OIL AND GAS PROPERTIES, at cost (full cost method):
Unevaluated properties ....................... 2,436,005 2,281,732
Costs being amortized ........................ 19,124,079 18,278,461
------------ ------------
Total oil and gas properties ............ 21,560,084 20,560,193
Less accumulated amortization ................ (15,616,936) (14,868,287)
------------ ------------
Net oil and gas properties .............. 5,943,148 5,691,906
------------ ------------
OTHER ASSETS:
Office equipment and vehicle ................. 230,624 230,211
Less accumulated depreciation ................ (190,744) (176,013)
------------ ------------
Net office equipment and vehicle ........ 39,880 54,198
Debt issuance costs, net ..................... 80,638 184,315
Deposits and other ........................... 4,995 7,493
------------ ------------
Total other assets ...................... 125,513 246,006
------------ ------------
TOTAL ASSETS ...................................... $ 8,125,034 $ 7,141,462
============ ============
</TABLE>
<TABLE>
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt:
Convertible Debenture, net of
<S> <C> <C>
unamortized discount..................... $ 2,654,554 $ --
Other ................................... 7,285 6,352
Accounts payable, trade ...................... 235,075 140,554
Accrued expenses ............................. 98,266 134,539
------------ ------------
Total current liabilities .......... 2,995,180 281,445
------------ ------------
LONG-TERM DEBT, less current maturities: .......... 10,752 2,506,218
------------ ------------
STOCKHOLDERS' EQUITY:
Preferred Stock, par value $0.01 per share,
2,000,000 shares authorized,
105,828 shares of Series B 5% PIK Cumulative
Convertible Preferred Stock issued and
outstanding (liquidation preference of
$5,577,715 atSeptember 30, 2000) ........... 1,058 1,058
Common Stock, par value $0.10 per share,
4,000,000 shares authorized, 1,731,398
shares issued and outstanding .............. 173,140 173,140
Additional paid-in capital ................... 37,636,191 37,636,191
Accumulated deficit .......................... (32,691,287) (33,456,590)
------------ ------------
Total Stockholders' equity ......... 5,119,102 4,353,799
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ........ $ 8,125,034 $ 7,141,462
============ ============
</TABLE>
-3-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------ ------------------------
2000 1999 2000 1999
---------- ---------- ------------ ----------
REVENUE:
<S> <C> <C> <C> <C>
Oil and gas sales ..............$1,005,474 $ 541,206 $2,633,412 $1,504,065
---------- ---------- ---------- ----------
OPERATING COSTS AND EXPENSES:
Oil and gas production costs ... 79,050 104,580 397,949 276,014
Consulting arrangement-related
party ........................ -- -- -- 37,750
General and administrative ..... 130,950 305,587 476,421 691,605
Depreciation, depletion and
amortization ................. 255,592 250,289 763,380 798,278
---------- --------- ---------- ----------
Total operating costs and
expenses ................ 465,592 660,456 1,637,750 1,803,647
---------- --------- ---------- ----------
INCOME (LOSS) FROM OPERATIONS ....... 539,882 (119,250) 995,662 (299,582)
OTHER INCOME (EXPENSES):
Interest and other income ...... 18,592 8,661 39,359 33,670
Interest expense ............... (89,788) (89,948) (269,718) $ (269,859)
---------- --------- ---------- ----------
NET INCOME (LOSS) ...................$ 468,686 $(200,537) $ 765,303 $ (535,771)
========== ========= ========== ==========
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS ............$ 402,182 $(245,846) $ 567,237 $ (713,588)
========== ========= ========== ==========
BASIC:
Earnings (Loss) Per Share ...... 0.23 $ (0.15) $ 0.33 $ (0.43)
Weighted Average Shares
Outstanding .................. 1,731,398 1,689,600 1,731,398 1,668,400
DILUTED:
Earnings (Loss) Per Share ......$ 0.03 $ (0.15) $ 0.04 $ (0.43)
Weighted Average Shares
Outstanding ....................17,264,316 1,689,600 17,264,316 1,668,400
</TABLE>
-4-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
<TABLE>
<CAPTION>
For the Nine Months
Ended September 30,
-------------------------
2000 1999
---------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES: ...........................$ 765,303 $ (535,771)
Net Income (Loss)
Adjustments to reconcile net loss to net cash provided by (Used in)
operating activities:
Depreciation, depletion and amortization ......... 763,380 798,278
Amortization of debt discount and issuance costs.. 268,181 268,180
Changes in operating assets and liabilities:
(Increase) decrease in:
Trade receivables ...................... 11,844 78,494
Prepaid expenses and other assets ...... 2,257 19,143
Increase (decrease) in:
Accounts payable ....................... (19,974) (93,928)
Accrued expenses ....................... (36,273) (104,323)
---------- -----------
Net cash provided by (used in) operating activities ............ 1,754,718 430,073
---------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment ..... (885,809) (638,597)
Proceeds from redemption of Certificate of Deposit ......... 15,000 100,000
Proceeds from sale of property and equipment ............... -- 70,000
---------- -----------
Net cash provided by (used in) investing
activities .......................................... (870,809) (468,597)
---------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt ................................ (4,483) (4,342)
Payment of Series B Preferred Stock Dividends .............. -- (177,817)
Purchase and retirement of Series B Preferred Stock ........ -- (51,064)
---------- -----------
Net cash provided by (used in) financing
activities .......................................... (4,483) (233,223)
---------- -----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS ..................... 879,426 (271,747)
CASH AND EQUIVALENTS, beginning of period ....................... 724,354 1,049,582
---------- -----------
CASH AND EQUIVALENTS, end of period .............................$1,603,780 $ 777,835
========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest .....................................$ 209,846 $ 209,795
========== ===========
Cash paid for income taxes .................................$ -- $ --
========== ===========
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND
FINANCING ACTIVITIES:
Increase (decrease) in payables for oil & gas
exploration activities ...................................$ 114,497 $ (10,342)
========== ===========
</TABLE>
-5-
<PAGE>
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 our Annual Report on Form 10-KSB for the year ended December 31, 1999. In our
opinion, 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 we followed are set forth in Note 1 to our financial
statements in Form 10-KSB for the year ended December 31, 1999. We suggest that
these financial statements be read in conjunction with the financial statements
and notes included in the Form 10-KSB.
Note 2 - Recent Developments
On November 8, 2000 Pease Oil and Gas Company announced that its proposed merger
with Carpatsky Petroleum, Inc. ("Carpatsky") had been terminated. Concurrently,
the Company also exchanged its outstanding Series B Convertible Preferred Stock
for a new series of Preferred to eliminate the Series B's hyper-dilutive "death
spiral" conversion feature.
Under terms of the Termination Agreement, Carpatsky paid the Company $80,000 in
cash for certain accounting and administrative services provided to Carpatsky by
the Company since October 1, 1999; will issue 1.5 million shares of Carpatsky
restricted common stock on or before January 31, 2001; and both companies
exchanged broad general releases.
The Company agreed to terminate the proposed merger with Carpatsky for several
reasons, including but not limited to:
o it did not appear that the transaction could be completed in the near
future without unreasonable effort and expense;
o several of the issues that are key to Carpatsky's ultimate value remain
uncertain; and
o recent successful drilling in Jackson County, Texas (combined with
further processing of the seismic data) indicate that the value of our
12.5% working interest in the 130,000 acre 3-D seismic prospect may be
worth significantly more than the value attributed to Pease in the
proposed Carpatsky merger.
These circumstances, combined with the willingness of the Series B Preferred
Stockholders to restructure their investment, led the Board of Directors to
believe that it was in the best interest of the Company to terminate the merger
at that time.
Under its original terms, the Series B Preferred Stock was convertible into
common stock at a 25% discount to the market price. This discount market feature
became hyper-dilutive when the common stock price decreased beginning shortly
after its issuance in December 1997. Based on the price of the common stock on
September 30, 2000 ($.4844 per share) the outstanding Series B could have been
converted into approximately 15.5 million shares of common, or over 95% of the
common equity after a conversion. Under the terms associated with the Carpatsky
merger, the Series B Preferred Stockholders were to receive approximately 10% of
the merged entity. In either case, the Pease common stockholders would have been
left with very little ownership in the Company. In addition, it became difficult
to value the common stock because the capital structure was so uncertain. Given
these circumstances, the Board of Directors determined that the Series B
Preferred stock would have to be replaced or restructured in conjunction with
terminating the merger.
-6-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Therefore, six institutional holders of approximately 94% of the Series B
Preferred stock, representing a stated value of over $4.97 million, exchanged
the Series B for a new class of non-voting, non-convertible, preferred stock
known as the "Series C" Preferred stock. The new Series C Preferred must be
redeemed, at its stated value, on December 31, 2005. However, the Company may,
at its election, redeem the Series C at a 331/3% discount (or approximately
$3.13 million if all of it is redeemed), either in whole or in part, through
December 31, 2003. We redeemed the remaining 6% of the Series B at a 331/3%
discount, or $210,833. Therefore, as of the date of this report, there is no
outstanding hyper-dilutive Series B Preferred Stock.
The Series C will pay dividends at 5% per annum starting in the second quarter
of 2001. The Company has not paid any dividends on the Series B Preferred stock
since September 1, 1999 (when the Plan of Merger was signed with Carpatsky). In
connection with this restructuring, all the holders of the Series B Preferred
stock have waived all the dividends in arrears.
As an inducement for the Series B Preferred stockholders to restructure their
investment and grant a discounted redemption feature, the Company issued
warrants to acquire up to 1,763,800 shares of common stock exercisable at $0.50
per share. These warrants will expire on December 31, 2003. The Company does not
expect the non-cash charge associated with the fair value of these warrants to
have a significant impact on the results of operations in the fourth quarter of
2000 since it will be offset by the dividends waived, and the discount on the
Series B preferred stock that was redeemed. These items will be reflected as
adjustments to net income to determine the net income available to the common
stockholders.
In conjunction with the restructuring of the outstanding preferred stock and the
termination of the merger with Carpatsky, the Board of Directors approved an
amended employment agreement for Patrick J. Duncan, the Company's President and
CFO. The amended terms of the agreement, which became effective November 2,
2000, include provisions for: 1) a $50,000 cash bonus; 2) the issuance of
150,000 shares of restricted common stock; and a warrant to purchase up to
600,000 shares of the Company's common stock at $0.50 per share, exercisable at
the earlier of: (a) December 31, 2004; or (b)(i) as to 300,000 shares, if the
Company's reported closing sales price for its common stock is at least $1.50
for at least 80% of the trading days in a one month period, and (ii) as to other
300,000 shares, if the Company's reported closing sales price for its common
stock is at least $2.00 for at least 80% of the trading days in a three month
period. In addition, the warrants would become exercisable if the Company enters
into a reorganization or merger transaction in which the deemed or actual value
received by the Company was equal to or greater than $1.50 per share. In
consideration for the cash bonus, Mr. Duncan agreed to reduce his total
severance due upon change of control from $197,500 to $150,000.
For financial statement reporting purposes, in addition to the cash bonus, the
Company will recognize a non-cash charge in the fourth quarter of $60,900 which
represents the fair value of the 150,000 common shares on the date of grant (or
$.40625 per share). There will be no financial statement impact for the warrants
issued since the exercise price was 18.75% higher than the market price on the
date of grant.
Note 3 - Net Income (Loss) Available to Common Stockholders
The net income available to common stockholders is determined by including any
dividends accruing to the benefit of the preferred stockholders to the net
income. Accordingly, a reconciliation of net income available to common
stockholders is as follows:
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
---------------------- ----------------------
2000 1999 2000 1999
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Net Income (Loss) ....................... $ 468,686 $(200,537) $ 765,303 $(535,771)
Dividends declared and paid
for the Series B Preferred Stock ... -- (45,309) -- (177,817)
Dividends in Arrears for the Series
B Preferred Stock .................. (66,504) -- (198,066) --
--------- --------- --------- ---------
Net Income (Loss) available to
common stockholders $ 402,182 $(245,846) $ 567,237 $(713,588)
========= ========= ========= =========
</TABLE>
-7-
<PAGE>
The dividends in arrears at September 30, 2000 have been included for purposes
of determining the net income available to common stockholders for the periods
presented, even though they were subsequently waived in connection with the
preferred stock restructuring discussed in Note 2.
Note 4 - Earnings Per Common Share
The Company follows SFAS No. 128 "Earnings Per Share". Accordingly, "basic"
earnings per common share is computed by dividing income available to common
stockholders (the "numerator") by the weighted-average number of common shares
outstanding (the "denominator") during the periods presented. "Diluted" earnings
per common share reflects the potential dilution that could occur if securities
or other contracts to issue common stock were exercised or converted into common
stock. A reconciliation of the components of basic and diluted net income per
common share for the periods presented is as follows:
<TABLE>
<CAPTION>
For the Three Months Ended September 30,
---------------------------------------------------------------
2000 1999
--------------------------- ------------------------------
Per Per
BASIC Income Shares Share Income Shares Share
-------- --------- ----- --------- --------- ------
Income (Loss) available to common
<S> <C> <C> <C> <C> <C> <C>
stockholders $402,182 1,731,398 $0.23 $(245,846) 1,689,600 $(0.15)
EFFECT OF DILUTIVE SECURITIES
Assumes the Series B Preferred
stock was converted under
its original terms 66,504 15,532,918 (0.20) - - -
-------- ---------- ----- --------- --------- ------
DILUTED
Income (Loss) available to common
stock including assumed
conversions $468,686 17,264,316 $0.03 $(245,846) 1,689,600 $(0.15)
======== ========== ===== ========= ========= ======
</TABLE>
<TABLE>
<CAPTION>
For the Nine Months Ended September 30,
----------------------------------------------------------------
2000 1999
--------------------------- -------------------------------
Per Per
BASIC Income Shares Share Income Shares Share
-------- --------- ----- --------- --------- ------
Income (Loss) available to common
<S> <C> <C> <C> <C> <C> <C>
stockholders $567,237 1,731,398 $0.33 $(713,588) 1,668,400 $(0.43)
EFFECT OF DILUTIVE SECURITIES
Assumes the Series B Preferred
stock was converted under
its original terms 198,066 15,532,918 (0.29) - - -
-------- ---------- ----- --------- --------- ------
DILUTED
Income (Loss) available to common
stock including assumed
conversions of Series B $765,303 17,264,316 $0.04 $(713,588) 1,668,400 $(0.43)
======== ========== ===== ========= ========= ======
</TABLE>
For the three and nine months ending September 30, 2000, the "diluted" earnings
per common share assumes that the Series B preferred stock, which was
restructured in November 2000, was converted under its original terms using a
conversion price of $0.3633 per share (this represents the price the Series B
preferred stock could have converted into using the market price of the common
stock on September 30, 2000). "Diluted" earnings per share for all the periods
presented in 1999, is identical to the "basic" earnings per share for the same
period since the affects of including any potential common shares would have
been antidilutive.
Although management believes that the above presentation of earnings per
share adheres to the authoritative accounting and reporting guidelines, they do
not believe that it is representative of the results that would have occurred
using the capital structure as it exists today. As of the date of this report,
the total number of fully diluted potential common shares, including the
1,763,800 shares underlying the warrants issued to the preferred stockholders in
connection with the restructuring, is approximately 4.0 million shares. The
earnings per share, as presented, illustrates the hyper-dilutive potential that
the Series B Preferred stock had before it was restructured but does not, in
managements opinion, accurately reflect the economic results benefiting the
common stock as a result of the restructured capital.
-8-
<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS
---------------------------------------------
Liquidity, Capital Expenditures and Capital Resources
At September 30, 2000, our cash balance was $1,603,780 with a negative working
capital position of $938,807, compared to a cash balance of $724,354 and a
positive working capital position of $922,105 at December 31, 1999. The change
in our working capital position can be attributed to the reclassification of our
convertible debentures, with a balance of $2.8 million, from a long-term
liability to a current liability during the second quarter of 2000 since they
become due on April 15, 2001. The change in our cash balance is summarized as
follows:
<TABLE>
<CAPTION>
<S> <C>
Cash balance at December 31, 1999 .............................. $ 724,354
-----------
Sources of Cash:
Cash provided by operating activities ...................... 1,754,718
Proceeds from the redemption of certificate of deposit ..... 15,000
-----------
Total sources of cash ................................. 1,769,718
Uses of Cash:
Capital expenditures for exploration activities ............ (885,395)
Repayment of long term debt ................................ (4,483)
Other capital expenditures ................................. (414)
-----------
Total uses of cash .................................... (890,292)
-----------
Cash balance at September 30, 2000 ............................. $ 1,603,780
===========
</TABLE>
We were able to generate positive cash flow from operating activities of
$1,754,718 during the first nine months of 2000 principally due to the favorable
oil and gas prices being enjoyed this year. For the first nine months of 2000,
the average prices received by the Company have been $28.70 per bbl of oil and
$3.84 per Mcf of gas. In addition, we have been able to reduce our overall
operating costs and expenses, including substantial reductions in general and
administrative costs, when compared to prior periods. Our operations are
discussed more thoroughly later in this section under the caption "Results of
Operations". However, assuming the price of oil and gas as of the date of this
report and our current production levels remain unchanged or improve, we can
expect to continue generating positive cash flow from operations for the
foreseeable future.
As far as our uses of cash, the following table presents the costs incurred for
our exploration activities for the first nine months of 2000 (the $114,497
difference between the total cash paid for exploration activities in the above
table and the amount presented below, represents the net increase in accounts
payable for the exploration activities between December 31, 1999 and September
30, 2000):
<TABLE>
<CAPTION>
PROGRAM OPERATOR
-------------------------------- Internal
NEG Parallel AHC Costs Total %
Category: -------- -------- -------- -------- -------- ---------
Evaluated Costs -
<S> <C> <C> <C> <C> <C> <C>
Productive Efforts ...... $ 66,325 $220,313 $117,864 $ -- $404,502 40%
Exploratory Dry Holes ... -- 56,079 -- -- 56,079 6%
Other Exploration Costs . -- -- -- 10,699 10,699 1%
-------- -------- -------- --------
Subtotal ........... 66,325 276,392 117,864 10,699 471,280 47%
Unevaluated Costs -
Land, G&G and Seismic ... 6,583 310,495 3,227 -- 320,305 32%
Capitalized Interest .... -- -- -- 208,307 208,307 21%
-------- -------- -------- -------- -------- ---------
Total .............. $ 72,908 $586,887 $121,091 $219,006 $999,892 100%
======== ======== ======== ======== ======== =========
Percent ............ 7% 59% 12% 22% 100%
</TABLE>
-9-
<PAGE>
A description of the areas we have an oil and gas interest in are more
thoroughly discussed in our 1999 Annual Report on Form 10-KSB. There have been
no significant changes in our areas of operation since the date of that report.
Since we are a non-operator in all of the areas in which we hold an oil and gas
interest, we do not necessarily control the timing of any development or
exploration activities and therefore have little control over the corresponding
required cash outlays. However, we currently expect the expenditures that will
be proposed by the respective operators of our core areas to be within the
following ranges through the second quarter of 2001:
<TABLE>
<CAPTION>
Estimated Investment
Area Operator Minimum Maximum
--------------------------- --------------------------- --------- ----------
East Bayou Sorrel National Energy Group, Inc.
<S> <C> <C> <C>
("NEG") $ 100,000 $ 150,000
Formosa, Texana, and Ganado Parallel Petroleum, Inc.
("Parallel") 500,000 1,500,000
Maurice Prospect Amerada Hess Corporation
("AHC") 350,000 500,000
-------- ----------
Total $950,000 $2,150,000
======== ==========
</TABLE>
Therefore, based on the potential capital that may be required for our future
exploration activities, compounded with the fact that our convertible
debentures, with a current outstanding balance of $2,782,500, will become due
and payable on April 15, 2001, we do not believe, as of the date of this report,
that our current and anticipated cash position will be sufficient to cover all
of the future working capital, debt service and exploration obligations.
Accordingly, we will have to attempt to restructure our outstanding convertible
debentures and possibly seek additional financing. Regarding additional
financing, our common stock is now listed on the over-the-counter market on the
NASD Bulletin Board (OTC BB). It is believed that being a Bulletin Board listed
company will impair our ability to raise additional equity capital. Therefore,
it is unclear at this time what alternatives for future working capital will be
available, whether or not an amicable restructuring of the convertible debt can
or will be accomplished, or to what extent the potential dilution to the
existing shareholders may be under either scenario. If additional sources of
financing are not ultimately available and/or we cannot satisfactorily
restructure our convertible debentures, we will have to consider other
alternatives, including the sale of existing assets, canceling existing
exploration agreements, farming out part or all of our prospect inventory,
pursuing joint ventures, or formal restructuring under the protection of the
Federal Bankruptcy Laws.
-10-
<PAGE>
RESULTS OF OPERATIONS
---------------------
Overview
Our largest source of operating revenue is from the sale of produced oil,
natural gas, and natural gas liquids. Therefore, the level of our revenues and
earnings are affected by prices at which natural gas, oil and natural gas
liquids are sold. Therefore, our operating results for any prior period are not
necessarily indicative of future operating results because of the fluctuations
in price and production levels.
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 Nine Months
Ended September 30, Ended September 30,
--------------------- -----------------------
2000 1999 2000 1999
Production: --------- --------- ---------- ----------
<S> <C> <C> <C> <C>
Oil (bbl) .................. 21,200 16,900 67,100 53,800
Gas (Mcf) .................. 81,800 68,500 183,800 281,500
BOE (6:1) .................. 34,900 28,300 97,800 100,700
Average Collected Price:
Oil (per bbl) ..............$ 30.36 $ 20.30 $ 28.70 $ 15.54
Gas (per Mcf) .............. 4.42 2.89 3.84 2.37
Per BOE (6:1) .............. 28.81 19.11 26.93 14.93
Operating Margins;
Revenue -
Oil ......................$ 643,788 $ 343,201 $1,927,011 $ 836,569
Gas ...................... 361,686 198,005 706,401 667,496
--------- --------- ---------- ----------
Total Revenue ..........1,005,474 541,206 2,633,412 1,504,065
Costs
Lifting Costs ............ (67,309) (50,378) (208,086) (134,761)
Production taxes ......... (11,741) (54,202) (189,863) (141,253)
--------- --------- ---------- ----------
Total Costs ........... (79,050) (104,580) (397,949) (276,014)
--------- --------- ---------- ----------
Operating Margin .........$ 926,424 $ 436,626 $2,235,463 $1,228,051
========= ========= =========== ==========
Operating Margin Percent 92% 81% 85% 82%
Production Costs per BOE
before DD&A ................$ 2.27 $ 3.70 $ 4.07 $ 2.74
Change in Revenue Attributable
to:
Production ...............$ 126,528 $ (24,254)
Price .................... 337,740 1,153,601
--------- -----------
Total Increase in Revenue ....$ 464,268 $ 1,129,347
========= ===========
</TABLE>
Discoveries in 2000
This year through September 30, we have participated in the drilling of
four exploratory wells, all located in or around Jackson County, Texas,
within the prospect areas operated by Parallel. Of these four wells,
three were productive and one was dry. All three of the wells completed
this year didn't begin producing until mid- September 2000 and
contributed approximately 7,000 Mcf of the third quarters production. As
of October 31, 2000, these three wells were producing, on an 8/8's
basis, approximately 6,040 Mcf of gas per day and 145 bbls of condensate
per day (representing approximately 566 Mcf of gas per day and 14 bbls
of condensate per day net to the Company). We own approximately a 12.5%
working interest in all of these wells.
-11-
<PAGE>
Another well located in the Ganado prospect area was drilled to a total
depth of 7,460ft in November 2000 and the log indicated probable
production from 34ft of sand in three separate zones and 8ft of oil in
one zone. Although it is unknown at this time whether or not this well
will be commercially productive, and if so at what rates, it will be
dual completed during the 4th quarter of 2000. We own a 12.6% working
interest in this well.
Comparison of Oil and Gas Production for the Three Months Ended September 30,
2000 & 1999:
Oil - The 4,300 bbl increase in oil production for the three months
ended September 30, 2000, when compared to the same period in 1999, is
primarily attributable to increased production realized by the Company
in 2000 from the wells located in the East Bayou Sorrel field, operated
by NEG. The increase in production realized by the Company is not
attributable to an overall increase in the 8/8's production from the
wells, but rather an increased interest in the respective wells. On
November 15, 1999, the prospect "paid out" and pursuant to the terms of
our after prospect payout agreement, our working interest in these wells
increased from 8.9% to 15.6% giving us more of the overall 8/8's
production subsequent to that date.
Gas - The 13,300 Mcf increase in gas production realized by the Company
for the three months ended September 30, 2000, when compared to the same
period in 1999, is primarily attributable to the fact that we recorded a
one time "catch-up" credit of approximately 25,000 Mcf during the third
quarter of 2000 for production from the wells located in the Maurice
field, operated by AHC. This production adjustment reflects an increase
in our net revenue interest resulting from an amended Division Order,
the document that itemizes all the owners interest in producing well
units. Prior to September 2000, the revenue and production had been paid
and accrued based on a preliminary Division Order provided to us by AHC.
Because of several unresolved issues related to certain farm-outs,
unitizations and other matters that could have affected the interests,
the original Division Order was prepared on a "worst-case" scenario
pending the resolution of the outstanding issues. AHC resolved the
outstanding issues and informed us in the third quarter of 2000 of our
new net revenue interests. Accordingly, this adjustment reflects the
incremental production from prior periods based on the new Division
Order. The increase in the net revenue interests varied on a
well-by-well basis and ranged from .02% to .09%. Our working interest in
the various wells in the Maurice field ranges from 6.0% to 8.4%.
Comparison of Oil and Gas Revenue for the Three Months Ended September 30, 2000
& 1999:
Oil and gas revenue for the three months ended September 30, 2000, when
compared to the same period in 1999, increased by $489,798. This
increase is attributed to: a) the substantially higher prices received
for the oil and gas in 2000. We received an average price of $30.32 per
bbl of oil during the third quarter of 2000 compared to $20.30 per bbl
for the same period in 1999 - representing a $10.02 per bbl, or 49%
increase, in 2000. We received an average price of $4.42 per Mcf of gas
during the third quarter of 2000 compared to $2.89 for the same period
in 1999 - representing a $1.53, or 53% increase, in 2000; and b) in
connection with the one time "catch-up" production adjustment discussed
in the previous paragraph for the wells located in the Maurice field, we
recorded incremental revenue totaling $100,533 (consisting of $17,692
for oil and $82,841 for gas).
Comparison of Oil and Gas Costs for the Three Months Ended September 30, 2000 &
1999:
Lifting Costs - The lifting costs increased $16,931 during the third
quarter of 2000, when compared to the same period in 1999, primarily
because of: a) increased water production from the three wells at East
Bayou Sorrel. Water disposal fees on an 8/8's basis are charge at a rate
of $0.57 per bbl. The average 8/8's water produced from these wells
during the third quarter of 2000 was 3,776 bbls per day compared to
2,473 bbls per day during the same period in 1999; and b) the increased
lifting costs from three additional discovery wells located in Jackson
County, Texas that were put on line during the third quarter 2000.
Production Taxes - The production taxes decreased $42,461 during the
third quarter of 2000 when compared to the same period in 1999 primarily
because of a one time credit on accrued but unpaid taxes was received
from the State of Louisiana (through AHC, the operator) in the amount of
$59,848 for severance tax relief associated with the wells located in
the Maurice field. Without this one time credit to offset the third
quarters production taxes in 2000, the overall costs incurred would have
been higher when compared to the same period in 1999 because a
substantial portion of the production taxes are based on the revenue
generated and not on the volume produced.
-12-
<PAGE>
Comparison of Oil and Gas Production for the Nine Months Ended September 30,
2000 & 1999:
Oil - The 13,300 bbl increase in oil production for the nine months
ended September 30, 2000, when compared to the same period in 1999, is
primarily attributable to increased production realized by the Company
from the wells located in the East Bayou Sorrel field, operated by NEG.
The increase in production realized by the Company, is not attributable
to an overall increase in the 8/8's production from the wells, but
rather an increased interest in the respective wells. On November 15,
1999, the prospect "paid out" and pursuant to the terms of our after
prospect payout agreement, our working interest in these wells increased
from 8.9% to 15.6% giving us more of the overall 8/8's production
subsequent to that date.
Gas - The 97,700 Mcf decrease in gas production for the nine months
ended September 30, 2000, when compared to the same period in 1999, is
primarily attributable to the Maurice field operations, which is
operated by AHC, where: a) we have experienced the natural decline of
production inherent in oil and gas operations; and b) the loss of one
well in September 1999 due to down-hole mechanical problems.
Comparison of Oil and Gas Revenue for the Nine Months Ended September 30, 2000 &
1999:
Oil and gas revenue for the nine months ended September 30, 2000, when
compared to the same period in 1999, increased over $1.1 million. As the
data in the above table illustrates, this increase is substantially
attributed to the substantially higher prices received for the oil and
gas in 2000. We received an average price of $28.70 per bbl of oil
during the first nine months of 2000 compared to $15.54 per bbl for the
same period in 1999 - representing a $13.16 per bbl, or 85% increase, in
2000. We received an average price of $3.84 per Mcf of gas during the
first nine months of 2000 compared to $2.37 for the same period in 1999
representing a $1.47, or 62% increase, in 2000.
Comparison of Oil and Gas Costs for the Nine Months Ended September 30, 2000 &
1999:
Lifting Costs - The lifting costs increased $73,325 during the first
nine months of 2000 when compared to the same period in 1999 primarily
because of: a) increased water production from the three wells at East
Bayou Sorrel. Water disposal fees on an 8/8's basis are charge at a rate
of $0.57 per bbl. The average 8/8's water produced from these wells
during the first nine months of 2000 was 3,508 bbls per day compared to
2,107 bbls per day during the same period in 1999; and b) the increased
lifting costs from three additional discovery wells located in Jackson
County, Texas that were put on line during the third quarter 2000.
Production Taxes - The production taxes increased $48,610 during the
first nine months of 2000 when compared to the same period in 1999
primarily because a substantial portion of the production taxes are
based on the revenue generated and not on the volume produced.
Accordingly, the higher prices received for oil and gas in 2000 have
increased the production taxes.
Exploration Outlook:
An exploratory well in the Maurice prospect located in Lafayette Parish,
Louisiana, operated by AHC, commenced drilling operations in October
2000 targeting the Lower Bol Mex at a planned measured depth of 17,500
ft. It is anticipated that this well, in which we own a 8.2% working
interest, will reach its total depth near the end of this year.
In addition, we will continue to exploit our assets within the Jackson
County, Texas area where we expect as many as twelve (12) Frio and Yegua
prospects may be proposed over the next six to nine months, depending on
weather and rig availability.
Parallel has also announced that a Regional Study of the Wilcox trend
(examining depths between 10,000' and 14,000' below the surface), has
recently been completed, where at least twelve (12) Wilcox prospects
covering approximately 25,000 acres have been identified. Although the
8/8's costs to drill a Wilcox objective is between $3.0 and $4.0
million, and there is a higher degree of risk associated with depth and
reservoir quality, Parallel believes the reserve potential is
considerable. Within the Regional Wilcox Study, at least four (4) of the
identified prospects are covered, either in whole or in part, within the
Texana Area of Mutual Interest (the "Texana AMI") where we have a 12.5%
working interest. The total acreage within the Texana
-13-
<PAGE>
AMI for the identified Wilcox prospects is over 6,000 acres and we have
recently acquired substantially all of our proportionate share of the
corresponding leases (with terms of two or three years). This Regional
Wilcox study, as it relates to the Texana AMI, appears extremely
attractive based on the preliminary studies and may provide our Company
with new opportunities in the future.
Cautionary Outlook:
Approximately 80% of our production for the first nine months of 2000,
on a BOE basis, was produced from the three wells located at East Bayou
Sorrel. Of that, 57% of the production, on a BOE basis, was produced
from the Schwing # 1 which averaged, on an 8/8's basis, 1,260 bbls of
oil per day and 1,270 Mcf per day for the first nine months of 2000. In
September 2000, sand began showing up in the production fluids in the
Schwing # 1. NEG, the operator of the well, believes this may be
formation sand and that the situation could possibly be corrected with
remedial procedures (eg. with a gravel pack or similar operation) as
soon as a work-over rig becomes available. However, NEG has informed us
that a work-over rig may not be available until January 2001. Therefore,
in order to mitigate the sand, NEG cut the production rate back in
October 2000 to approximately 500 bbls per day and 550 Mcf per day. At
this level, the sand in the production fluids, has been at an acceptable
level through the date of this report. However, it can not be determined
at this time whether or not this will be the case for the indefinite
future. If not, the already reduced production levels may have to be
lowered even further or the well may have to be shut-in alltogether.
Once a work-over rig is available, NEG is confident that the well can be
restored to full production. However, at this time there can be no
assurance when the remedial procedures will be performed or if they will
ultimately be successful.
Most of the average daily production lost from Schwing # 1, on an
equivalent units basis, has been replaced by the recent discoveries in
Jackson County, Texas that were previously discussed. Therefore, absent
any unforeseen circumstances, we do not expect our average daily
production for the fourth quarter, on an equivalent units basis, to be
lower than the average daily production reported for the first nine
months of 2000 (excluding the one time adjustment for the wells in the
Maurice field). However, any unexpected loss of production from one of
the new discoveries, further reductions of the production from any of
the wells in East Bayou Sorrel, and/or if the planned remedial
procedures on the Schwing # 1 are not ultimately successful, could have
a material negative impact on our estimated reserves, future production
and future cash flows.
Consulting Arrangement - Related Party
In March 1996 the Company entered into a three-year consulting agreement with
Beta Capital Group, Inc. ("BCG") located in Newport Beach, California. BCG's
chairman, Steve Antry, has been a director of Pease since August 1996. The
Consulting agreement provided for minimum monthly cash payments of $17,500 plus
reimbursement for out-of-pocket expenses. Stephen Fischer, an independent
contractor for BCG, is also a member of our Board of directors. Messrs. Antry
and Fischer are also principals of Beta Oil & Gas, Inc., a publicly held oil and
gas company located in Tulsa, Oklahoma. We have not incurred any costs
associated with this consulting agreement since its expiration in February 1999.
General and Administrative
General and administrative ("G&A") expenses decreased: i) $174,638 during the
third quarter of 2000 when compared to the same period in 1999; and ii) $215,184
during the first nine months of 2000 when compared to the same period in 1999.
These decreases are attributable to an overall effort initiated in the fourth
quarter of 1998 to substantially reduce G&A costs. Actions taken included
reducing personnel, limiting travel, eliminating unnecessary administrative
services and only utilizing consultants on an as needed basis. In addition, the
costs incurred in connection with the efforts to consummate the merger with
Carpatsky were: i) $88,237 less for the three months ended September 30, 2000
when compared to the same period in 1999; and ii) $33,695 less for the nine
months ended September 30, 2000 when compared to the same period in 1999. The
following table presents the merger costs that are included in our G&A during
the periods presented:
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
---------------------------- -----------------------------
2000 1999 2000 1999
--------- --------- ---------- ----------
<S> <C> <C> <C> <C>
$ 14,489 $ 102,726 $ 89,444 $ 123,139
</TABLE>
We expect "core" G&A expenses for the foreseeable future to be between $40,000
to $50,000 per month.
-14-
<PAGE>
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 Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
2000 1999 2000 1999
--------- --------- -------- --------
<S> <C> <C> <C> <C>
Oil and Gas Properties .............. $ 250,695 $ 245,007 $748,649 $780,899
Furniture, Fixtures and Equipment ... 4,898 5,283 14,732 17,380
--------- --------- -------- --------
Total .......................... $ 255,593 $250,290 $763,381 $798,279
========= ========= ======== ========
DD&A for the oil and gas properties,
per BOE: ................................. $ 7.19 $ 8.66 $ 7.66 $ 7.75
========= ========= ======== ========
</TABLE>
The DD&A for oil and gas properties is computed using the units-of-production
method utilizing only proved reserves at the end of the respective period. Even
though there hasn't been a significant difference in the total amount of DD&A
for oil and gas properties between the periods presented, the DD&A rate per BOE
decreased $.09 per BOE for the nine months ended September 30, 2000 when
compared to the same period in 1999, and decreased $1.47 per BOE for the three
months ended September 30, 2000 when compared to the same period in 1999. This
decrease in the DD&A rate per BOE can be substantially attributed to an overall
increase in reserves attributable to: a) our recent well discoveries in Jackson
County, Texas (these discoveries were previously discussed under the caption
"oil and gas"); and b) higher oil and gas prices between the periods presented.
Higher oil and gas prices will generally extend the economic life of a well
which in turn increases the total recoverable reserves.
Interest Expense
Total interest incurred, and its allocation, for the periods presented is as
follows:
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
---------------------- ----------------------
2000 1999 2000 1999
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Interest paid or accrued ........................$ 70,337 $ 70,690 $ 209,845 $ 209,795
Amortization of debt discount ................... 54,834 54,834 164,503 164,503
Amortization of debt issuance costs ............. 34,559 34,559 103,677 103,677
--------- --------- --------- ---------
Total interest incurred ..................... 159,730 160,083 478,025 477,975
Interest capitalized for exploration activities . (69,942) (70,135) (208,307) (208,116)
--------- --------- --------- ---------
Interest expense ............................$ 89,788 $ 89,948 $ 269,718 $ 269,859
========= ========= ========= =========
</TABLE>
There has been very little change in the total interest incurred when comparing
the periods presented because the majority of our debt is represented by the
$2.8 million in convertible debentures. The principal balance of that debenture
has not changed during the periods presented.
The total interest capitalized for exploration activities has remained
relatively constant when comparing the periods presented since we have, and will
continue to, incur costs on our unevaluated oil and gas properties. Interest is
being properly capitalized in accordance with FAS 34 and FASB Interpretation No.
33, on the unevaluated oil and gas costs. Interest capitalization on the
unevaluated oil and gas costs ceases when the corresponding asset has become
evaluated and is ready for its intended use.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
We 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. At September 30, 2000 and
as of the date of this report, we were not involved in any litigation which we
believe could have a materially adverse effect on our financial condition or
results of operations.
-15-
<PAGE>
Item 2. Recent Sales of Unregistered Securities
We have not issued or sold any unregistered securities during the period covered
by this report.
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 our 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
September 30, 2000.
(b) Reports on Form 8-K: We filed a report on Form 8-K on November 8,
2000 related to the restructuring of the Series B Preferred Stock
and the Termination Agreement with Carpatsky Petroleum, Inc.
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: November 20, 2000 By: /s/ Patrick J. Duncan
------------------------------------------
Patrick J. Duncan
President and Principal Accounting Officer
-16-
