SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-QSB
QUARTERLY 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: 0-12633
TEXOIL, INC.
(EXACT NAME OF SMALL BUSINESS ISSUER AS SPECIFIED IN ITS CHARTER)
NEVADA 88-0177083
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
110 CYPRESS STATION DRIVE
SUITE 220
HOUSTON, TEXAS 77090
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(281) 537-9920
(ISSUER'S TELEPHONE NUMBER)
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act 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 [ ]
APPLICABLE ONLY TO CORPORATE ISSUERS
State the number of shares outstanding of each of the issuer's classes of
common equity, as of the latest practicable date: 6,555,126 shares of common
stock, $.01 par value, issued and outstanding at July 30, 1999.
Transitional Small Business Disclosure Format (check one): Yes [ ] No [X]
<PAGE>
TEXOIL, INC.
TABLE OF CONTENTS
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheet as of June 30, 1999 ..................... 3
Consolidated Statements of Income for the three and six months
ended June 30, 1999 and 1998 ...................................... 4
Consolidated Statements of Cash Flows
for the six months ended June 30, 1999 and 1998 .................. 5
Notes to Consolidated Financial Statements ......................... 6
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS .............................. 10
PART II. OTHER INFORMATION ............................................. 18
2
<PAGE>
TEXOIL, INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
<TABLE>
<CAPTION>
JUNE 30,
1999
--------
<S> <C>
Assets:
Current Assets:
Cash and cash equivalents.......... $ 671
Accounts receivable and other...... 3,911
Drilling advances.................. 9
Other current assets............... 27
--------
Total current assets.......... 4,618
Property, plant and equipment, at cost:
Oil and natural gas properties
(full-cost method)
Evaluated properties.......... 45,634
Unevaluated properties........ 5,968
Office and other equipment.............. 679
--------
52,281
Less -- accumulated depletion,
depreciation and amortization......... (7,358)
--------
Net property, plant and equipment....... 44,923
--------
Other assets, net....................... 715
Deferred tax asset...................... 260
--------
Total assets.................. $ 50,516
========
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued
liabilities....................... $ 2,084
Revenue royalties payable.......... 1,758
--------
Total current liabilities..... 3,842
--------
Long-term debt.......................... 24,500
Convertible subordinated notes.......... 10,000
Stockholders' equity:
Series A preferred stock -- $.01
par value with liquidation
preference of $100 per share,
5,000,000 shares authorized, none
issued and outstanding............ --
Common stock -- $.01 par value;
25,000,000 shares authorized;
6,555,126 shares issued and
outstanding....................... 66
Additional paid-in capital.............. 11,118
Retained earnings....................... 990
--------
Total stockholders' equity......... 12,174
--------
Total liabilities and stockholders'
equity............................ $ 50,516
========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
3
<PAGE>
TEXOIL, INC.
CONSOLIDATED STATEMENTS OF INCOME
THREE AND SIX MONTHS ENDED JUNE 30, 1999 AND 1998
(UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
<TABLE>
<CAPTION>
THREE MONTHS SIX MONTHS
ENDED JUNE 30 ENDED JUNE 30
------------------------ ------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales............... $ 4,845 $ 2,366 $ 8,672 $ 4,232
Operator and management fees.... 237 227 479 481
Interest and other.............. 8 15 12 73
----------- ----------- ----------- -----------
Total revenues............. 5,090 2,608 9,163 4,786
----------- ----------- ----------- -----------
Costs and Expenses:
Lease operating................. 1,534 1,372 3,034 2,142
Workover........................ 44 29 46 109
Production taxes................ 338 123 612 226
General and administrative...... 449 389 896 827
Depletion, depreciation and
amortization.................. 1,069 500 2,094 934
Interest........................ 535 170 1,082 279
Write-down of oil and gas
properties.................... -- 1,208 -- 1,208
----------- ----------- ----------- -----------
Total expenses............. 3,969 3,791 7,764 5,725
----------- ----------- ----------- -----------
Income (loss) before income taxes.... 1,121 (1,183) 1,399 (939)
Provision for deferred income
taxes.............................. (424) 307 (529) 215
----------- ----------- ----------- -----------
Net income........................... $ 697 $ (876) $ 870 $ (724)
=========== =========== =========== ===========
Basic net income per share........... $ .11 $ (.14) $ .13 $ (.12)
=========== =========== =========== ===========
Basic weighted average shares........ 6,555,126 6,387,652 6,555,126 6,251,848
=========== =========== =========== ===========
Diluted net income per share......... $ .10 $ (.14) $ .13 $ (.12)
=========== =========== =========== ===========
Diluted weighted average shares...... 6,721,681 6,387,652 6,789,882 6,251,848
=========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE>
TEXOIL, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 1999 AND 1998
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss).................... $ 870 $ (724)
Adjustments to reconcile net income
(loss) to net cash provided by
(used in) operating activities:
Depletion, depreciation and
amortization................... 2,094 934
Write-down of oil and gas
properties..................... -- 1,208
Deferred income taxes........... 529 (215)
Accounts receivable............. 134 1,669
Accounts receivable -- related
party.......................... -- 60
Notes receivable................ -- (120)
Other assets.................... (52) (262)
Accounts payable and accrued
liabilities.................... (862) (1,949)
Revenue royalties payable....... 260 (1,029)
--------- ---------
Net cash provided by (used
in) operating activities. 2,973 (428)
--------- ---------
Cash flows from investing activities:
Additions to oil and gas
properties..................... (1,674) (7,977)
Other equipment additions....... (51) (156)
--------- ---------
Net cash provided by (used
in) investing
activities.............. (1,725) (8,133)
--------- ---------
Cash flows from financing activities:
Proceeds from issuance of common
stock.......................... -- --
Proceeds from long-term debt and
other.......................... -- 5,000
Repayments of long-term debt.... (1,000) (2)
--------- ---------
Net cash provided by
financing activities.... (1,000) 4,998
--------- ---------
Net increase (decrease) in cash and
cash equivalents................... 248 (3,563)
Cash and cash equivalents --
beginning of period................ 423 4,059
--------- ---------
Cash and cash equivalents -- end of
period............................. $ 671 $ 496
========= =========
Supplemental disclosure of cash flow
information:
Cash paid during the period for:
Interest................... $ 1,348 $ 379
========= =========
Income taxes............... $ -- $ --
========= =========
Oil and gas properties purchased by
issuance of common stock........... $ -- $ 763
========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
5
<PAGE>
TEXOIL, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1: ORGANIZATION AND ACCOUNTING POLICIES:
ORGANIZATION AND BASIS OF PRESENTATION
Texoil Inc. ("Texoil" or the "Company") operates a single business
segment involved in the acquisition, development and production of, and
exploration for, crude oil, natural gas and related products primarily in Texas,
Louisiana and Oklahoma. The financial statements included herein have been
prepared by the Company without audit pursuant to the rules and regulations of
the Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (which consist solely of normal recurring adjustments) which are, in
the opinion of management, necessary for a fair presentation of the financial
results for interim periods. Certain information and notes normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to such rules and
regulations. However, the Company believes that the disclosures are adequate to
make the information presented not misleading. These financial statements should
be read in conjunction with the financial statements and notes thereto included
in the Company's annual report on Form 10-KSB for the year-ended December 31,
1998.
REVERSE STOCK SPLIT
The Company's Board of Directors recently approved certain changes to the
Company's outstanding common shares intended to result in approximately a
1-for-6 reverse stock split effective on June 25, 1999. In order to reduce the
number of outstanding odd lots, the reverse split occurred in a two-step process
whereby a 1-for-600 reverse split was followed by a 100-for-1 forward split.
These procedures were undertaken to enable the Company to adjust or redeem
odd-lots, which should result in substantial annual administrative cost savings
to the Company. Step one (the reverse split) resulted in each 600 shares of
outstanding stock being reduced to one share of common stock. Shareholders with
less than one share, but at least one-tenth share of stock, were issued one
whole share of common stock. Shareholders with less than one-tenth share after
the reverse stock split are entitled to receive a cash payment in redemption of
their fractional shares at a price equal to the market value. With step two (the
forward split), each share of common stock was adjusted to 100 shares of common
stock, $.01 par value. The Company is now authorized to issue 25,000,000 shares
of common stock, par value $.01, and 5,000,000 shares of preferred stock, $.01
par value. The Company estimates that the rounding and redemption effects of
these actions will result in approximately 8,600 shares being issued and
approximately 7,400 shares being redeemed, on a post-split basis. The redemption
cost is estimated at $25,000.Annual savings related to administrative costs are
estimated at $38,000. The Company estimates that 6,555,126 shares are issued and
outstanding at June 30, 1999, subject to certain nominal adjustments as shares
are exchanged.
All issued and outstanding share and per share data reflected in the
accompanying Consolidated Financial Statements and Notes to Consolidated
Financial Statements have been retroactively restated to reflect the impact of
the reverse stock split.
6
<PAGE>
TEXOIL, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NET INCOME PER COMMON SHARE
Basic net income per common share is computed based on the weighted average
shares of common stock outstanding. Net income per share computations to
reconcile basic and diluted net income for the quarters ended June 30, 1999 and
1998 consist of the following (in thousands except per share data):
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Net income.............................. $ 697 $ (876) $ 870 $ (724)
Basic weighted average shares........... 6,555,126 6,387,652 6,555,126 6,251,848
Effect of dilutive securities:
Warrants........................... 38,042 -- 62,833 --
Options............................ 128,513 -- 171,923 --
Awards............................. -- -- -- --
Convertible notes.................. -- -- -- --
Diluted weighted average shares......... 6,721,681 6,387,652 6,789,882 6,251,848
Per common share net income:
Basic.............................. $ .11 $ (.14) $ .13 $ (.12)
Diluted............................ $ .10 $ (.14) $ .13 $ (.12)
</TABLE>
NOTE 2: NEW ACCOUNTING PRONOUNCEMENTS
In June 1998 the Financial Accounting Standards Board issued SFAS Statement
No. 133, "Accounting for Derivative Instruments and Hedging Activities". The
statement establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows the gains and losses on derivatives to offset related results on the
hedged item either in the income statement or in the statement of stockholders'
equity, and requires that a company must formally document, designate and assess
the effectiveness of transactions that receive hedge accounting. The statement
is effective for fiscal years beginning after June 15, 2000. The Company is
currently evaluating the new standard but has not yet determined the impact it
will have on its financial position and results of operations.
7
<PAGE>
TEXOIL, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3: UNAUDITED PRO FORMA FINANCIAL INFORMATION
On October 30, 1998, the Company closed on a significant acquisition of oil
and gas properties in South Texas and Louisiana from Sonat Exploration Company
("Sonat Properties"). The acquisition was accounted for using the purchase
method of accounting. The activities of the acquired Sonat Properties were
included in results of operations beginning November 1, 1998. Selected results
of operations for the six months ended June 30, 1998, on a pro forma basis,
giving effect to the acquisition as if it took place on January 1, 1998, are as
follows:
<TABLE>
<S> <C>
Revenues................................ $ 10,047
===========
Net income.............................. $ 436
===========
Basic income per share.................. $ .07
===========
Basic weighted average shares
outstanding........................... 6,251,848
===========
Diluted income per share................ $ .06
===========
Diluted weighted average shares
outstanding........................... 7,069,767
===========
</TABLE>
Adjustments reflected in the historical results to estimate the above pro
forma results of operations for the quarter ended June 30, 1998, include
adjustments to (1) increase operator fees pursuant to operating agreements
associated with acquired properties, (2) recalculate depreciation, depletion and
amortization based upon combined historical production, reserves and cost basis,
(3) reflect interest expense for borrowings under the increased and amended
credit facility at an estimated average annual interest rate of 8.0%, and (4)
adjust income tax expense as a result of the acquisition. The unaudited pro
forma amounts do not purport to represent what the results of operations would
have been had the acquisition of the Sonat Properties occurred on such date or
to project the Company's results of operations for any future period.
NOTE 4: CREDIT AGREEMENT
The Company has a revolving credit agreement (Credit Agreement) with a bank
to finance property acquisitions and for temporary working capital requirements.
The Credit Agreement, as amended, provides up to $50 million in available
borrowings, limited by a borrowing base (as defined in the Credit Agreement)
which was $31 million and $9.0 million at June 30, 1999 and 1998, respectively.
As of June 30, 1999 and 1998, borrowings outstanding under the Credit Agreement
were $24.5 million and $5.0 million, respectively. The borrowing base is
redetermined annually by the bank pursuant to the Credit Agreement (or more
frequently at the option of the Company) and is reduced over a five-year period
on a straight-line basis, commencing September 1, 1999. The average interest
rate paid to the lender was 7.3% and 9.0% for the six months ended June 30, 1999
and 1998, respectively. The Company has granted first mortgages, assignments of
production, security agreements and other encumbrances on its oil and gas
properties to the lender, as collateral, pursuant to the Credit Agreement. The
Credit Agreement contains covenants which, among other things, restrict the
payment of dividends on any security, limit the amount of consolidated debt,
limit the Company's ability to make certain loans and investments, and require
that the Company remain in compliance with certain covenants of the Credit
Agreement.
NOTE 5: HEDGING ACTIVITIES
OIL AND GAS PRICES
The Company has entered into various oil and gas hedging contracts with a
major financial institution in an effort to manage its exposure to product price
volatility. Under these contracts, the Company receives or makes payments based
on the differential between fixed and variable prices for crude oil and natural
gas; such amounts are reflected in oil and gas sales in the accompanying
financial statements. Amounts received
8
<PAGE>
TEXOIL, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
or paid under such hedging and financial instrument contracts increased oil and
gas sales by $9,225 and $100,225 for the three and six months ended June 30,
1999, respectively. There were no hedging activities in 1998. The oil and gas
hedging contracts in place as of June 30, 1999 had a market value of $(517,728).
For the three and six months ended June 30, 1999, the Company sold 300,000
MMBtu and 500,000 MMBtu, respectively, at a fixed price of $2.17 per MMBtu under
a natural gas swap. In addition to these amounts, the Company has various fixed
price swap contracts for July 1999 through October 1999 and February 2000
through October 2000 production covering 1,210,000 MMBtu's of natural gas at a
price per unit averaging $2.16 based on Houston Ship Channel index pricing. For
the three months ended June 30, 1999, the Company sold 50,000 Bbls at prices
ranging from $17.75 to $18.07 per barrel. No oil volumes were hedged in the
first quarter of 1999. The Company also has fixed price swaps covering 270,000
Bbls of oil at prices averaging $17.76 per Bbl for the period of July 1999
through December 1999.
INTEREST RATES
In order to mitigate the impact of changes in interest rates, the Company
entered into an interest rate swap effective November 5, 1998 which fixed the
floating portion of its interest rate at 5.25% on $12,000,000 notional amount
for the period from November 5, 1998 through November 6, 2000. For the three and
six months ended June 30, 1999 the Company paid $9,826 and $17,618,
respectively, which has been recorded as additional interest expense. The market
value of the interest rate swap contract in place as of June 30, 1999, was
$60,486.
NOTE 6: SUBSEQUENT EVENT
On July 22, 1999, the Company closed the acquisition of Hagist Ranch field,
Duval County, Texas. The acquisition price was approximately $5.4 million,
subject to certain post-closing adjustments, as specified in the purchase and
sale agreement. Texoil will operate the field through its wholly-owned operating
subsidiary. The Company funded the acquisition with available borrowings under
its Credit Agreement. In connection with the acquisition, the Company's
borrowing base under its Credit Agreement has increased from $31.0 million to
$36.0 million.
9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the unaudited
Consolidated Financial Statements and related notes thereto, included elsewhere
in this 10-QSB and should further be read in conjunction with the Company's
annual report on Form 10-KSB, for the year-ended December 31, 1998.
FORWARD-LOOKING INFORMATION
This quarterly report on Form 10-QSB, and in particular this management's
discussion and analysis of financial condition and results of operations,
contains "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. All statements other than statements of historical
facts included in this report and, in particular, this section of this report,
including, without limitation, statements regarding the Company's business
strategy, plans, objectives expectations, intent and beliefs of management
related to current or future operations are forward-looking statements. Such
statements are based on certain assumptions and analyses made by management,
based on its experience and its perception of historical trends, current
conditions, expected future developments and other factors it believes to be
appropriate. The forward-looking statements included in this report are subject
to a number of material risks and uncertainties including assumptions about the
pricing of oil and gas, assumptions about operating costs, production operations
continuing as in the past or as projected by independent engineers, the ability
to generate and take advantage of acquisition opportunities and numerous other
factors. A detailed discussion of important factors that could cause actual
results to differ materially from the Company's expectations are discussed
herein and in the Company's annual report on Form 10-KSB for 1998.
Forward-looking statements are not guarantees of future performance and actual
results, developments and business decisions may differ from those envisioned by
such forward-looking statements.
BUSINESS AND STRATEGY
Texoil is an independent oil and gas company engaged in the acquisition and
development of oil and gas reserves through an active and diversified program
which includes purchases of oil and gas reserves, re-engineering, development
and exploration activities. As further discussed herein, future growth in
assets, earnings, cash flows and share values are dependent upon the Company's
ability to acquire, discover and develop commercial quantities of oil and gas
reserves that can be produced at a profit and assemble an oil and gas reserve
base with a market value exceeding its finding and production costs. The price
of crude oil was significantly depressed in 1998 and early 1999. While prices
have recently rebounded, no assurance can be given that current price levels
will be sustained or that prices will continue to increase. The industry-wide
reduction in prices adversely affected revenues and net cash flows of the
Company, as well as most companies in the industry, particularly those whose
assets were concentrated in oil reserves. Such reduced revenues and cash flows
have led to capital budget decreases, contraction of exploration financing and
elimination or deferral of new ventures by many companies and institutional
investors. In the opinion of management, during 1998 and early 1999, such
conditions adversely affected Texoil's ability to solicit industry partners for
major exploration prospects. Texoil compensated for these industry conditions by
focusing clearly on exploratory prospects which were readily marketable to
industry partners, acquiring additional producing assets, concentrating on
operating and administrative cost reductions, and taking other actions designed
to offset the severe effects of price reductions. Most of these actions already
were an integral part of the Company's fundamental business strategy. Recent
price increases appear to have favorably impacted corporate budgets and the
Company has begun soliciting industry partners for certain high potential
exploratory projects that had been deferred. No assurance can be given that the
Company will be able to secure partners for exploratory prospects on a promoted
basis.
Management believes, however, that Texoil will benefit from existing and
new opportunities to acquire and develop reserves. The Company has identified
numerous development and exploratory projects in its existing property portfolio
and has further undertaken detailed field studies intended to define additional
potential. In addition, management believes the acquisitions market has
improved. Major companies and
10
<PAGE>
large independents are expected to continue or expand divestitures of
"non-core" properties. Smaller companies that were not positioned to withstand
the significant price declines may be forced to sell assets or consolidate or
merge to satisfy creditors or improve shareholder value. Furthermore, costs of
labor and field services and products have declined during the industry downturn
and generally have not increased in relation to oil and gas prices, making
re-engineering and development projects more cost effective.
As a result of these circumstances, management believes the Company is
positioned to benefit from property acquisition, development and exploratory
opportunities. The Company also intends to pursue corporate acquisitions and
mergers. In addition, management continues to focus on capital expenditures that
can result in increased production and operating cost reductions on a per-unit
basis. The current corporate action plan is merely an expansion and adaptation
of the business plan which was conceived and implemented by management in early
1996, and has resulted in significant growth to date. Following is a brief
outline of management's plans. See also, "Impact of Property Acquisitions and
Development" and "Capital Expenditures" below.
1) Place greater emphasis on acquisition opportunities. Selectively
acquire corporate entities and properties with significant proved
producing reserves and development and exploration potential.
2) Complete field studies and implement capital development programs.
3) Continue the Company's exploration program; continue to solicit
industry or institutional partners on a promoted basis.
4) Continue activities directed toward reducing per-unit operating and
general and administrative costs on a long-term sustained basis.
5) Increase equity and long-term financing through available means,
whether through direct placement of securities or in connection with
corporate acquisition activities.
Consistent with the emphasis being placed on acquisitions and development
in the short-term, capital expenditures directed to exploration may be reduced.
While the Company does not intend to curtail exploration spending, it will
focus, in the near-term, on projects currently in inventory and situations where
the Company can acquire proprietary seismic data and prospective acreage as part
of a corporate or asset acquisition, rather than initiating new 3-D surveys.
Management believes the current market is conducive to the acquisition of proved
reserves with seismic data and exploratory acreage, at little or no incremental
cost over such proved reserves. While the impact and success of this action plan
cannot be predicted with any accuracy, management's goal is to replace
production and further increase its reserve base at an acquisition or finding
cost that will yield attractive rates of return and share appreciation.
ACCOUNTING FOR OIL & GAS PROPERTIES
The Company uses the full-cost method of accounting for its investment in
oil and gas properties. Under the full-cost method, all costs of acquisition,
exploration and development of oil and gas reserves are capitalized separately
for each cost center (generally defined as a country). Capitalized balances are
referred to as the "full-cost pool" and are further classified as evaluated or
unevaluated. Evaluated costs are those where proved reserves have been
determined or where the property has been impaired or abandoned. Such costs are
subject to depletion, depreciation and amortization expense ("DD&A").
Unevaluated costs are not subject to DD&A and generally require additional
geological, geophysical and/or engineering evaluation prior to management's
decision to drill, develop or abandon such properties. When such properties are
evaluated, capitalized costs will be transferred to an evaluated status and
included in the calculation of DD&A. Depletion expense is calculated using the
units of production method based on the ratio of current production to total
proved recoverable oil and natural gas reserves. The depletion rate is applied
to a cost base which includes net capitalized evaluated costs plus an estimate
of costs to be incurred in the development of proved undeveloped reserves, or in
future abandonment activities. Under the full-cost method, a write-down of oil
and gas properties must be charged to operations if net capitalized costs at the
end of each quarterly reporting period exceed the estimated discounted future
net revenues of proved oil and
11
<PAGE>
natural gas reserves, using current oil and gas prices and costs, held constant
over the life of the properties, plus the lower of cost or fair value of
unevaluated properties, both on an after-tax basis (the "full cost ceiling").
Capitalized costs include payroll and related costs of technical personnel
which are directly attributable to the Company's oil and gas acquisition,
exploration and development activities. Such amounts capitalized for the three
and six months ended June 30, were $162,000 and $331,000 for 1999, and $149,000
and $265,000 for 1998, respectively. The Company capitalizes interest
attributable to oil and natural gas properties which are not subject to
amortization and are in the process of being evaluated. Included in unevaluated
capitalized costs for the three and six months ended June 30, 1999 and 1998, are
interest costs of $122,790 and $235,832 for 1999, and $107,000 and $201,000 for
1998.
At the end of the second quarter of 1999, the Company's full-cost ceiling
substantially exceeded its net capitalized costs. Net capitalized costs could
exceed the full-cost ceiling in future periods due to downward revisions to
estimated proved reserve quantities, declines in oil and gas prices, increases
in operating costs, unsuccessful exploration and development activities or other
factors which cannot be reasonably predicted by the Company. Once recorded, a
write-down of oil and gas properties cannot be reversed at a later date even if
estimated reserve quantities or oil and gas prices subsequently increase.
Management believes that current reserve estimates, which represent the basis
for calculating limitations on capitalized costs, are reasonable under present
operating conditions and circumstances. However, reserve estimates and forecasts
are inherently imprecise and, therefore, subject to significant future changes.
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 1999, COMPARED TO THREE MONTHS ENDED JUNE 30,
1998.
The Company recorded a net income (loss) of $697,000 and $(876,000) for
three months ended June 30, 1999 and 1998, respectively. The $1,573,000 increase
in the Company's comparative net income resulted primarily from the following
factors:
<TABLE>
<CAPTION>
NET AMOUNT CONTRIBUTING
TO INCREASE (DECREASE)
IN NET INCOME
------------------------
<S> <C>
(000'S)
Oil and gas sales.................... $2,479
Lease operating and workover
expenses........................... (177)
Production taxes..................... (215)
General and administrative
expenses -- net.................... (60)
Depletion, depreciation and
amortization expense ("DD&A")...... (569)
Interest expense -- net.............. (365)
Writedown of oil and gas
properties......................... 1,208
Other income -- net.................. 3
Provision for income taxes........... (731)
--------
$1,573
========
</TABLE>
12
<PAGE>
The following discussion applies to the changes in the composition of net
income shown above.
The $2,479,000 or 105% increase in net oil and gas sales is due to the
increase in production volumes resulting from the acquisition and development of
properties and an increase in average oil prices, as shown in the table
presented immediately below. The reduction on a per BOE basis is due to several
factors including incremental gas and oil volumes and ongoing cost reduction and
re-engineering activities.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
PERCENT JUNE 30,
INCREASE --------------------
(DECREASE) 1999 1998
---------- --------- ---------
<S> <C> <C> <C>
Gas production (MMcf)................ 271% 1,051 283
Oil production (MBbls)............... 34% 175 131
Barrel of oil equivalent (MBOE)...... 97% 350 178
Average price gas (per Mcf).......... (1%) $ 2.30 $ 2.33
Average price oil (per Bbl).......... 29% $ 15.80 $ 12.24
Average price per BOE................ 9% $ 13.84 $ 12.71
</TABLE>
Lease operating expenses and workover costs increased $177,000 or 13%. On a
unit-of-production, barrel of oil equivalent ("BOE") basis, costs were
actually reduced 43%. The dollar increase is a result of the acquisition and
development of oil and gas properties. On a BOE basis, production volumes
increased 97% over the prior year. Accordingly, lease operating expenses
increased primarily as a result of additional production volumes. The Company
expects further reductions to lease operating expenses on a BOE basis in 1999 as
a result of re-engineering and development activities. Production taxes
increased by $215,000 or 175% due to increased production volumes and revenues.
General and administrative costs increased $60,000 or 15%. The percentage
increase in general and administrative expenses was considerably less than the
increases in production and revenues as a result of both rigorous cost
containment efforts and production increases. On a BOE basis, general and
administrative expenses actually were reduced by 42% in 1999 over 1998 levels.
The dollar increase is comprised primarily of increases in management, operating
and administrative staffing associated with the Company's growth. The Company
must attract and retain competent management, technical and administrative
personnel to pursue its business strategy and fulfill its contractual
obligations.
The $569,000 or 114% increase in DD&A expenses is primarily due to the
increase in oil and gas production volumes and capitalized balances subject to
DD&A, offset by increases in estimated recoverable reserves, resulting from the
acquisition and development of gas and oil properties and from price increases.
Capitalized costs included in the full-cost pool and subject to DD&A were $45.6
and $25.5 million at June 30, 1999 and 1998, respectively. In addition,
estimated future development costs associated with proved undeveloped reserves
in the amount of $14.6 million and $6.5 million at June 30, 1999 and 1998,
respectively, were included in the DD&A calculations. The proved reserve
quantities used for the calculation of DD&A were approximately 18.2 million
barrels of oil equivalent. This amount is approximately 12% larger than the
quantities used at year end 1998. The increase is due to upward reserve
revisions resulting from the economics of the higher commodity prices prevailing
at June 30, 1999, and other engineering considerations.
Interest expense increased by $365,000 primarily due to the increased
long-term debt used to finance acquisitions. Interest expense was $535,000 and
$170,000 for the three months ended June 30, 1999 and 1998, respectively, and is
expected to be approximately $2.2 million in 1999; however, the Company plans to
replace some debt with equity and, therefore, reduce projected interest expense.
The net change in the provision for income taxes was $731,000 due to the
recognition of pre-tax income in 1999 versus a 1998 loss.
13
<PAGE>
SIX MONTHS ENDED JUNE 30, 1999, COMPARED TO SIX MONTHS ENDED JUNE 30, 1998
The Company recorded a net income (loss) of $870,000 and $(724,000) for the
six months ended 1999 and 1998, respectively. The $1,594,000 increase in the
Company comparative net income resulted primarily from the following factors:
<TABLE>
<CAPTION>
NET AMOUNT CONTRIBUTING
TO INCREASE (DECREASE)
IN NET INCOME
------------------------
<S> <C>
(000'S)
Oil and gas sales.................... $4,440
Lease operating and workover
expenses........................... (829)
Production taxes..................... (386)
General and administrative
expenses -- net.................... (69)
Depletion, depreciation and
amortization expense ("DD&A")...... (1,160)
Interest expense -- net.............. (803)
Writedown of oil and gas
properties......................... 1,208
Other income net.................... (63)
Provision for income taxes........... (744)
--------
$1,594
========
</TABLE>
The following discussion applies to the changes in the composition of net
income shown above.
The $4,440,000 or 105% increase in net oil and gas sales is primarily
attributable to the increase in production volumes resulting from the
acquisition and development of properties during 1998. The increase in
production volumes and changes in prices are shown in the table presented
immediately below.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
PERCENT JUNE 30,
INCREASE --------------------
(DECREASE) 1999 1998
---------- --------- ---------
<S> <C> <C> <C>
Gas production (Mmcf)................ 276% 1,961 521
Oil production (MBbls)............... 48% 343 232
Barrel of oil equivalent (MBOE)...... 110% 670 319
Average price gas (per Mcf).......... (8%) $ 2.07 $ 2.26
Average price oil (per Bbl).......... 4% $ 13.43 $ 12.88
Average price per BOE................ (2%) $ 12.94 $ 13.27
</TABLE>
Lease operating expenses and workover costs increased 829,000 or 37%. On a
unit-of production, barrel of oil equivalent ("BOE") basis, costs were
actually reduced 35%. The dollar increase is a result of the acquisition and
development of oil and gas properties in 1998. On a BOE basis, production
volumes increased 110% over the prior year. Accordingly, lease operating
expenses increased primarily as a result of additional production volumes. The
Company expects further reductions to lease operating expenses on a BOE basis in
1999 as a result of re-engineering and development activities. Production taxes
increased by $386,000 or 171% due to increased production volumes and revenues.
General and administrative costs increased $69,000 or 8%. The percentage
increase in general and administrative expenses was considerably less than the
increases. On a BOE basis, general and administrative expenses actually were
reduced by 48% in 1999 compared to 1998 levels. The dollar increase is comprised
primarily of increases in management, operating and administrative staffing
associated with the Company's growth. The Company must attract and retain
competent management, technical and administrative personnel to pursue its
business strategy and fulfill its contractual obligations.
The $1,160,000 or 124% increase in DD&A expenses is primarily due to the
increase in oil and gas production volumes and capitalized balances subject to
DD&A, offset by increases in estimated recoverable reserves, resulting from the
acquisition and development of gas and oil properties and price increases.
Capitalized costs included in the full-cost pool and subject to DD&A were $45.6
and $25.5 million at
14
<PAGE>
June 30, 1999, and 1998, respectively. In addition, estimated future development
costs associated with proved undeveloped reserves in the amount of $14.6 million
and $6.5 million at June 30, 1999 and 1998, respectively, were included in the
DD&A calculations. The proved reserve quantities used for the calculation of
DD&A were approximately 18.2 million barrels of oil equivalent. This amount is
approximately 12% larger than the quantities used at the year end 1998. The
increase is due to upward reserve revisions resulting from the economics of
higher commodity prices prevailing at June 30, 1999, and other engineering
considerations.
Interest expense increased by $803,000 primarily due to the increased
long-term debt used to finance acquisitions. Interest expense was $1,082,000 and
$279,000 for the six months ended June 30, 1999 and 1998, respectively, and is
expected to be approximately $2.2 million in 1999; however, the Company plans to
replace some debt with equity and, therefore, reduce projected interest expense.
Other income decreased $63,000 for the six months ended June 30, 1999,
principally due to decreases in interest income and consulting fees.
The provision for income taxes increased $744,000 as a result of the
increase in net income.
IMPACT OF PROPERTY ACQUISITIONS AND DEVELOPMENT
Management expects revenues and cash flows to exceed $18.0 million and $9.0
million, respectively, in 1999, representing an increase of $7.6 million (73%)
and $5.9 million (187%), respectively, over 1998. These estimates are predicated
on the results of operations for the first half of 1999 and anticipated
production levels from proved producing reserves, without significant
development of proved behind-pipe or undeveloped reserves. These estimates
further assume the average prices realized on a year-to-date basis will be
realized in the last half of 1999, and that prevailing cost levels can be
sustained. Estimates are based on independent reserve reports prepared by third
parties in connection with required reporting and financing activities. The
majority of the expected increase in revenues is a direct result of
approximately $28.4 million in capital expenditures incurred in 1998. In
connection with its acquisitions, the Company has initially focused on capital
expenditures designed to increase production (or arrest natural or mechanical
declines), and lower recurring expenses. The Company has identified numerous
projects in its existing property portfolio related to proved behind-pipe and
undeveloped reserves and has further undertaken detailed engineering and
geological field studies to define additional development and exploratory
potential. Net future cash flows could be favorably affected by further price
improvements, additional reductions to per-unit operating costs, and development
activities related to proved and non-proved reserves. No assurance can be given,
however, that the Company will be able to successfully and economically develop
additional reserves which are associated with its existing properties on new
acquisitions.
IMPACT OF CHANGING PRICES AND COSTS
Texoil's revenues and the carrying value of its oil and gas properties are
subject to significant change due to changes in oil and gas prices. As
demonstrated historically, prices are volatile and unpredictable. As previously
mentioned, oil prices declined appreciably during 1998 and early 1999, but have
recently rebounded. Average oil prices for the six months ended June 30, 1999,
of $13.43 per Bbl were 4% higher than the six month comparable period in 1998
and 9% higher than prices realized in 1998, but still 27% and 41% lower than
average prices realized in 1997 and 1996, respectively. Average oil prices for
the month of June 1999 improved to about $16.29 per barrel. Should prices fall
or fail to remain at levels which will facilitate repayment of debt and
reinvestment of cash flow to replace current production, the Company could
experience difficulty in developing its assets and continuing its growth.
Throughout the low price environment the Company has maintained positive cash
flows including its financing and administrative costs.
CORPORATE EFFORTS TO OFFSET REDUCED PRICES
Early in 1998, in an effort to mitigate the adverse effect of low oil
prices, the Company expanded numerous cost-saving programs designed to reduce
operating and administrative costs and enhance net revenues. Rather than impose
staff reductions of technical and other personnel, the Company chose to
15
<PAGE>
implement a salary reduction program and defer salary increases. With continued
growth and price recovery, salaries have been restored to prior levels and the
Company has expanded its office space to accommodate acquisition development
activities and further production growth. In addition to general and
administrative savings realized during the industry downturn, the Company
further implemented programs designed to reduce operating expenses and has
deferred certain capital expenditures. The Company has continued, however, to
pursue projects that can add economic producing reserves, enhance current
production levels and lower recurring operating expenses. With increased cash
flows and financial resources, the Company expects to expand development
activities and acquire additional properties in its focus areas.
LIQUIDITY AND CAPITAL RESOURCES
The Company expects to finance its future acquisition, development and
exploration activities through cash flow from operating activities, its bank
credit facility, sale of non-strategic assets, various means of corporate and
project finance and ultimately through the issuance of additional securities. In
addition, the Company intends to continue to subsidize drilling activities
through the sale of participations to industry partners on a promoted basis,
whereby the Company will earn working interests in reserves and production
greater than its proportionate capital cost.
RIMCO FINANCING
On December 31, 1997, Texoil entered into a Note Purchase Agreement and
issued 7.875% Convertible Subordinated General Obligation Notes in the principal
amount of $10 million. The financing matures on December 31, 1999, and is
subject to certain extensions or conversion to common stock pursuant to the
terms of the agreements. Management expects that the indebtedness will be
refinanced, extended, or converted into Texoil common stock, on or before
maturity.
CREDIT FACILITY
At June 30, 1999 and 1998, the Company had available borrowing capacity of
$6.5 million and $3.9 million, respectively, in accordance with a revolving
credit agreement with its banks, which can be used to finance property
acquisitions and temporary working capital requirements. The borrowing base is
redetermined annually, or more often at the request of the Company. As of June
30, 1999, a $31 million borrowing base was established. The Company intends to
refinance its bank debt through a corporate offering of securities in 1999 that
may provide longer term financing than presently available under its credit
facility. No assurance can be given, however, that the Company will be able to
refinance its debt.
CASH FLOW FROM OPERATING ACTIVITIES
For the six months ended June 30, 1999, the Company's net cash flow
provided by operating activities was $3.0 million up $3.4 million from the prior
year. This increase is attributable to production from acquisition and
development, price increases lower per unit operating expenses and lower cash
requirements to reduce current liabilities.
CAPITAL EXPENDITURES
The Company's net oil and gas capital expenditures for the six months ended
June 30, 1999 and 1998, are as follows:
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES
FOR THE SIX MONTHS
ENDED
JUNE 30,
--------------------
1999 1998
--------- ---------
<S> <C> <C>
Acquisitions of properties:
Evaluated properties............ $ 1,702 $ 7,598
Unevaluated properties.......... 489 1,143
--------- ---------
$ 2,191 $ 8,741
========= =========
</TABLE>
16
<PAGE>
Capital expenditures for the six months ended June 30, 1999, were financed
principally with cash flows from operations. The above totals do not include
transfers of unevaluated costs to an evaluated status during the period. During
the first half of 1999, the Company has concentrated on integrating its 1998
acquisitions into its operations and on certain re-engineering and development
activities.
As a result of the Company's performance, management believes the Company
has emerged from the industry downturn with significant profit potential,
stronger financial capabilities and enhanced credibility in the industry.
Therefore, management believes the Company can compete successfully for
significant acquisition opportunities. Accordingly, the Company has directed a
greater portion of its current efforts toward new corporate and asset
acquisitions, which are expected to include both proved and exploratory assets.
Certain exploration and development projects have been deferred in favor of
anticipated industry opportunities. In particular, the Company has deferred
projects which are "held-by-production" in favor of projects with definitive
lease expirations. The Company's business strategy has always been to shift its
emphasis among acquisitions, development and exploratory activities consistent
with changes in the marketplace.
Accordingly, with increased cash flows during the remainder of 1999, Texoil
intends to concentrate its capital expenditures on re-engineering facilities
(surface and down-hole), restoring shut-in wells to production, recompletions
and, pending completion of geological and engineering field studies, development
drilling. The Company expects to make additional capital expenditures during
1999 to maintain leases and complete the interpretation of 3-D seismic data
associated with certain exploratory and development projects and further expects
to incur certain drilling costs in 1999. Texoil will continue its practice of
soliciting partners, on a promoted basis, for higher risk exploratory and
development projects.
Based solely on its existing portfolio of properties and projects, the
Company expects to incur $3.0 million of capital expenditures during the
remainder of 1999, as follows:
<TABLE>
<CAPTION>
($000'S)
---------
<S> <C>
Development of proved properties:
Re-engineering -- facilities &
equipment...................... $ 400
Well recompletions and
workovers...................... 950
Drilling........................ 1,000
Exploration:
Land, geological &
geophysical.................... 300
Drilling........................ 350
---------
$ 3,000
=========
</TABLE>
The Company believes that it will have sufficient capital available from
its credit facility, cash flows from operating activities, sale of certain
"non-core" proved properties and sale of drilling participations to industry
partners to fund its capital expenditures. Management believes projected
expenditures will result in increased production and cash flows and increases in
reserve value and will further expose the Company to potentially significant
upside from exploration. Management further believes the deferral of certain
projects will not result in any losses to the Company. A portion of available
cash flow and borrowing capacity will be reserved to fund additional
acquisitions. The Company cannot predict with accuracy the level of capital
expenditures it may incur in connection with acquisitions and development of new
producing properties; however, Texoil has recently acquired a South Texas field
(see Note 6 to the Consolidated Financial Statements) and has set a goal of $20
million for the acquisition and development of new properties over the next 12
months. This goal will require additional corporate or project financing to be
obtained by the Company.
YEAR 2000 COMPLIANCE
The Company has conducted a review of and will continue to review its
software applications for Year 2000 issues. None of the software applications
utilized by the Company were developed internally and all
17
<PAGE>
have been acquired and routinely updated since early 1996. The Company uses a PC
based networked hardware configuration with widely utilized, accepted and
supported software applications for its basic operating and office support
functions. The primary software applications used by the Company for its oil and
gas activities are its accounting, land, production management, engineering and
interpretative exploration software. All such systems were purchased from third
party vendors, who are responsible for their maintenance and support, pursuant
to the terms of license and use agreements. The most critical systems referred
to above are the accounting, land and production systems. Other systems are
primarily analytical tools which facilitate and support engineering and
geological projects. Based on reviews and inquiries conducted by Company
personnel and resultant representations by software vendors, the Company
believes its primary software applications are Year 2000 compliant. Accordingly,
the Company does not expect to incur any material costs to modify, upgrade or
replace its basic business systems over and above ongoing requirements to expand
systems, as required by growth and operations. However, the Company is not able
nor does it possess the technical expertise to conduct a comprehensive review of
programs and systems purchased from and supported by third parties; therefore,
the Company cannot guarantee that it will not incur problems with such software
and business applications.
Although the Company does not expect Year 2000 issues to have a material
impact on its internal operations, it is possible that such issues could
adversely affect customers, suppliers and joint venture partners, with the
possibility of an adverse impact on the Company. Major issues include, (i) the
ability of the Company's customers to accurately and timely measure and pay for
quantities of oil and gas production delivered, (ii) the ability of the
Company's vendors and suppliers to accurately invoice for services and products
and to properly process and account for payments received, (iii) the ability of
non-operating partners in Company operated properties to process and pay their
share of joint interest billings, as rendered and due, and (iv) the ability of
operators, where the Company is a non-operating participant, to disburse net
revenue and render joint interest billings to the Company. As part of its basic
operating practices, the Company believes it currently has adequate internal
controls and procedures in place to account for and monitor material aspects of
the above described activities. As Year 2000 approaches, the Company intends to
take additional steps to determine the Year 2000 readiness of third parties and
to implement additional procedures as it deems reasonably necessary, to account
for and take actions necessary to minimize potential problems resulting from
third party customers, vendors and partners outside of the control of the
Company. In the opinion of management, the single most significant issue is the
timely receipt of payment for oil and gas volumes sold. The majority of the
Company's production is from operated properties where the Company sells field
production to a relatively small number of purchasers. The Company can readily
account for production volumes and prices and aggressively pursue collection.
The effect of problems associated with third parties, if any, cannot be
controlled by the Company and the potential financial impact cannot be estimated
with any accuracy. Such matters could have a material impact on the Company.
PART II. OTHER INFORMATION
Item 1 -- Legal Proceedings -- No material change from legal proceedings
reported in Registrant's Form 10-KSB for the fiscal year ended
December 31, 1998.
Item 2 -- Change in Securities -- None
Item 3 -- Defaults Upon Senior Securities -- None
Item 4 -- Submission of Matters to a Vote of Security Holders -- None
Item 5 -- Other Information -- None
Item 6 -- Exhibits and Reports on Form 8-K
(a) Exhibits -- None
(b) Reports on Form 8-K -- On June 21, 1999, the Company filed a
report on Form 8-K, including Item 5, Other Events, related
to a reverse stock split.
18
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THE
REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE
UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
TEXOIL, INC.
Date: August , 1999 By: /s/FRANK A. LODZINSKI
FRANK A. LODZINSKI
PRESIDENT AND CEO
19
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM TEXOIL QUARTERLY REPORT 6/30/99 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 671
<SECURITIES> 0
<RECEIVABLES> 3,920
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 4,618
<PP&E> 52,281
<DEPRECIATION> (7,358)
<TOTAL-ASSETS> 50,516
<CURRENT-LIABILITIES> 3,842
<BONDS> 0
0
0
<COMMON> 66
<OTHER-SE> 12,108
<TOTAL-LIABILITY-AND-EQUITY> 50,516
<SALES> 8,672
<TOTAL-REVENUES> 9,163
<CGS> 3,692
<TOTAL-COSTS> 896
<OTHER-EXPENSES> 2,094
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,082
<INCOME-PRETAX> 1,399
<INCOME-TAX> 529
<INCOME-CONTINUING> 870
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 870
<EPS-BASIC> .13
<EPS-DILUTED> .13
</TABLE>
