<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarterly period ended June 30, 1999
-------------
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition period _________________ to _________________
Commission File Number 0-22650
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PETROCORP INCORPORATED
(Exact name of registrant as specified in its charter)
Texas 76-0380430
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
16800 Greenspoint Park Drive 77060-2391
Suite 300, North Atrium (Zip Code)
Houston, Texas
(Address of Principal Executive Offices)
Registrant's Telephone Number, Including Area Code: (281) 875-2500
Not Applicable
(Former Name, Former Address and Former Fiscal Year, if changed since
last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or 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 [_]
Indicate the number of shares outstanding of each of the Registrant's classes of
stock, as of July 31, 1999:
Common Stock, $.01 per value 8,656,019
---------------------------- ---------
(Title of Class) (Number of Shares Outstanding)
<PAGE>
PETROCORP INCORPORATED
INDEX
<TABLE>
<CAPTION>
PAGE NO.
PART I. FINANCIAL INFORMATION --------
Item 1. Financial Statements.
<S> <C>
Consolidated Balance Sheet at June 30, 1999 and December 31, 1998 1
Consolidated Statement of Operations for the three months and six months ended June 30,
1999 and 1998 2
Consolidated Statement of Cash Flows for the three months and six months ended June 30,
1999 and 1998 3
Notes to Consolidated Financial Statements 4
Item 2. Management's Discussion and Analysis of Financial Condition and Results of
Operations 7
Item 3. Quantitative and Qualitative Disclosures about Market Risk 13
PART II. OTHER INFORMATION 15
SIGNATURES 16
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEET
(in thousands, except share amounts)
JUNE 30 December 31,
1999 1998
--------- ---------
ASSETS (Unaudited)
Current assets:
Cash and cash equivalents $ 8,330 $ 7,786
Accounts receivable, net 3,629 4,569
Other current assets 377 326
--------- ---------
Total current assets 12,336 12,681
--------- ---------
Property, plant and equipment:
Proved oil and gas properties, at cost, full
cost method, net of accumulated depreciation,
and amortization 62,973 64,179
Unproved oil and gas properties, not subject
to depletion 8,131 9,151
Plant and related facilities, net 3,485 3,768
Other, net 881 1,144
--------- ---------
75,470 78,242
--------- ---------
Deferred income taxes 13,705 12,761
Other assets, net 433 308
--------- ---------
Total assets $ 101,944 $ 103,922
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 3,860 $ 4,424
Accrued liabilities 1,658 3,467
Current portion of long-term debt 4,445 2,710
--------- ---------
Total current liabilities 9,963 10,601
--------- ---------
Long-term debt 45,362 47,305
--------- ---------
Deferred revenue 80 257
--------- ---------
Deferred income taxes 5,343 5,085
--------- ---------
Commitments and contingencies (Note 6)
Shareholders' equity:
Preferred stock, $0.01 par value, 1,000,000
shares authorized none issued
Common stock, $0.01 par value, 25,000,000
shares authorized, 8,656,019 share issued
and outstanding as of June 30, 1999 and
December 31, 1998 87 87
Additional paid-in capital 71,245 71,245
Accumulated deficit (24,962) (24,324)
Accumulated other comprehensive loss (5,174) (6,264)
--------- ---------
Total shareholders' equity 41,196 40,744
--------- ---------
Total liabilities and shareholders' equity $ 101,944 $ 103,992
========= =========
The accompanying notes are an integral part of these financial statements.
1
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PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands, except per share amounts)
(Unaudited)
<TABLE>
<CAPTION>
For the three months For the six months
ended June 30, ended June 30,
----------------- -------------------
1999 1998 1999 1998
------- ------- -------- --------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas $ 5,964 $ 5,717 $ 10,905 $ 11,890
Plant processing 452 334 906 677
Other 44 34 54 24
------- ------- -------- --------
6,460 6,085 11,865 12,591
------- ------- -------- --------
EXPENSES:
Production costs 1,502 1,863 3,113 3,652
Depreciation, depletion and amortization 2,774 4,017 5,467 7,968
General and administrative 821 1,155 1,875 2,333
Restructuring costs 1,090
Other operating expenses 90 48 153 86
------- ------- -------- --------
5,187 7,083 11,698 14,039
------- ------- -------- --------
INCOME (LOSS) FROM OPERATIONS 1,273 (998) 167 (1,448)
------- ------- -------- --------
OTHER INCOME (EXPENSES):
Investment and other income 79 84 167 176
Interest expense (924) (875) (1,859) (1,739)
Other expenses (36) (1) (39)
------- ------- -------- --------
(845) (827) (1,693) (1,602)
INCOME (LOSS) BEFORE INCOME TAXES 428 (1,825) (1,526) (3,050)
Income tax benefit (55) (796) (888) (1,385)
------- ------- -------- --------
NET INCOME (LOSS) $ 483 $(1,029) $ (638) $ (1,665)
======= ======= ======== ========
Net income (loss) per common
share - basic $ 0.06 $ (0.12) $ (0.07) $ (0.19)
======= ======= ======== ========
Net income (loss) per common
share - diluted $ 0.06 $ (0.12) $ (0.07) $ (0.19)
======= ======= ======== ========
Weighted average number of common
shares - basic 8,656 8,642 8,656 8,617
Weighted average number of common
shares - diluted 8,667 8,714 8,667 8,698
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
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PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
For the six months
ended June 30,
--------------------------
1999 1998
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ (638) $ (1,665)
Adjustments to reconcile net loss to net
cash provided by operating activities:
Depreciation, depletion and amortization 5,467 7,968
Deferred income tax benefit (888) (1,385)
------- ---------
3,941 4,918
Change in operating assets and liabilities:
Accounts receivable 940 2,281
Other current assets (51) 92
Accounts payable (564) (2,208)
Accrued liabilities (1,809) 78
Other (177) (229)
------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES 2,280 4,932
------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties 1,896
Additions to oil and gas properties (1,228) (12,107)
Additions to plant and related facilities (62) (386)
Additions to other property, plant and equipment (13) (58)
Additions to other assets (156) (5)
------- ---------
NET CASH USED IN INVESTING ACTIVITIES (1,459) (10,660)
------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 2,170 10,117
Repayment of long-term debt (2,525) (8,442)
Other 350
------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (355) 2,025
------- ---------
Effect of exchange rate changes on cash 78 (8)
------- ---------
Net increase (decrease) in cash and cash equivalents 544 (3,711)
Cash and cash equivalents at beginning of period 7,786 9,391
------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 8,330 $ 5,680
======= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
3
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - BASIS OF PRESENTATION:
The unaudited consolidated financial statements of PetroCorp Incorporated (the
"Company" or "PetroCorp") have been prepared in accordance with generally
accepted accounting principles for interim financial information and with
instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they
do not include all of the information and footnotes required by generally
accepted accounting principles for complete financial statements. In the
opinion of management, all adjustments, consisting of normal and recurring
adjustments necessary for a fair presentation, have been included. For further
information, refer to the consolidated financial statements and footnotes
thereto for the year ended December 31, 1998, included in the Company's 1998
Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934. Interim period results are not necessarily indicative of
results of operations or cash flows for a full-year period.
NOTE 2 - RESTRUCTURING:
On November 16, 1998, the Company announced that its Board of Directors had
retained CIBC Oppenheimer Corp. to advise it with respect to strategic
alternatives available to the Company for maximizing shareholder value,
including sales of some or all of the Company's assets or a merger,
reorganization or other restructuring of the Company.
As part of its goal of maximizing shareholder value, the Company also
announced that its Board of Directors has adopted a Shareholder Rights Plan. The
newly adopted Shareholder Rights Plan is designed to protect the shareholder
against any effort to acquire the Company for less than its full value. However,
the Plan does not prevent a takeover. The intention of the Plan is to enable
shareholders to realize the long-term value of their investments and to enable
the Board of Directors to serve the interests of all shareholders. Under the
Plan, each shareholder of record at the close of business on November 23, 1998,
received one Series A Preferred Stock Purchase Right (Right) for each share of
Common Stock held. The Rights expire on November 12, 2008.
The Company opened a data room in February, 1999 and received expressions of
interest from third parties to purchase certain assets of, or merge with, the
Company. On May 21, 1999, the Company announced that it had rejected as
inadequate all proposals received. The Board of Directors, after consultation
with CIBC Oppenheimer, decided that the interests of all shareholders were best
served by not pursing a sale or merger at that time.
After consideration of other strategic alternatives, on August 3, 1999,
PetroCorp's Board of Directors entered into a Management Agreement with its
largest shareholder, Kaiser-Francis Oil Company, under which Kaiser-Francis will
provide management, technical and administrative support services for all
PetroCorp operations in the United States and Canada. The Agreement is subject
to shareholder approval, which is anticipated prior to year-end. The Company
also entered into an Interim Agreement with Kaiser-Francis to provide certain
services pending receipt of shareholder approval of the Management Agreement.
The Company recorded a $1.1 million restructuring charge, included in the
accompanying consolidated statement of operations, in the first quarter of 1999
related to the Company's pursuit of strategic alternatives
4
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to maximize shareholder value. Included in this charge are retention costs along
with severance pay related to a 20% reduction in personnel. Substantially all of
the $1.1 million charge was paid as of June 30, 1999, with the personnel
reduction occurring during the first quarter.
NOTE 3 - COMPREHENSIVE INCOME OR LOSS:
The Company implemented Statement of Financial Accounting Standards No. 130,
"Reporting Comprehensive Income," effective January 1, 1998. This statement
establishes new requirements for reporting comprehensive income or loss and the
components which include the Company's foreign currency translation. Adoption
of this statement has no impact on the Company's net income(loss) as presented
on the accompanying consolidated statement of operations. The Company's
comprehensive income(loss) for the three and six months ended June 30, 1999 and
1998 are as follows (amounts in thousands):
<TABLE>
<CAPTION>
For the three For the six
months ended months ended
June 30, June 30,
-------- --------
1999 1998 1999 1998
------ ------- ------ -------
<S> <C> <C> <C> <C>
Net income (loss) $ 483 $(1,029) $ (638) $(1,665)
Foreign currency translation income (loss) 697 (815) 1,090 (629)
------ ------- ------ -------
Comprehensive income (loss) $1,180 $(1,844) $ 452 $(2,294)
====== ======= ====== =======
</TABLE>
NOTE 4 - PROPERTY, PLANT AND EQUIPMENT:
The Company accounts for its oil and gas properties using the full cost
accounting rules promulgated by the Securities and Exchange Commission whereby
all productive and nonproductive exploration and development costs incurred for
the purpose of finding oil and gas reserves are capitalized. Such capitalized
costs include lease acquisition, geological and geophysical work, delay rentals,
drilling, completing and equipping oil and gas wells, together with internal
costs directly attributable to property acquisition, exploration and development
activities. No gains or losses are recognized upon the sale or other
disposition of oil and gas properties, except in unusually significant
transactions.
The costs of the Company's oil and gas properties, including estimated future
development and dismantlement costs, are depreciated on a country-by-country
basis using a composite unit-of-production rate. An additional valuation
adjustment is made on a country-by-country basis if net capitalized costs of the
Company's oil and gas properties exceed the capitalization ceiling, which is
calculated on a quarterly basis as the sum of (1) the present value (10%) of
future net revenues from estimated production of proved oil and gas reserves
plus (2) the lower of cost or estimated fair value of the unproved properties,
less (3) the related income tax effects.
NOTE 5 - DEFERRED REVENUE:
In March 1996, the Company sold its SW Oklahoma City Field gas gathering
system for $3.8 million. The Company's total gain on the sale was $3.1 million,
with $1.0 million being recognized in the first quarter of 1996 in "investment
and other income" on the consolidated statement of operations while the
remaining $2.1 million of the gain was deferred. The $2.1 million deferred
revenue will be recognized in future periods as a component of gas revenues by
partially offsetting the gas gathering fees paid by the
5
<PAGE>
Company over the productive life of the Company's SW Oklahoma City Field.
Through June 30, 1999, $2.0 million has been recognized, leaving a balance of
$80,000 in "deferred revenue" on the consolidated balance sheet as of June 30,
1999.
NOTE 6 - COMMITMENTS AND CONTINGENCIES:
There are claims and actions pending against the Company. In the opinion of
management, the amounts, if any, which may be awarded in connection with any of
these claims and actions would not be material to the Company's consolidated
financial position, results of operations or cash flows.
6
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
General
The Company's principal line of business is the production and sale of its oil
and natural gas reserves located in North America. Results of operations are
dependent upon the quantity of production and the price obtained for such
production. Prices received by the Company for the sale of its oil and natural
gas have fluctuated significantly from period to period. Such fluctuations
affect the Company's ability to maintain or increase its production from
existing oil and gas properties and to explore, develop or acquire new
properties.
The following table reflects certain operating data for the periods presented:
<TABLE>
<CAPTION>
FOR THE FOR THE
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
--------------------- ---------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
PRODUCTION:
United States:
Oil (MBbls) 76 99 164 220
Gas (MMcf) 1,152 1,134 2,388 2,298
Gas equivalents (MMcfe) 1,608 1,728 3,372 3,618
Canada:
Oil (MBbls) 36 41 69 73
Gas (MMcf) 1,109 1,122 2,188 2,224
Gas equivalents (MMcfe) 1,325 1,368 2,602 2,662
Total:
Oil (MBbls) 112 140 233 293
Gas (MMcf) 2,261 2,256 4,576 4,522
Gas equivalents (MMcfe) 2,933 3,096 5,974 6,280
AVERAGE SALES PRICES:
United States:
Oil (per Bbl) $15.61 $12.73 $13.14 $13.66
Gas (per Mcf) 2.22 2.24 1.99 2.22
Canada:
Oil (per Bbl) 14.73 11.51 12.94 12.11
Gas (per Mcf) 1.52 1.29 1.42 1.30
Weighted average:
Oil (per Bbl) 15.33 12.37 13.08 13.27
Gas (per Mcf) 1.88 1.77 1.72 1.77
SELECTED DATA PER BOE:
Average sales price $ 2.03 $ 1.85 $ 1.83 $ 1.89
Production costs 0.51 0.60 0.52 0.58
General and administrative expenses 0.28 0.37 0.31 0.37
Oil and gas depreciation, depletion and amortization 0.81 1.16 0.78 1.14
</TABLE>
7
<PAGE>
RESTRUCTURING
On November 16, 1998, the Company announced that its Board of Directors had
retained CIBC Oppenheimer Corp. to advise it with respect to strategic
alternatives available to the Company for maximizing shareholder value,
including sales of some or all of the Company's assets or a merger,
reorganization or other restructuring of the Company.
As part of its goal of maximizing shareholder value, the Company also
announced that its Board of Directors has adopted a Shareholder Rights Plan. The
newly adopted Shareholder Rights Plan is designed to protect the shareholder
against any effort to acquire the Company for less than its full value. However,
the Plan does not prevent a takeover. The intention of the Plan is to enable
shareholders to realize the long-term value of their investments and to enable
the Board of Directors to serve the interests of all shareholders. Under the
Plan, each shareholder of record at the close of business on November 23, 1998,
received one Series A Preferred Stock Purchase Right (Right) for each share of
Common Stock held. The Rights expire on November 12, 2008.
The Company opened a data room in February, 1999 and received expressions of
interest from third parties to purchase certain assets of, or merge with, the
Company. On May 21, 1999, the Company announced that it had rejected as
inadequate all proposals received. The Board of Directors, after consultation
with CIBC Oppenheimer, decided that the interests of all shareholders were best
served by not pursing a sale or merger at that time.
After consideration of other strategic alternatives, on August 3, 1999,
PetroCorp's Board of Directors entered into a Management Agreement with its
largest shareholder, Kaiser-Francis Oil Company, under which Kaiser-Francis will
provide management, technical and administrative support services for all
PetroCorp operations in the United States and Canada. The Agreement is subject
to shareholder approval, which is anticipated prior to year-end. The Company
also entered into an Interim Agreement with Kaiser-Francis to provide certain
services pending receipt of shareholder approval of the Management Agreement.
The Company incurred $1.1 million in restructuring costs during the first
quarter of 1999 in its pursuit of strategic alternatives to maximize shareholder
value (see discussion below). Additional restructuring costs are anticipated
during the second half of 1999 related to the implementation of the Management
Agreement with Kaiser-Francis.
Coupled with previously implemented cost reductions, the Management Agreement
is expected to reduce the Company's annual general and administrative costs
(before capitalization) by approximately $4.5 million, or $0.50 per share, from
1998 levels.
ACQUISITIONS
In June 1998, the Company acquired a position in a South Texas exploration and
development drilling alliance (the South Texas Acquisition). The acquisition
includes a working interest in the new discovery well in the Rich Hurt Field in
western Duval County. The alliance also controls approximately 25,000 acres in
Duval and Webb counties as well as the rights to more than 100 square miles of
new 3-D seismic data over the area.
The acquired Rich Hurt discovery well, along with three subsequently drilled
development wells, were producing at a combined rate of approximately 13 MMcf/D
at June 30, 1999. PetroCorp's net share of this production is approximately 1.7
MMcf/D. The alliance has identified more than 80 prospects/leads in this South
Texas area and currently has a leasehold position over 35 of these ideas.
8
<PAGE>
RESULTS OF OPERATIONS
Three Months Ended June 30, 1999 Compared to Three Months Ended June 30, 1998
Overview. The Company recorded second quarter 1999 net income of $483,000, or
$0.06 per share, compared to a net loss of $1.0 million, or $0.12 per share,
recorded in the second quarter of 1998. Additionally, the Company's cash flow
before changes in operating assets and liabilities increased 47% to $3.2 million
from $2.2 million in the second quarter of 1998. The improvements result from
lower operating expenses and higher oil and gas prices.
Revenues. Total revenues increased 6% to $6.5 million in the second quarter
of 1999 compared to $6.1 million in the second quarter of 1998. The Company's
natural gas production increased slightly to 2,261 MMcf from 2,256 MMcf but was
more than offset by a 20% decline in oil production to 112 MBbls from 140 Mbbls,
resulting in the Company's overall production declining 5% to 2,933 MMcfe from
3,096 MMcfe. The slight increase in natural gas production reflects the impact
of the South Texas Acquisition completed in June 1998 coupled with increases
resulting from new wells in Canada and the restoration of production in a South
Louisiana well. The decline in oil production reflects normal production
declines from two of the Company's oil properties.
The Company's composite average oil price increased 24% to $15.33 per barrel
in the second quarter of 1999 from $12.37 per barrel in the second quarter of
1998. The Company's average U.S. natural gas price decreased 1% to $2.22 per
Mcf in the second quarter of 1999 while the average Canadian natural gas price
increased 18% to $1.52 per Mcf from $1.29 per Mcf. The improvement in prices
partially offset by the decline in production volumes resulted in a 4% increase
in oil and gas revenues to $6.0 million in the second quarter of 1999 from $5.7
million in the prior year quarter.
Plant processing revenues increased 35% to $452,000 from $334,000, reflecting
the impact of new third party gas processed through the Company's Canadian
Hanlan-Robb gas processing plant.
Production Costs. Production costs decreased 19% to $1.5 million in the
second quarter of 1999 as a result of the Company's cost reduction efforts.
Production costs per Mcfe decreased 15% to $0.51 per Mcfe.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 31% to
$2.8 million in the second quarter of 1999 from $4.0 million in the second
quarter of 1998. The decrease reflects the impact of a lower U.S. DD&A rate
resulting from a U.S. oil and gas property valuation adjustment recorded in the
fourth quarter of 1998. Additionally, the composite oil and gas DD&A rate
decreased 30% to $0.81 per Mcfe from $1.16 per Mcfe.
General and Administrative Expenses. General and administrative expenses
decreased 29% to $821,000 million in the second quarter of 1999 from $1.2
million in the second quarter of 1998 as a result of the Company's focus on
reducing costs, including a 20% reduction in personnel in March 1999.
Investment and Other Income. Investment and other income decreased 6% to
$79,000 in the second quarter of 1999 from $84,000 in the second quarter of
1998.
Interest Expense. Interest expense increased 6% to $924,000 in the second
quarter of 1999 from $875,000 in the prior year quarter, reflecting the impact
of increased debt associated with the South Texas Acquisition completed in June
1998.
Income Taxes. The Company recorded a $55,000 income tax benefit on pre-tax
income of $428,000 in the second quarter of 1999. The Company's Canadian pre-
tax income more than offset a U.S. pre-tax
9
<PAGE>
loss, resulting in consolidated pre-tax income of $428,000. However, the
Canadian tax provision with a low effective tax rate of only 6% was more than
offset by a U.S. tax benefit with an effective tax rate of 39%, resulting in the
consolidated income tax benefit of $55,000. The Company recorded an income tax
benefit of $796,000 with an effective tax rate of 44% on a pre-tax loss of $1.8
million in the second quarter of 1998.
Six Months Ended June 30, 1999 Compared to Six Months Ended June 30, 1998
Overview. The Company recorded net income of $44,000, or $0.01 per share,
before restructuring charges, during the first six months of 1999. This
compares to a net loss of $1.7 million, or $0.19 per share, recorded in the
first six months of 1998. This improvement results from lower operating
expenses, though total revenues declined. The Company recorded a $1.1 million
($682,000 after-tax) restructuring charge in the first quarter of 1999.
Excluding the restructuring charge, the Company's cash flow before changes in
operating assets and liabilities increased 2% to $5.0 million.
Revenues. Total revenues decreased 6% to $11.9 million in the first six
months of 1999 compared to $12.6 million in the first six months of 1998. The
Company's natural gas production increased 1% to 4,576 MMcf from 4,522 MMcf but
was more than offset by a 20% decline in oil production to 233 MBbls from 293
Mbbls, resulting in the Company's overall production declining 5% to 5,974 MMcfe
from 6,280 MMcfe. The increase in natural gas production reflects the impact of
the South Texas Acquisition completed in June 1998 coupled with increases
resulting from new wells in Canada and the restoration of production in a South
Louisiana well. The decline in oil production reflects normal production
declines from two of the Company's oil properties.
The Company's composite average oil price decreased 1% to $13.08 per barrel in
the first six months of 1999. The Company's average U.S. natural gas price
decreased 10% to $1.99 per Mcf in the first six months of 1999 from $2.22 per
Mcf in the prior year period, while the average Canadian natural gas price
increased 12% to $1.42 per Mcf from $1.30 per Mcf. The decline in production
volumes coupled with the decline in the Company's U.S. gas price resulted in an
8% decrease in oil and gas revenues to $10.9 million in the first six months of
1999 from $11.9 million in the prior year period.
Plant processing revenues increased 34% to $906,000 from $677,000, reflecting
the impact of new third party gas processed through the Company's Canadian
Hanlan-Robb gas processing plant.
Production Costs. Production costs decreased 15% to $3.1 million in the first
six months of 1999 as a result of the Company's cost reduction efforts.
Production costs per Mcfe decreased 10% to $0.52 per Mcfe.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 31% to
$5.5 million in the first six months of 1999 from $8.0 million in the first six
months of 1998. The decrease reflects the impact of a lower U.S. DD&A rate
resulting from a U.S. oil and gas property valuation adjustment recorded in the
fourth quarter of 1998. Additionally, the composite oil and gas DD&A rate
decreased 32% to $0.78 per Mcfe from $1.14 per Mcfe.
General and Administrative Expenses. General and administrative expenses
decreased 20% to $1.9 million in the first six months of 1999 from $2.3 million
in the first six months of 1998 as a result of the Company's focus on reducing
costs, including a 20% reduction in personnel in March 1999.
Restructuring Costs. The Company recorded a $1.1 million restructuring charge
in the first quarter of 1999 related to the Company's pursuit of strategic
alternatives to maximize shareholder value. Included in this charge are
retention costs along with severance pay related to a 20% reduction in
personnel.
10
<PAGE>
Substantially all of the $1.1 million charge was paid as of June 30, 1999, with
the personnel reduction occurring during the first quarter.
Investment and Other Income. Investment and other income decreased 5% to
$167,000 in the first six months of 1999 from $176,000 in the first six months
of 1998.
Interest Expense. Interest expense increased 7% to $1.9 million in the first
six months of 1999 from $1.7 million in the prior year period, reflecting the
impact of increased debt associated with the South Texas Acquisition completed
in June 1998.
Income Taxes. The Company recorded an $888,000 income tax benefit with an
effective tax rate of 58% on a pre-tax loss of $1.5 million in the first six
months of 1999 (see Income Tax discussion for the second quarter of 1999). This
compares to an income tax benefit of $1.4 million with an effective tax rate of
45% on a pre-tax loss of $3.1 million in the first six months of 1998.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its capital expenditures and working
capital requirements with its cash flow from operations, debt and equity capital
and participation by institutional investors. As of June 30, 1999, the Company
had working capital of $2.4 million as compared to $2.1 million at December 31,
1998. Excluding the $1.1 million restructuring charge in the first quarter of
1999, cash provided by operating activities before changes in operating assets
and liabilities were $5.0 million and $4.9 million for the six months ended June
30, 1999 and 1998, respectively.
The Company's total capital expenditures, including capitalized internal
costs, were $1.5 million and $10.7 million for the six months ended June 30,
1999 and 1998, respectively.
No oil and gas property sales occurred in the first six months of 1999 while
sales of non-strategic properties totaled $1.9 million in the first six months
of 1998.
In March 1996, the Company sold its SW Oklahoma City Field gas gathering
system for $3.8 million. The Company's total gain on the sale was $3.1 million,
with $1.0 million being recognized in the first quarter of 1996 in "investment
and other income" on the consolidated statement of operations while the
remaining $2.1 million of the gain was deferred. The $2.1 million deferred
revenue will be recognized in future periods as a component of gas revenues by
partially offsetting the gas gathering fees paid by the Company over the
productive life of the Company's SW Oklahoma City Field. Through June 30, 1999,
$2.0 million has been recognized, leaving a balance of $80,000 in "deferred
revenue" on the consolidated balance sheet as of June 30, 1999.
In June 1997, the Company entered into a $50.0 million five-year revolving
credit agreement with the Toronto-Dominion Bank, the agent, and the Bank of Nova
Scotia. On June 30, 1997, the Company was advanced $13.0 million to fund an
acquisition of producing properties completed in early July 1997 and to fund
certain debt repayments. During 1998 and 1999, the Company borrowed $14.0
million to fund additional acquisitions and other debt repayments. At June 30,
1999, the Company had a total of $27.0 million outstanding under the revolver.
The facility was amended in June 1998 to extend the initial five-year term an
additional year to July 1, 2003 with quarterly borrowing base amortization
beginning September 30, 2001. The borrowings can be funded by either Eurodollar
loans or Prime loans. The interest rate on the borrowings is equal to an
interest rate spread plus either the Eurodollar rate or the Prime rate. The
interest spread is determined from a sliding scale based on the Company's
borrowing base percentage utilization in effect from time to time. Effective
July 1, 1999, the spread ranges from 1.375% to 2.0% on Eurodollar loans and
.375% to 1.0% on Prime loans. The Company's average interest rate under this
facility was
11
<PAGE>
approximately 6.3% during the first six months of 1999.
On December 30, 1996, the Company, through a wholly-owned Canadian subsidiary,
entered into a long-term borrowing agreement with the Royal Bank of Canada (RBC)
whereby the Company borrowed $3.5 million to partially fund the December 1996
acquisition of Millarville Oil and Gas Ltd., a privately held Alberta
corporation that owns and operates oil and gas properties in Alberta, Canada. On
June 29, 1998, this loan was repaid and the agreement was terminated. The
Company's average interest rate while the loan remained outstanding in 1998 was
6.6%.
In July 1993, PetroCorp issued $40.0 million in senior notes. The Note
Purchase Agreement established $10.0 million of Senior Adjustable Rate Notes
Series A, due June 30, 1999 (the Series A Notes), payable to a subsidiary of
USF&G Corporation (a 20% shareholder of the Company), and $30.0 million of 7.55%
Senior Notes Series B, due June 30, 2008 (the Series B Notes), payable to two
wholly-owned subsidiaries of CIGNA Corporation (formerly an 18% shareholder of
the Company) and to four unaffiliated institutional investors in amounts
totaling $20.0 million and $10.0 million, respectively. Mandatory redemptions
commenced on December 31, 1994 for the Series A Notes and commenced on December
31, 1995 for the Series B Notes. At June 30, 1999, the remaining principal
balance for the Series A Notes was paid off and the remaining balance of the
Series B Notes was $19.1 million. Current maturities of the Series B Notes
total $3.5 million. Interest on the Series A Notes was adjustable, based on a
spread of 115 basis points over the London Interbank Offered Rate (LIBOR).
Interest on the Series B Notes is fixed at a rate of 7.55% and is payable
semiannually in arrears.
The Note Purchase Agreement contains provisions that limit the Company's debt
levels based on undiscounted and discounted oil and gas reserves using the SEC's
rules, including the use of year-end prices held constant over the life of the
remaining reserves. Due to low oil and gas prices at December 31, 1998, the
Company was not in compliance with certain debt covenants of the Series A and
Series B Note Purchase Agreement at year-end. However, the note holders have
waived such provisions until January 1, 2000.
The Company's Canadian subsidiary redeemed its redeemable preferred stock on
August 9, 1994 for $7.0 million and simultaneously issued $7.0 million in
nonrecourse long-term notes payable with similar financial terms. At June 30,
1999, the nonrecourse long-term notes payable balance was $3.7 million, of which
$945,000 was classified as "current."
The Company plans to finance its substantially reduced 1999 capital
expenditures solely from available cash flow from operations and working
capital. If the Company increases its capital expenditure level in the future,
capital expenditures may require additional funding, obtained through borrowings
from commercial banks and other institutional sources, public offerings of
equity or debt securities and existing and future relationships with
institutional investment partners.
YEAR 2000 ISSUES
The Year 2000 presents significant issues for many computer systems. Much of
the hardware and software in use today may not be able to accurately process
data beyond the year 1999. The vast majority of computer systems process
transactions using two digits for the year of the transaction, rather than the
full four digits, making such systems unable to distinguish January 1, 2000 from
January 1, 1900. Such systems may encounter significant processing inaccuracies
or become inoperable when Year 2000 transactions are processed. Such matters
could not only impact the Company in its day-to-day operations but also impact
the Company's financial institutions, customers and vendors as well as state,
provincial and federal governments with jurisdictions where the Company
maintains operations.
PetroCorp has formed a Year 2000 compliance team and has been addressing Year
2000 issues since
12
<PAGE>
the fourth quarter of 1997. The Company's initial focus was on internal business
systems and processes. Beginning in August 1998, PetroCorp expanded its focus to
include its oil and gas operations systems and processes as well as assessing
the readiness of its key business partners (financial institutions, customers,
vendors, oil and gas operators, etc.).
It has been a PetroCorp strategy to use, wherever possible, industry prevalent
products and processes with minimal customization. As a result, PetroCorp does
not expect any extensive in-house hardware, software or process conversions in
an effort to be Year 2000 compliant nor does PetroCorp expect its Year 2000
compliance related costs to be material to the Company's operations. PetroCorp
has contacted its major information technology suppliers concerning their Year
2000 compliance status and is continuing to test (using available software
tools) these systems for compliance.
As previously mentioned, on August 3, 1999, PetroCorp's Board of Directors
entered into a Management Agreement with its largest shareholder, Kaiser-Francis
Oil Company, under which Kaiser-Francis will provide management, technical and
administrative support services for all PetroCorp operations. Such services
will also include the use of Kaiser-Francis' internal business systems and
processes which are currently estimated by Kaiser-Francis to be more than 98%
Year 2000 compliant. The Agreement is subject to shareholder approval, which is
anticipated prior to year-end.
The Company estimates that it is more than 95% complete in obtaining its goal
to be Year 2000 compliant by year-end and have contingency plans in place,
wherever possible, when compliance is not probable in a timely manner.
While it is PetroCorp's goal to be Year 2000 compliant, there can be no
assurance that there will not be a material adverse effect on the Company as a
result of a Year 2000 related issue. The Company believes its business partners
present the area of greatest risk to the Company, in part because of the
Company's limited ability to influence actions of third parties, and in part
because of the Company's inability to estimate the level and impact of
noncompliance of third parties. Additionally, there are many variables and
uncertainties associated with judgments regarding any contingency plans
developed by the Company.
THE ABOVE IS A YEAR 2000 READINESS DISCLOSURE UNDER THE "YEAR 2000 INFORMATION
AND READINESS DISCLOSURE ACT" 15 U.S.C. SEC. 1.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary sources of market risk are from fluctuations in
commodity prices, interest rates and exchange rates.
Commodity Price Risk
The Company produces and sells natural gas, crude oil, condensate, natural gas
liquids and sulfur. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response to
changing market forces. Prior to 1997, the Company utilized hedging transactions
to manage its exposure to price fluctuations on its sales of oil and natural
gas. No hedge transactions were in place in 1999 and 1998.
Interest Rate Risk
Total debt at June 30, 1999, included $22.8 million of fixed-rate debt
attributed to Series B Senior Notes and Nonrecourse Notes Payable, and $27.0
million of floating-rate debt attributed to the TD Bank Credit Agreement. As a
result, the Company's annual interest cost will fluctuate based on short-term
interest rates. The impact on annual cash flow of a 100 basis point change in
the floating rate would be
13
<PAGE>
approximately $270,000.
Foreign Currency Exchange Rate Risk
The Company conducts a significant portion of its business in the Canadian
dollar and is therefore subject to foreign currency exchange rate risk on cash
flows related to sales, expenses, financing and investing transactions. Exposure
from market rate fluctuations related to activities in Canada, where the
Company's functional currency is the Canadian dollar, is not material at this
time.
14
<PAGE>
PART II. OTHER INFORMATION
Item 1 - Legal Proceedings
Not Applicable
Item 2 - Changes in Securities
Not Applicable
Item 3 - Defaults upon Senior Securities
Not Applicable
Item 4 - Submission of Matters to Vote of Security Holders
Not Applicable
Item 5 - Other Information
Not Applicable
Item 6 -
(a) Exhibits
3.1* Amended and Restated Articles of Incorporation of PetroCorp
Incorporated. Incorporated by reference to Exhibit 3.2 to the
Registration Statement on Form S-1 (Registration No. 33-36972)
initially filed with the Securities and Exchange Commission on
August 26, 1993 (the "Registration Statement").
3.2* Amended and Restated Bylaws of PetroCorp Incorporated.
Incorporated by reference to Exhibit 3.2 to the Form 10-Q for the
quarterly period ended June 30, 1996.
27 Financial Data Schedule
______________________________
* Incorporated by reference.
(b) Reports on Form 8-K
Not Applicable
15
<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.
PETROCORP INCORPORATED
----------------------
(Registrant)
Date: August 13, 1999 /s/ CRAIG K. TOWNSEND
---------------- --------------------------
Craig K. Townsend
Vice President - Finance, Secretary and Treasurer
(On behalf of the Registrant and as the
Principal Financial Officer)
16
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITY EXCHANGE ACT OF
1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 3-MOS 6-MOS
<FISCAL-YEAR-END> DEC-31-1999 DEC-31-1999
<PERIOD-START> APR-01-1999 JAN-01-1999
<PERIOD-END> JUN-30-1999 JUN-30-1999
<CASH> 8,330 8,330
<SECURITIES> 0 0
<RECEIVABLES> 3,679 3,679
<ALLOWANCES> (50) (50)
<INVENTORY> 0 0
<CURRENT-ASSETS> 12,336 12,336
<PP&E> 233,050 233,050
<DEPRECIATION> (157,580) (157,580)
<TOTAL-ASSETS> 101,944 101,944
<CURRENT-LIABILITIES> 9,963 9,963
<BONDS> 0 0
0 0
0 0
<COMMON> 87 87
<OTHER-SE> 41,109 41,109
<TOTAL-LIABILITY-AND-EQUITY> 101,944 101,944
<SALES> 5,964 10,905
<TOTAL-REVENUES> 6,460 11,865
<CGS> 0 0
<TOTAL-COSTS> 5,187 11,698
<OTHER-EXPENSES> 0 1
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 924 1,859
<INCOME-PRETAX> 428 (1,526)
<INCOME-TAX> (55) (888)
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 483 (638)
<EPS-BASIC> 0.06 (0.07)
<EPS-DILUTED> 0.06 (0.07)
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