<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 September 30, 1998
------------------
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
-------
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 October 31, 1998:
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
<S> <C> <C>
Item 1. Financial Statements.
Consolidated Balance Sheet at September 30, 1998 and December 31, 1997 1
Consolidated Statement of Operations for the three months and nine months ended
September 30, 1998 and 1997 2
Consolidated Statement of Cash Flows for the nine months ended September 30, 1998
and 1997 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 Disclosure about Market Risk 13
PART II. OTHER INFORMATION 14
SIGNATURES 15
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEET
(in thousands, except share amounts)
SEPTEMBER 30, December 31,
1998 1997
---------- ---------
ASSETS (UNAUDITED)
Current assets:
Cash and cash equivalents $ 7,487 $ 9,391
Accounts receivable, net 3,510 6,608
Other current assets 327 337
---------- ---------
Total current assets 11,324 16,336
---------- ---------
Property, plant and equipment:
Proved oil and gas properties, at cost,
full cost method, net of accumulated
depreciation, depletion and amortization 98,807 99,038
Unproved oil and gas properties, not subject
to depletion 8,952 9,592
Plant and related facilities, net 3,860 3,922
Other, net 1,297 1,717
---------- ---------
112,916 114,269
---------- ---------
Other assets, net 178 319
---------- ---------
Total assets $ 124,418 $ 130,924
========== =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 4,330 $ 6,167
Accrued liabilities 3,727 3,345
Current portion of long-term debt 740 4,186
---------- ---------
Total current liabilities 8,797 13,698
---------- ---------
Long-term debt 47,120 42,192
---------- ---------
Deferred revenue 310 685
---------- ---------
Deferred income taxes 5,476 7,792
---------- ---------
Commitments and contingencies (Note 5)
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 shares and
8,616,216 shares issued as of September 30,
1998 and December 31, 1997, respectively 87 86
Additional paid-in capital 71,245 71,143
Retained earnings (accumulated deficit) (2,358) 71
Accumulated other comprehensive loss (6,259) (4,496)
Treasury stock, at cost (nil and 24,697
shares as of September 30, 1998 and
December 31, 1997, respectively - (247)
---------- ---------
Total shareholders' equity 62,715 66,557
---------- ---------
Total liabilities and shareholders' equity $ 124,418 $ 130,924
========== =========
The accompanying notes are an integral part of this statement.
1
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands, except per share amounts)
(Unaudited)
<TABLE>
<CAPTION>
For the three months For the nine months
ended September 30, ended September 30,
--------------------- -----------------------
1998 1997 1998 1997
------- ------- -------- --------
<S> <C> <C> <C> <C>
REVENUE:
Oil and gas $ 5,827 $ 8,337 $ 17,717 $ 24,478
Plant processing 340 354 1,017 1,075
Other 6 47 30 165
------- ------- -------- --------
6,173 8,738 18,764 25,718
------- ------- -------- --------
EXPENSES:
Production costs 1,779 1,945 5,431 5,516
Depreciation, depletion and amortization 4,277 4,397 12,245 12,314
General and administrative 1,126 1,076 3,459 3,605
Other operating expenses 97 96 183 301
------- ------- -------- --------
7,279 7,514 21,318 21,736
------- ------- -------- --------
INCOME (LOSS) FROM OPERATIONS (1,106) 1,224 (2,554) 3,982
------- ------- -------- --------
OTHER INCOME (EXPENSES):
Investment and other income 669 116 845 404
Interest expense (937) (975) (2,676) (2,565)
Other expenses 38 (1) (1) (3)
------- ------- -------- --------
(230) (860) (1,832) (2,164)
------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES (1,336) 364 (4,386) 1,818
Income tax provision (benefit) (572) 137 (1,957) 372
------- ------- -------- --------
NET INCOME (LOSS) $ (764) $ 227 $ (2,429) $ 1,446
======= ======= ======== ========
Net income (loss) per common share - basic $ (0.09) $ 0.03 $ (0.28) $ 0.17
======= ======= ======== ========
Net income (loss) per common share - diluted $ (0.09) $ 0.03 $ (0.28) $ 0.17
======= ======= ======== ========
Weighted average number of common shares - basic 8,649 8,586 8,630 8,586
Weighted average number of common shares - diluted 8,685 8,689 8,699 8,684
</TABLE>
The accompanying notes are an integral part of this statement.
2
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
For the nine months
ended September 30,
--------------------
1998 1997
-------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (2,429) $ 1,446
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Depreciation, depletion and amortization 12,245 12,314
Deferred income tax provision (benefit) (1,957) 372
-------- --------
7,859 14,132
Change in operating assets and liabilities:
Accounts receivable 3,098 2,694
Other current assets 10 (71)
Accounts payable (1,837) (1,194)
Accrued liabilities 382 (519)
Other (253) (534)
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 9,259 14,508
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (15,177) (22,134)
Additions to plant and related facilities (789) (201)
Additions to other property, plant and equipment (67) (155)
Additions to other assets (8) (198)
Proceeds from sale of oil and gas properties 2,786 --
-------- --------
NET CASH USED IN INVESTING ACTIVITIES (13,255) (22,688)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 10,442 13,145
Repayment of long-term debt (8,621) (2,919)
Other 350 --
-------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES 2,171 10,226
-------- --------
Effect of exchange rate changes on cash (79) (13)
-------- --------
Net increase (decrease) in cash and cash equivalents (1,904) 2,033
Cash and cash equivalents at beginning of period 9,391 8,859
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 7,487 $ 10,892
======== ========
</TABLE>
The accompanying notes are an integral part of this statement.
3
<PAGE>
PETROCORP INCORPORATED
----------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
(Unaudited)
NOTE 1 - BASIS OF PRESENTATION AND OTHER:
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, 1997, included in the Company's 1997 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.
In May 1998, the Company acquired net profit interests in certain oil and
gas properties for $550,000 and received a note receivable in exchange for
$925,000 which was secured by certain working interests in the properties. In
June, upon the purchase of the related working interests in the properties, the
payment for the net profit interests and the note receivable were netted against
the total acquisition price for final settlement. Accordingly, the net profit
interests and the note receivable were terminated. As the note receivable was
issued by the Company with the intention of ultimately offsetting the note's
proceeds against the acquisition price, the Company has treated the $925,000
proceeds payable upon the issuance of the note as an oil and gas investing
activity in the Consolidated Statement of Cash Flows for the nine months ended
September 30, 1998.
On June 15, 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133 is effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999 for certain companies
(January 1, 2000 for the Company). SFAS 133 requires that all derivative
instruments be recorded on the balance sheet at their fair value. Changes in the
fair value of derivatives are recorded each period in current earnings or other
comprehensive income (only certain types of hedge transactions are reported as a
component of other comprehensive income). Additionally, for all hedge
transactions the nature and type of hedge should be disclosed. Management of the
Company anticipates that, due to its limited use of derivative instruments, the
adoption of SFAS 133 will not have a significant effect on the Company's results
of operations or its financial position.
Certain prior-period amounts have been reclassified to conform to the
current-year presentation.
4
<PAGE>
NOTE 2 - COMPREHENSIVE INCOME:
The Company implemented SFAS No. 130, "Reporting Comprehensive Income,"
effective January 1, 1998. This statement establishes new requirements for
reporting comprehensive income and its components which includes 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 months and nine months ended September 30, 1998 and 1997 are as follows
(amounts in thousands):
<TABLE>
<CAPTION>
For the three For the nine
months ended months ended
September 30, September 30,
------------- -------------
1998 1997 1998 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
Net income (loss) $ (764) $ 227 $(2,429) $1,446
Foreign currency translation (1,134) 1 (1,763) (178)
------- ----- ------- ------
Comprehensive income (loss) $(1,898) $ 228 $(4,192) $1,268
======= ===== ======= ======
</TABLE>
NOTE 3 - 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.
Product prices declined significantly during the first nine months of 1998
and continue to be volatile subsequent to September 30, 1998. Companies that
follow the full cost accounting method are required to make the quarterly
"ceiling test" calculations using product prices in effect at that time. In the
future, should product prices decline further and depending on drilling results,
the Company could be required to record a valuation adjustment to its oil and
gas property balances, resulting in a non-cash charge against earnings.
5
<PAGE>
NOTE 4 - 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 Company over the
productive life of the Company's SW Oklahoma City Field. Through September 30,
1998, $1.8 million has been recognized, leaving a balance of $310,000 in
"deferred revenue" on the consolidated balance sheet as of September 30, 1998.
NOTE 5 - COMMITMENTS AND CONTINGENCIES:
There are claims and actions pending against the Company in the ordinary
course of its operations. 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 or results of
operations.
NOTE 6 - SUBSEQUENT EVENTS:
On November 16, 1998, the Company announced that its Board of Directors has
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,
will receive one Series A Preferred Stock Purchase Right (Right) for each share
of Common Stock held. The Rights expire on November 12, 2008.
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 three For the nine
months ended months ended
September 30, September 30,
--------------- ----------------
1998 1997 1998 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
PRODUCTION:
United States:
Oil (MBbls) 106 160 326 451
Gas (MMcf) 1,266 1,356 3,564 3,528
Oil equivalents (MBOE) 317 386 920 1,039
Canada:
Oil (MBbls) 34 38 107 108
Gas (MMcf) 1,159 1,193 3,383 3,530
Oil equivalents (MBOE) 227 237 671 696
Total:
Oil (MBbls) 140 198 433 559
Gas (MMcf) 2,425 2,549 6,947 7,058
Oil equivalents (MBOE) 544 623 1,591 1,735
AVERAGE SALES PRICES:
United States:
Oil (per Bbl) $12.21 $18.61 $13.19 $19.81
Gas (per Mcf) 2.14 2.36 2.19 2.46
Canada:
Oil (per Bbl) 11.44 15.81 11.90 18.28
Gas (per Mcf) 1.24 1.30 1.28 1.39
Weighted average:
Oil (per Bbl) 12.03 18.07 12.87 19.51
Gas (per Mcf) 1.71 1.87 1.75 1.92
SELECTED DATA PER BOE:
Average sales price $10.71 $13.38 $11.14 $14.11
Production costs 3.27 3.12 3.41 3.18
General and administrative expenses 2.07 1.73 2.17 2.08
Oil and gas depreciation, depletion and amortization 7.18 6.42 6.94 6.36
</TABLE>
7
<PAGE>
ACQUISITION
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. It is anticipated that the alliance will
drill approximately one well per month throughout the remainder of 1998 and into
1999.
The acquired Rich Hurt discovery well, along with two subsequently drilled
development wells, are now producing at a combined rate of approximately of 23
million cubic feet of natural gas per day. PetroCorp's net share of this current
production is approximately 3.0 million cubic feet of natural gas per day.
Additional exploration activity is continuing on other prospects.
RESULTS OF OPERATIONS
Three Months Ended September 30, 1998 Compared to Three Months Ended
September 30, 1997
Overview. Primarily resulting from a 33% decline in oil prices and a 9%
decline in gas prices, coupled with a 13% decrease in production volumes, cash
flow before changes in operating assets and liabilities decreased 38% to $2.9
million in the third quarter of 1998. This compares to $4.8 million in the third
quarter of 1997. Additionally, the Company recorded a net loss of $764,000, or
$0.09 per share, in the third quarter of 1998 compared to net income of
$227,000, or $0.03 per share, recorded in the prior year.
Though the Company experienced a decline in its production during the third
quarter of 1998 compared to the third quarter of 1997, third quarter 1998
production was up 4% from the second quarter of this year and the Company
anticipates that its fourth quarter volumes will be up 6% compared to the second
quarter. The increase in the third quarter came primarily from new gas
production in South Texas, while expected increases in the fourth quarter should
come primarily from the South Texas area, as well as new production in the
Mcleod area of Canada and restored production in South Louisiana.
Revenues. Total revenues decreased 29% to $6.2 million in the third quarter
of 1998 compared to $8.7 million in the third quarter of 1997. Oil and gas
revenues decreased by 30% to $5.8 million in the third quarter of 1998 from $8.3
million in the prior year quarter as a result of the lower oil and gas prices,
coupled with the lower production volumes.
The Company's oil production decreased 29% to 140 MBbls while its natural
gas production decreased 5% to 2,425 MMcf for an overall decline in production
of 13% to 544 MBOE from 623 MBOE. The decrease in oil production reflects normal
production declines at the Hunter waterflood unit located in northern Oklahoma
and the Maynor Creek field in Mississippi. Though the Company had increases in
gas production from the South Texas Acquisition and new wells in the U.S. and
Canada, third quarter 1998 gas production decreased. This decrease reflects the
impact of lower gas volumes resulting from an unexpected mechanical problem,
which has since been remedied, in a significant gas well located in South
Louisiana, non-stratigic property sales and natural production declines.
The Company's composite average oil price decreased 33% to $12.03 per
barrel in the third quarter of 1998 from $18.07 per barrel in the third quarter
of 1997. The Company's average U.S. natural gas price decreased 9% to $2.14 per
Mcf in the third quarter of 1998 from $2.36 per Mcf in the prior year third
quarter, while the average Canadian natural gas price decreased 5% to $1.24 per
Mcf from $1.30 per Mcf.
8
<PAGE>
Production Costs. Production costs decreased 9% to $1.8 million in the
third quarter of 1998 while production costs per BOE increased 5% to $3.27 per
BOE from $3.12 per BOE. The decrease in absolute dollars reflects the Company's
continued effort to reduce operating costs and includes reductions in the
Company's Hanlan gas processing plant expense as a result of fees collected from
third parties which began processing gas through the Hanlan plant in August
1998. The increase in costs per BOE reflects the impact of lower production
volumes.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 3% to
$4.3 million in the third quarter of 1998 from $4.4 million in the third quarter
of 1997. Decreases from lower production volumes were partially offset by a 12%
increase in the oil and gas DD&A rate to $7.18 per BOE from $6.42 per BOE.
General and Administrative Expenses. General and administrative expenses
remained almost level at $1.1 million between quarters.
Investment and Other Income. Investment and other income increased
significantly to $669,000 in the third quarter of 1998 from $116,000 in the
third quarter of 1997. The Company recorded an additional $536,000 in the third
quarter of 1998 related to settlement of a gas contract dispute and other items.
Interest Expense. Interest expense decreased 4% to $937,000 in the third
quarter of 1998 from $975,000 in the prior year quarter, reflecting the impact
of slightly lower debt levels in the third quarter of 1998.
Income Taxes. The Company recorded a $572,000 income tax benefit with an
effective tax rate of 43% on a pre-tax loss of $1.3 million in the third quarter
of 1998 compared to an income tax provision of $137,000 with an effective tax
rate of 38% on a pre-tax income of $364,000 in the third quarter of 1997.
Nine Months Ended September 30, 1998 Compared to Nine Months Ended
September 30, 1997
Overview. Primarily resulting from a 34% decrease in oil prices and a 9%
decrease in gas prices, coupled with an 8% decrease in production volumes, cash
flow before changes in operating assets and liabilities decreased 44% to $7.9
million during the first nine months of 1998. This compares to $14.1 million
in the first nine months of 1997. Additionally, the Company recorded a net loss
of $2.4 million, or $0.28 per share, in the first nine months of 1998 compared
to net income of $1.4 million, or $0.17 per share, recorded in the prior year.
Though the Company experienced a decline in its production during the first
nine months of 1998 compared to the first nine months of 1997, third quarter
1998 production was up 4% from the second quarter of this year, and the Company
anticipates that its fourth quarter volumes will be up 6% compared to the second
quarter. The increase in the third quarter came primarily from new gas
production in South Texas, while expected increases in the fourth quarter should
come primarily from the South Texas area, as well as new production in the
Mcleod area of Canada and restored production in South Louisiana.
Revenues. Total revenues decreased 27% to $18.8 million in the first
nine months of 1998 compared to $25.7 million in the first nine months of 1997.
Oil and gas revenues decreased 28% to $17.7 million in the first nine months of
1998 from $24.5 million in the prior year period as a result of
9
<PAGE>
the lower oil and gas prices, coupled with the lower production volumes.
The Company's oil production decreased 23% to 433 MBbls while its natural
gas production decreased 2% to 6,947 MMcf for an overall decline in production
of 8% to 1,591 MBOE from 1,735 MBOE. The decreased oil production reflects
normal production declines at the Hunter waterflood unit located in northern
Oklahoma and the Maynor Creek field in Mississippi. Though the Company had
increases in gas production from the South Texas Acquisition and new wells in
the U.S. and Canada, gas production decreased. The decrease reflects the impact
of lower gas volumes resulting from an unexpected mechanical problem, which has
since been remedied, in a significant gas well located in South Louisiana, non-
stratigic property sales and natural production declines.
The Company's composite average oil price decreased 34% to $12.87 per
barrel in the first nine months of 1998 from $19.51 per barrel in the first nine
months of 1997. The Company's average U.S. natural gas price decreased 11% to
$2.19 per Mcf in the first nine months of 1998 from $2.46 per Mcf in the prior
year period, while the average Canadian natural gas price decreased 8% to $1.28
per Mcf from $1.39 per Mcf.
Production Costs. Production costs decreased 2% to $5.4 million in the
first nine months of 1998 while production costs per BOE increased 7% to $3.41
per BOE from $3.18 per BOE. The decrease in absolute dollars reflects the
Company's continued effort to reduce operating costs and includes reductions in
the Company's Hanlan gas processing plant expense as a result of fees collected
from third parties which began processing gas through the Hanlan plant in
August 1998. The increase in costs per BOE reflect the impact of lower
production volumes.
Depreciation, Depletion & Amortization (DD&A). Total DD&A remained almost
level at $12.2 million in the first nine months of 1998. Decreases from lower
production volumes were offset by a 9% increase in the oil and gas DD&A rate to
$6.94 per BOE from $6.36 per BOE.
General and Administrative Expenses. General and administrative expenses
decreased 4% to $3.5 million in the first nine months of 1998 from $3.6 million
in the first nine months of 1997 as a result of the Company's focus on reducing
costs.
Investment and Other Income. Investment and other income increased
significantly to $845,000 in the first nine months of 1998 from $404,000 in the
first nine months of 1997. The Company recorded an additional $536,000 in the
third quarter of 1998 related to settlement of a gas contract dispute and other
items.
Interest Expense. Interest expense increased 4% to $2.7 million in the
first nine months of 1998 from $2.6 million in the prior year period, reflecting
the impact of increased debt associated with a producing property acquisition in
July 1997.
Income Taxes. The Company recorded a $2.0 million income tax benefit with
an effective tax rate of 45% on a pre-tax loss of $4.4 million in the first nine
months of 1998 compared to an income tax provision of $372,000 with an effective
tax rate of 20% on pre-tax income of $1.8 million in the first nine months of
1997. The lower prior period effective tax rate reflects certain adjustments
related to the Company's Canadian income taxes.
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
10
<PAGE>
September 30, 1998, the Company had working capital of $2.5 million as compared
to $2.6 million at December 31, 1997. Cash provided by operating activities
before changes in operating assets and liabilities were $7.9 million and $14.1
million for the nine months ended September 30, 1998 and 1997, respectively.
The Company's total capital expenditures, including capitalized internal
costs, were $16.0 million and $22.7 million for the nine months ended September
30, 1998 and 1997, respectively. During the first nine months of 1998, the
Company spent $9.4 million related to exploration and development and $4.4
million related to acquisitions. In the first nine months of 1997, the Company
spent $11.2 million related to exploration and development and $9.5 million
related to acquisitions.
Sales of non-strategic oil and gas properties totaled $2.8 million in the
first nine months of 1998 while there were no property sales in the first nine
months of 1997.
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 September 30,
1998, $1.8 million has been recognized, leaving a balance of $310,000 in
"deferred revenue" on the consolidated balance sheet as of September 30, 1998.
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 producting properties completed in early July 1997 and to fund
certain debt repayments. Since year-end, the Company borrowed $8.0 million to
fund additional acquisitions and other debt repayments. At September 30,1998,
the Company had a total of $21.0 million outstanding under the revolver, all
being classified as "long-term." 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. The spread ranges from 7/8% to 1 1/2% on Eurodollar
loans and nil to 1/2% on Prime loans. The Company's average interest rate under
this facility was approximately 6.8% during the first nine months of 1998.
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
11
<PAGE>
December 31, 1995 for the Series B Notes. As of September 30, 1998, the
remaining principal balances for the Series A and B Notes were $1.7 million and
$21.5 million, respectively, for a total of $23.2 million, of which $4.1 matures
in the next twelve months. Interest on the Series A Notes is adjustable, based
on a spread of 115 basis points over the London Interbank Offered Rate (LIBOR).
The Company may select a rate which may be applicable for a one-, three- or six-
month period. Interest is payable in arrears at the end of the selected period.
Interest on the Series B Notes is fixed at a rate of 7.55% and is payable
semiannually in arrears.
As the Company has both the ability and intent to refinance $4.1 million of
its current maturities of long-term debt utilizing its revolving credit
facility, $4.1 million has been reclassified from "current" to "long-term" on
the Company's accompanying consolidated balance sheet as of September 30, 1998.
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 September
30, 1998, the nonrecourse long-term notes payable balance was $3.7 million, of
which $740,000 was classified as "current."
Product prices declined significantly during the first nine months of 1998
and continue to be volatile subsequent to September 30, 1998. Under rules
promulgated by the Securities and Exchange Commission, companies that follow the
full cost accounting method are required to make quarterly "ceiling test"
calculations, by country, using product prices in effect at that time (see Note
3 to the Consolidated Financial Statements: Property, Plant and Equipment). In
the future, should prices decline further and depending on drilling results, the
Company could be required to record a valuation adjustment to its oil and gas
property balances, resulting in a non-cash charge against earnings.
The Company's Board of Directors has approved a capital budget of $12.0
million for 1998. The approved 1998 capital budget includes expenditures for
exploration and development projects, excluding capitalized internal costs, and
for producing property acquisitions, net of property sales. However, actual
levels of expenditures for planned exploration and development projects and
producing property acquisitions may vary significantly due to many factors,
including drilling results, oil and gas prices, industry conditions and
acquisition opportunities, among others.
The Company plans to finance its 1998 capital expenditures with its cash
flow from operations, borrowings under its bank revolver, and working capital.
If the Company increases its exploration, development and acquisition activities
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 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.
The Company's goal is to be Year 2000 compliant by March 31, 1999 wherever
possible and have contingency plans in place where compliance is not possible 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.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
The information discussed herein includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of historical
facts included herein regarding planned capital expenditures, increases in oil
and gas production, the number of anticipated wells to be drilled after the date
hereof, the Company's financial position, business strategy and other plans and
objectives for future operations, are forward-looking statements. Although the
Company believes that the expectations reflected in such forward-looking
statements are reasonable, they do involve certain assumptions, risks and
uncertainties, and the Company can give no assurance that such expectations will
prove to have been correct. The Company's actual results could differ materially
from those anticipated in these forward-looking statements as a result of
certain factors. Among the factors that could cause actual results to differ
materially are the timing and success of the company's drilling activities, the
volatility of the prices and supply and demand for oil and gas, the numerous
uncertainties inherent in estimating quantities of oil and gas reserves and
actual future production rates and associated costs, the usual hazards
associated with the oil and gas industry (including blowouts, cratering, pipe
failure, spills, explosions and other unforeseen hazards), and increases in
regulatory requirements, as well as other risks described more fully in the
Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1997
filed with the SEC.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not Applicable
13
<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
14
<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: November 16, 1998 /s/ CRAIG K. TOWNSEND
--------------------- --------------------------
Craig K. Townsend
Vice President - Finance, Secretary and Treasurer
(On behalf of the Registrant and as the
Principal Financial Officer)
15
<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 SEPTEMBER 30, 1998 AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 3-MOS 9-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1998
<PERIOD-START> JUL-01-1998 JAN-01-1998
<PERIOD-END> SEP-30-1998 SEP-30-1998
<CASH> 7,487 7,487
<SECURITIES> 0 0
<RECEIVABLES> 3,560 3,560
<ALLOWANCES> (50) (50)
<INVENTORY> 0 0
<CURRENT-ASSETS> 11,324 11,324
<PP&E> 226,919 226,919
<DEPRECIATION> (114,003) (114,003)
<TOTAL-ASSETS> 124,418 124,418
<CURRENT-LIABILITIES> 8,797 8,797
<BONDS> 0 0
0 0
0 0
<COMMON> 87 87
<OTHER-SE> 62,628 62,628
<TOTAL-LIABILITY-AND-EQUITY> 124,418 124,418
<SALES> 5,827 17,717
<TOTAL-REVENUES> 6,173 18,764
<CGS> 0 0
<TOTAL-COSTS> 7,279 21,318
<OTHER-EXPENSES> (38) 1
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 937 2,676
<INCOME-PRETAX> (1,336) (4,386)
<INCOME-TAX> (572) (1,957)
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> (764) (2,429)
<EPS-PRIMARY> (0.09) (0.28)
<EPS-DILUTED> (0.09) (0.28)
</TABLE>
