<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, 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
Incorporation or Organization) (I.R.S. Employer Identification No.)
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, 1998:
Common Stock, $.01 per value 8,656,019
---------------------------- ---------
(Title of Class) (Number of Shares Outstanding)
<PAGE>
PETROCORP INCORPORATED
INDEX
<TABLE>
<CAPTION>
PAGE NO.
----------
<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Balance Sheet at June 30, 1998 and December 31, 1997 1
Consolidated Statement of Operations for the three months and 2
six months ended June 30, 1998 and 1997
Consolidated Statement of Cash Flows for the six months ended 3
June 30, 1998 and 1997
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)
JUNE 30, December 31,
1998 1997
-------- ------------
ASSETS (UNAUDITED)
------
Current assets:
Cash and cash equivalents $ 5,680 $ 9,391
Accounts receivable, net 4,327 6,608
Other current assets 245 337
-------- --------
Total current assets 10,252 16,336
-------- --------
Property, plant and equipment:
Proved oil and gas properties, at cost,
full cost method, net of accumulated
depreciation, depletion and amortization 101,774 99,038
Unproved oil and gas properties, not
subject to depletion 9,091 9,592
Plant and related facilities, net 3,819 3,922
Other, net 1,449 1,717
-------- --------
116,133 114,269
-------- --------
Other assets, net 204 319
-------- --------
Total assets $126,589 $130,924
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable $ 3,959 $ 6,167
Accrued liabilities 3,423 3,345
Current portion of long-term debt 772 4,186
-------- --------
Total current liabilities 8,154 13,698
-------- --------
Long-term debt 47,094 42,192
-------- --------
Deferred revenue 459 685
-------- --------
Deferred income taxes 6,269 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 June 30,
1998 and December 31, 1997, respectively 87 86
Additional paid-in capital 71,245 71,143
Retained earnings (accumulated deficit) (1,594) 71
Accumulated other comprehensive income
(loss) (5,125) (4,496)
Treasury stock, at cost (nil and 24,697
shares as of June 30, 1998 and December 31,
1997, respectively) - (247)
-------- --------
Total shareholders' equity 64,613 66,557
-------- --------
Total liabilities and shareholders'
equity $126,589 $130,924
========= ========
The accompanying notes are an integral part of this statement.
1
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PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands, except per share amounts)
(Unaudited)
For the three months For the six months
ended June 30, ended June 30,
-------------------- ------------------
1998 1997 1998 1997
-------- -------- -------- --------
REVENUES:
Oil and gas $ 5,717 $7,166 $11,890 $16,141
Plant processing 334 357 677 721
Other 34 63 24 118
------- ------ ------- -------
6,085 7,586 12,591 16,980
------- ------ ------- -------
EXPENSES:
Production costs 1,863 1,753 3,652 3,571
Depreciation, depletion and
amortization 4,017 4,070 7,968 7,917
General and administrative 1,155 1,273 2,333 2,529
Other operating expenses 48 89 86 205
------- ------ ------- -------
7,083 7,185 14,039 14,222
------- ------ ------- -------
INCOME (LOSS) FROM OPERATIONS (998) 401 (1,448) 2,758
------- ------ ------- -------
OTHER INCOME (EXPENSES):
Investment and other income 84 132 176 288
Interest expense (875) (796) (1,739) (1,590)
Other expenses (36) 5 (39) (2)
------- ------ ------- -------
(827) (659) (1,602) (1,304)
------- ------ ------- -------
INCOME (LOSS) BEFORE INCOME
TAXES (1,825) (258) (3,050) 1,454
Income tax provision (benefit) (796) (502) (1,385) 235
------- ------ ------- -------
NET INCOME (LOSS) $(1,029) $ 244 $(1,665) $ 1,219
======= ====== ======= =======
Net income (loss) per common
share - basic $ (0.12) $ 0.03 $ (0.19) $ 0.14
======= ====== ======= =======
Net income (loss) per common
share - diluted $ (0.12) $ 0.03 $ (0.19) $ 0.14
======= ====== ======= =======
Weighted average number of
common shares - basic 8,642 8,585 8,617 8,585
Weighted average number of
common shares - diluted 8,714 8,680 8,698 8,687
The accompanying notes are an integral part of this statement.
2
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PETROCORP INCORPORATED
----------------------
CONSOLIDATED STATEMENT OF CASH FLOWS
------------------------------------
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
For the six months
ended June 30,
---------------------
1998 1997
--------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (1,665) $ 1,219
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization 7,968 7,917
Deferred income tax provision (benefit) (1,385) 235
--------- --------
4,918 9,371
Change in operating assets and liabilities:
Accounts receivable 2,281 3,079
Other current assets 92 (40)
Accounts payable (2,208) (2,030)
Accrued liabilities 78 (538)
Other (229) (369)
--------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 4,932 9,473
--------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (12,107) (8,598)
Additions to plant and related facilities (386) (100)
Additions to other property, plant and equipment (58) (107)
Additions to other assets (5) (1,275)
Proceeds from sale of oil and gas properties 1,896 -
--------- --------
NET CASH USED IN INVESTING ACTIVITIES (10,660) (10,080)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 10,117 13,112
Repayment of long-term debt (8,442) (2,728)
Other 350 -
--------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES 2,025 10,384
--------- --------
Effect of exchange rate changes on cash (8) (14)
--------- --------
Net increase (decrease) in cash and cash equivalents (3,711) 9,763
Cash and cash equivalents at beginning of period 9,391 8,859
--------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 5,680 $ 18,622
========= ========
</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 interest 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 six months ended
June 30, 1998.
On June 15, 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). 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
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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 six months ended June 30, 1998 and 1997 are as follows (amounts
in thousands):
For the three For the six
------------- -----------
months ended months ended
------------ ------------
June 30, June 30,
-------- --------
1998 1997 1998 1997
---- ---- ---- ----
Net income (loss) $(1,029) $ 244 $(1,665) $1,219
Foreign currency translation (815) 60 (629) (179)
------- ----- ------- ------
Comprehensive income (loss)
$(1,844) $ 304 $(2,294) $1,040
======= ===== ======= ======
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 six months of 1998
and continue to be volatile subsequent to June 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 June 30, 1998,
$1.6 million has been recognized, leaving a balance of $459,000 in "deferred
revenue" on the consolidated balance sheet as of June 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.
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,
--------------- ---------------
1998 1997 1998 1997
------ ------ ------ ------
<S> <C> <C> <C> <C>
PRODUCTION:
United States:
Oil (MBbls)........................................... 99 142 220 291
Gas (MMcf)............................................ 1,134 1,056 2,298 2,172
Oil equivalents (MBOE)................................ 288 318 603 653
Canada:
Oil (MBbls)........................................... 41 38 73 70
Gas (MMcf)............................................ 1,122 1,343 2,224 2,337
Oil equivalents (MBOE)................................ 228 262 444 460
Total:
Oil (MBbls)........................................... 140 180 293 361
Gas (MMcf)............................................ 2,256 2,399 4,522 4,509
Oil equivalents (MBOE)................................ 516 580 1,047 1,113
AVERAGE SALES PRICES:
United States:
Oil (per Bbl)......................................... $12.73 $18.86 $13.66 $20.47
Gas (per Mcf)......................................... 2.24 2.08 2.22 2.51
Canada:
Oil (per Bbl)......................................... 11.51 18.47 12.11 19.62
Gas (per Mcf)......................................... 1.29 1.18 1.30 1.43
Weighted average:
Oil (per Bbl)......................................... 12.37 18.78 13.27 20.31
Gas (per Mcf)......................................... 1.77 1.58 1.77 1.95
SELECTED DATA PER BOE:
Average sales price.................................... $11.08 $12.36 $11.36 $14.50
Production costs....................................... 3.61 3.02 3.49 3.21
General and administrative expenses.................... 2.24 2.19 2.23 2.27
Oil and gas depreciation, depletion and amortization... 6.95 6.25 6.81 6.32
</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 in excess of 30 million
cubic feet of natural gas per day. PetroCorp's net share of this current
production is equivalent to 12% of the Company's average daily production during
the first half of 1998. Additional exploration activity is continuing on other
prospects.
RESULTS OF OPERATIONS
Three Months Ended June 30, 1998 Compared to Three Months Ended June 30, 1997
Overview. As a result of a 34% decline in oil prices, partially offset by a
12% increase in gas prices, coupled with a 11% decrease in production volumes,
cash flow before changes in operating assets and liabilities decreased 42% to
$2.2 million in the second quarter of 1998. This compares to $3.8 million in
the second quarter of 1997. Additionally, the Company recorded a net loss of
$1.0 million, or $0.12 per share, in the second quarter of 1998 compared to net
income of $244,000, or $0.03 per share, recorded in the prior year.
Though the Company experienced a decline in its production during the second
quarter of 1998, the Company anticipates that its production volumes for the
third and fourth quarters will be up significantly from the second quarter
volumes. The Company currently expects that production in the second half of
1998 will increase 17% over first half levels. The increase is expected to come
mainly from new gas production from the South Texas Acquisition along with new
production in the McLeod area in Canada, pending the negotiation and tie-in to a
nearby gas processing plant.
Revenues. Total revenues decreased 20% to $6.1 million in the second quarter
of 1998 compared to $7.6 million in the second quarter of 1997. Oil and gas
revenues also decreased by 20% to $5.7 million in the second quarter of 1998
from $7.2 million in the prior year quarter as a result of the lower oil prices,
partially offset by the higher gas prices, coupled with the lower production
volumes.
The Company's oil production decreased 22% to 140 MBbls while its natural gas
production decreased 6% to 2,256 MMcf for an overall decline in production of
11% to 516 MBOE from 580 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. Second quarter 1998 gas production
reflects the impact of lower gas volumes resulting from a plant turnaround
located in the Hanlan-Robb area in Canada and an unexpected mechanical problem
in a significant gas well located in South Louisiana.
The Company's composite average oil price decreased 34% to $12.37 per barrel
in the second quarter of 1998 from $18.78 per barrel in the second quarter of
1997. The Company's average U.S. natural gas price increased 8% to $2.24 per
Mcf in the second quarter of 1998 from $2.08 per Mcf in the prior year second
quarter, while the average Canadian natural gas price increased 9% to $1.29 per
Mcf from $1.18 per Mcf.
Production Costs. Production costs increased 6% to $1.9 million in the
second quarter of 1998
8
<PAGE>
while production costs per BOE increased 20% to $3.61 per BOE from $3.02 per
BOE. The increase in absolute dollars reflects increased costs associated with
the plant turn-around in the Hanlan-Robb Area in the second quarter of 1998.
The increase in costs per BOE reflect both the increased costs related to the
plant turn-around as well as the lower production volumes.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 1% to
$4.0 million in the second quarter of 1998 from $4.1 million in the second
quarter of 1997. Decreases from lower production volumes were partially offset
by an 11% increase in the oil and gas DD&A rate to $6.95 per BOE from $6.25 per
BOE.
General and Administrative Expenses. General and administrative expenses
decreased 9% to $1.2 million in the second quarter of 1998 from $1.3 million in
the second quarter of 1997 as a result of the Company's focus on reducing costs.
Investment and Other Income. Investment and other income decreased 36% to
$84,000 in the second quarter of 1998 from $132,000 in the second quarter of
1997 as less funds were available for investment.
Interest Expense. Interest expense increased 10% to $875,000 in the second
quarter of 1998 from $796,000 in the prior year quarter, reflecting the impact
of increased debt associated with a producing property acquisition in July 1997.
Income Taxes. The Company recorded a $796,000 income tax benefit with an
effective tax rate of 44% on a pre-tax loss of $1.8 million in the second
quarter of 1998 compared to an income tax benefit of $502,000 with an effective
tax rate of 195% on a pre-tax loss of $258,000 in the second quarter of 1997.
The higher prior period effective tax rate reflects certain adjustments related
to the Company's Canadian income taxes.
Six Months Ended June 30, 1998 Compared to Six Months Ended June 30, 1997
Overview. As a result of a 35% decrease in oil prices and a 9% decrease in
gas prices, coupled with a 6% decrease in production volumes, cash flow before
changes in operating assets and liabilities decreased 48% to $4.9 million during
the first six months of 1998. This compares to $9.4 million in the first six
months of 1997. Additionally, the Company recorded a net loss of $1.7 million,
or $0.19 per share, in the first six months of 1998 compared to net income of
$1.2 million, or $0.14 per share, recorded in the prior year.
Though the Company experienced a decline in its production during the first
six months of 1998, the Company anticipates that its production for the second
half of 1998 will increase 17% over first half levels. The increase is expected
to come mainly from new gas production from the South Texas Acquisition along
with new production in the McLeod area in Canada, pending the negotiation and
tie-in to a nearby gas processing plant.
Revenues. Total revenues decreased 26% to $12.6 million in the first six
months of 1998 compared to $17.0 million in the first six months of 1997. Oil
and gas revenues also decreased 26% to $11.9 million in the first six months of
1998 from $16.1 million in the prior year period as a result of the lower oil
and gas prices, coupled with the lower production volumes.
Though the Company's natural gas production remained level at 4,522 MMcf, oil
production declined 19% to 293 MBbls from 361 MBbls resulting in an overall
decrease in production of 6% to 1,047 MBOE from 1,113 MBOE. Though natural gas
production increased as a result of an acquisition completed in July
9
<PAGE>
of last year in addition to increases from recently drilled wells, the increases
were offset by decreases elsewhere. Lower gas volumes resulted from the plant
turnaround in the Hanlan-Robb area of Canada. In addition, lower gas volumes
resulted due to an unexpected mechanical problem with a gas well located in
South Louisiana and natural production declines. The decreased oil production
reflects normal production declines at the Hunter waterflood unit located in
northern Oklahoma and the Maynor Creek field in Mississippi.
The Company's composite average oil price decreased 35% to $13.27 per barrel
in the first six months of 1998 from $20.31 per barrel in the first six months
of 1997. The Company's average U.S. natural gas price decreased 12% to $2.22
per Mcf in the first six months of 1998 from $2.51 per Mcf in the prior year
period, while the average Canadian natural gas price decreased 9% to $1.30 per
Mcf from $1.43 per Mcf.
Production Costs. Production costs increased 2% to $3.7 million in the first
six months of 1998 while production costs per BOE increased to $3.49 per BOE
from $3.21 per BOE. The increase in absolute dollars reflects increased costs
associated with the plant turn-around in the Hanlan-Robb Area in the second
quarter of 1998. The increase in costs per BOE reflects both the increased
costs related to the plant turn-around as well as the lower production volumes.
Depreciation, Depletion & Amortization (DD&A). Total DD&A remained almost
level at $8.0 million in the first six months of 1998. Decreases from lower
production volumes were offset by an 8% increase in the oil and gas DD&A rate to
$6.81 per BOE from $6.32 per BOE.
General and Administrative Expenses. General and administrative expenses
decreased 8% to $2.3 million in the first six months of 1998 from $2.5 million
in the first six months of 1997 as a result of the Company's focus on reducing
costs.
Investment and Other Income. Investment and other income decreased 39% to
$176,000 in the first six months of 1998 from $288,000 in the first six months
of 1997 as less funds were available for investment.
Interest Expense. Interest expense increased 9% to $1.7 million in the first
six months of 1998 from $1.6 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 $1.4 million income tax benefit with an
effective tax rate of 45% on a pre-tax loss of $3.1 million in the first six
months of 1998 compared to an income tax provision of $235,000 with an effective
tax rate of 16% on pre-tax income of $1.5 million in the first six 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 June 30, 1998, the Company
had working capital of $2.1 million as compared to $2.6 million at December 31,
1997. Cash provided by operating activities before changes in operating assets
and liabilities were $4.9 million and $9.4 million for the six months ended June
30, 1998 and 1997, respectively.
The Company's total capital expenditures, including capitalized internal
costs, were $12.6 million and $10.1 million for the six months ended June 30,
1998 and 1997, respectively. During the first six months of 1998, the Company
spent $6.8 million related to exploration and development and $4.4 million
related
10
<PAGE>
to acquisitions. In the first six months of 1997, the Company spent $7.3
million related to exploration and development with an additional $1.1 million
deposit included in "other assets" related to a producing property acquisition
which closed on July 1, 1997.
Sales of non-strategic oil and gas properties totaled $1.9 million in the
first six months of 1998 while there were no property sales in the first six
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 June 30, 1998,
$1.6 million has been recognized, leaving a balance of $459,000 in "deferred
revenue" on the consolidated balance sheet as of June 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 the
Gulf Coast Acquisition and certain debt repayments. Since year-end, the Company
borrowed $8.0 million to fund additional acquisitions and other debt
repayments. At June 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 6.5%
during the first six 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 under this facility was 6.6% during the first
six months of 1998.
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. As of June 30, 1998, the remaining principal
balances for the Series A and B Notes were $1.8 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
11
<PAGE>
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 June 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 June 30,
1998, the nonrecourse long-term notes payable balance was $3.7 million, of which
$771,000 was classified as "current."
Product prices declined significantly during the first six months of 1998 and
continue to be volatile subsequent to June 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. The Company's Management is in the process
of identifying or remediating Year 2000 issues and does not expect any issues to
arise that would materially impact the Company's financial condition or
operations.
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
12
<PAGE>
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
(a) May 7, 1998 annual meeting of shareholders.
(b) (1) Election of Directors
Number of Votes
-----------------------------------------------------
Abstentions and
Nominee For Withheld Authority Broker Non-Votes
- -------------------- --------- --------------------- ----------------
W. Neil McBean 8,117,323 4,080 --
Thomas N. Amonett 8,117,323 4,080 --
Robert C. Thomas 8,117,323 4,080 --
- ----------------------------------------------------------------------------
(2) Ratification of the Reappointment of Price Waterhouse LLP as the
Company's independent accountants for the fiscal year ending December 31,
1998.
Number of Votes
- --------------------------------------------------------------------------------
Abstentions and
For Against Broker Non-Votes
- ------------ ------- ----------------
8,119,723 600 1,080
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: August 14, 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 JUNE 30, 1998.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 3-MOS 6-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1998
<PERIOD-START> APR-01-1998 JAN-01-1998
<PERIOD-END> JUN-30-1998 JUN-30-1998
<CASH> 5,680 5,680
<SECURITIES> 0 0
<RECEIVABLES> 4,377 4,377
<ALLOWANCES> (50) (50)
<INVENTORY> 0 0
<CURRENT-ASSETS> 10,252 10,252
<PP&E> 226,487 226,487
<DEPRECIATION> (110,354) (110,354)
<TOTAL-ASSETS> 126,589 126,589
<CURRENT-LIABILITIES> 8,154 8,154
<BONDS> 0 0
0 0
0 0
<COMMON> 87 87
<OTHER-SE> 64,526 64,526
<TOTAL-LIABILITY-AND-EQUITY> 126,589 126,589
<SALES> 5,717 11,890
<TOTAL-REVENUES> 6,085 12,591
<CGS> 0 0
<TOTAL-COSTS> 7,083 14,039
<OTHER-EXPENSES> 36 39
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 875 1,739
<INCOME-PRETAX> (1,825) (3,050)
<INCOME-TAX> (796) (1,385)
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> (1,029) (1,665)
<EPS-PRIMARY> (0.12) (0.19)
<EPS-DILUTED> (0.12) (0.19)
</TABLE>
