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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K/A
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 1998
or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from to
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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
Suite 300, North Atrium 77060-2391
Houston, Texas (Zip Code)
(Address of principal executive
offices)
Registrant's telephone number, including area code: (281) 875-2500
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Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.01 per share
(Title of class)
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 for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. [X] Yes [_] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K ((S)(S) 229.045 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of April 9, 1999 was $18,766,807. Indicate the number of shares
outstanding of each of the registrant's classes of common stock, as of April 9,
1999:
Common Stock, par value $.01 per share: 8,656,019
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held in 1999 (to be filed within 120 days of the close of registrant's fiscal
year) is incorporated by reference into Part III.
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
Item Title Page
---- ----- ----
PART I
<C> <S> <C>
1 Business.......................................................... 1
2 Properties........................................................ 7
3 Legal Proceedings................................................. 15
4 Submission of Matters to a Vote of Security Holders............... 15
PART II
5 Market for Registrant's Common Equity and Related Stockholder
Matters........................................................... 15
6 Selected Financial Data........................................... 16
7 Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 17
7A Quantitative and Qualitative Disclosure about Market Risk......... 23
8 Financial Statements and Supplementary Data....................... 24
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 24
PART III
10-13 (Items 10-13 incorporated by reference to Proxy Statement)........ 24
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 24
</TABLE>
As used in this report, "Bbl" means barrel, "MBbls" means thousand barrels,
"MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "BOPD" means barrel of oil
per day, "Mcf/D" means thousand cubic feet per day, "MMcf/D" means million
cubic feet per day, "Mcfe" means thousand cubic feet of natural gas equivalent
determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,
"MMcfe" means million cubic feet of natural gas equivalents, "Bcfe" means one
billion cubic feet of natural gas equivalents, "Tcf" means one trillion cubic
feet, "PV-10" means estimated pretax present value of future net revenues
discounted at 10% using SEC rules, "gross" wells or acres are the wells or
acres in which the Company has a working interest, and "net" wells or acres are
determined by multiplying gross wells or acres by the Company's working
interest in such wells or acres.
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PART I
Item 1. Business.
General
PetroCorp Incorporated is an independent energy company engaged in the
acquisition, exploration and development of oil and gas properties, and in the
production of oil and natural gas in North America. The Company's activities
are conducted principally in the states of Oklahoma, Texas, Mississippi,
Louisiana and Kansas, and in the province of Alberta, Canada.
At December 31, 1998, the Company's proved reserves totaled 4.0 MMBbls of oil
and 79.4 Bcf of natural gas and had an estimated pretax present value of future
net revenues (PV-10) of $78 million. On a Mcfe basis, approximately 75% of the
Company's proved reserves were natural gas at such date. In addition, the
Company has unproved interest holdings with a net book value of $9.2 million,
as well as interests in natural gas processing and gathering facilities with a
net book value of $3.8 million.
The Company was formed in July 1983 as a Delaware corporation and in December
1986 contributed its assets to a newly formed Texas general partnership. In
October 1992, the Company changed its legal form from a Texas general
partnership to a Texas corporation. PetroCorp's principal executive offices are
located at 16800 Greenspoint Park Drive, Suite 300, North Atrium, Houston,
Texas 77060, and its telephone number is (281) 875-2500. Unless the context
otherwise requires, the terms the "Company" and "PetroCorp" refer to and
include PetroCorp Incorporated, its predecessor entities (including the
original Delaware corporation and the subsequent Texas general partnership) and
all subsidiaries in which PetroCorp owns a 50% or greater interest.
Business Strategy
PetroCorp and its Canadian, wholly-owned PCC Energy subsidiaries acquire,
explore and develop oil and natural gas properties in North America.
Acquisition Strategy. The Company has grown, in large part, through the
acquisition of producing oil and gas properties. The Company generally focuses
on acquisitions of long-lived natural gas reserves, located onshore in North
America, and prefers acquisitions that provide additional potential through
development or exploitation efforts, as well as exploratory drilling
opportunities.
Exploration and Development Strategy. Exploration and development activities
are an important component of PetroCorp's business strategy. In recent years,
the Company has allocated greater capital and management resources to
exploration and development activities, increased the personnel and
technological capabilities (including the use of 3D seismic technology)
available to its exploration and development teams, and developed major
exploration and development projects in South Texas, Mississippi, Oklahoma, and
Alberta, Canada. PetroCorp has the capability to perform some reprocessing, as
well as all visualization and interpretation of its seismic database completely
in-house.
Recent Acquisition Activity
South Texas Acquisition. In June 1998, PetroCorp acquired a significant
position in a strategic exploration and development drilling alliance in South
Texas. Partners include Mobil Exploration & Producing U.S. Inc. and J.M. Huber
Corporation. The acquisition included a 17.5% working interest in 25,000 acres
controlled by the alliance (primarily in Duval County, Texas), as well as
rights to more than 100 square miles of new 3D seismic data over the area. The
program has already yielded its first significant new field discovery. At year-
end 1998, the Rich Hurt Field in Duval County was producing 24 MMcf/D from four
successful Wilcox completions.
1
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Exploration and Development Activities
South Texas Wilcox Play. The Company has devoted significant manpower and
technical expertise to its recent South Texas Acquisition, completed in June
1998 (see South Texas Acquisition in preceding section). Primary targets in
this area are Wilcox sand intervals at depths ranging from 8,000 to 13,000
feet. Since committing to the acquisition, PetroCorp has participated in four
successful wells out of seven total drilled. The four successful wells are
completed in an area now defined as the Rich Hurt Field in Duval County and
were producing at a combined rate of 24 MMcf/D at year-end 1998. To date, the
Company had received approximately 80 square miles of the 100+ square miles of
3D seismic data currently committed to by the alliance. The three-company
alliance has identified more than 80 prospects/leads in the area and currently
has a leasehold position over 35 of these ideas.
Southwest Oklahoma City Unit Waterflood. Discovered in 1987, the PetroCorp
operated Southwest Oklahoma City Field is located in an established production
trend bounded by the Wheatland-Will Rogers Airport Field complex to the
southwest and the Oklahoma City Field to the east. The Company operates 61
wells in the field and has a working interest in two additional wells in the
area. Since 1996, activity has focused on implementation of waterflood
activities at the SW Oklahoma City Unit, targeting a Prue sand interval at
6,500 feet. PetroCorp owns an 86.4% working interest in this unit, which is
showing a positive response to injection consistent with initial expectations
and offset analogs.
Mississippi Salt Basin. The Mississippi Salt Basin is one of PetroCorp's
significant exploration plays. Through year-end 1998, the Company had drilled
five exploratory prospects in Wayne, Greene and Smith Counties, yielding two
new field discoveries and seven successful wells out of 10 total wells drilled.
Since 1997, PetroCorp has been involved in a seismic joint venture with a
subsidiary of Shell Oil Company which give the Company access to Shell's
extensive database, including 13,000 line miles of 2D seismic, covering 18
counties.
Hanlan-Robb Area. Located in the foothills of the Canadian Rockies in western
Alberta, the Hanlan-Robb area is the largest in terms of reserves and
production, in PetroCorp's property portfolio. The Company owns an interest in
ten fields in this area, covering 47,000 developed acres with current combined
gross production of 220 MMcf/D. PetroCorp has an interest in 73,900 undeveloped
acres in this area. Recent activity in the area has focused on the sidetracking
of existing vertical wells and the installation of field compression for the
Hanlan Swan Hills Gas Unit #1 (a 1.4 Tcf EUR gas field). PetroCorp also
participated in two horizontal re-drills in the Shaw/Basing area which have
more than doubled gross production from the Company's acreage to 24 MMcf/D.
PetroCorp has access to a substantial amount of seismic and other data covering
the Hanlan-Robb properties and has continued to participate in additional
seismic surveys in the area. PetroCorp's technical team is actively engaged in
analyzing such data to identify further development and exploration
opportunities.
PetroCorp owns a 24.5% working interest in the centrally located Hanlan-Robb
gas processing plant and varying interests in a gas gathering system that
connects all of the Company's currently producing Hanlan-Robb fields to the
plant. The original design capacity of the plant was recently expanded to 380
MMcf/D. Two new major pipeline systems capable of transporting gas to the plant
from an area of approximately 2,400 square miles have recently begun delivering
third-party gas to the plant for processing. This new third-party gas, for
which processing fees are received, has increased plant throughput from 220
MMcf/D to approximately 300 MMcf/D at year-end 1998. As a result of the
increased plant throughput and third-party processing revenue, total operating
costs for PetroCorp have been reduced from $0.15/Mcf in 1998 to an anticipated
$0.06/Mcf for 1999. The Company also has adequate excess capacity
(approximately 22 MMcf/D in 1999) in the plant for its exploration and
development plans in the area.
Minehead Prospect. Located ten miles east of the Hanlan-Robb Gas Plant, the
Minehead exploratory prospect exposes the Company to significant reserve
additions. Targeting the Swan Hills formation, the
2
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prospect is on trend with the Blackstone Field (1.0 Tcf) and the Hanlan Unit
(1.4 Tcf). A well testing the concept was drilling at year-end 1998, at no cost
to the Company. PetroCorp owns a 2.3% Gross Overriding Royalty in this
exploratory well, convertible to a 9.4% working interest upon payout of the
well, as well as a 9.4% working interest in the 12,800 surrounding leased
acres. The well is expected to reach total depth by April 1999.
McLeod Field. As part of an acquisition in late 1996, the Company acquired
one shut-in oil well in this field in west central Alberta, Canada. Since then,
the PetroCorp has drilled six wells to develop production from three
formations. The Company's working interests vary from 12% to 100% in 8.8
sections (approximately 5,600 acres).
Production and Sales
The following table presents certain information with respect to oil and gas
production attributable to the Company's properties, average sales price
received and average production costs during the three years ended December 31,
1998, 1997, and 1996. See Note 11 to the Consolidated Financial Statements of
the Company and "Supplemental Information to the Consolidated Financial
Statements" in the Notes thereto included elsewhere in this report for
additional financial information regarding the Company's foreign and domestic
operations.
<TABLE>
<CAPTION>
Year Ended December
31,
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1998 1997 1996
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<S> <C> <C> <C>
Net oil produced (MBbls):
United States........................................... 422 580 662
Canada.................................................. 143 142 5
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Total................................................. 565 722 667
Average oil sales price (per Bbl):
United States........................................... $12.55 $19.57 $19.89
Canada.................................................. 11.59 17.19 23.12
Weighted average........................................ 12.31 19.10 19.91
Net gas produced (MMcf):
United States........................................... 4,932 4,853 5,155
Canada.................................................. 4,579 4,787 3,182
------ ------ ------
Total................................................. 9,511 9,640 8,337
Average gas sales price (per Mcf):
United States........................................... $ 2.15 $ 2.62 $ 2.36
Canada.................................................. 1.32 1.46 1.34
Weighted average........................................ 1.75 2.04 1.97
Gas equivalents produced (MMcfe):
United States........................................... 7,464 8,333 9,127
Canada.................................................. 5,437 5,639 3,212
------ ------ ------
Total................................................. 12,901 13,972 12,339
Average sales price (per Mcfe):
United States........................................... $ 2.13 $ 2.89 $ 2.78
Canada.................................................. 1.42 1.67 1.36
Weighted average........................................ 1.83 2.39 2.41
Production costs (per Mcfe):
United States........................................... $ .69 $ .73 $ .65
Canada.................................................. .40 .30 .23
Weighted average........................................ .57 .56 .54
</TABLE>
3
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Marketing
PetroCorp's United States gas production is sold to a variety of pipelines,
marketing companies and utility end users, typically under short-term contracts
ranging in length from one month to one year. During 1998, the majority of the
Company's Canadian gas was dedicated under long-term contracts to Pan-Alberta
Gas Ltd. (Pan-Alberta), a major Canadian gas aggregator and marketer, which was
affiliated with the pipeline authorized to gather all gas in the province of
Alberta. Under these contracts, approximately 75% of the Company's Canadian gas
was resold into the United States, predominantly to markets in the upper
Midwest region. PetroCorp received a price, per Mcf, from Pan-Alberta equal to
their resale price, less certain costs.
PetroCorp, along with other Canadian producers, reached a legal settlement
with Pan-Alberta in December 1998 that has changed the fundamental ownership
structure of Pan-Alberta. Effective December 31, 1998, Pan-Alberta is now owned
by 435 Canadian producers (including PetroCorp). The contractual relationship
between the 435 pool producers and Pan-Alberta has not changed, but all costs
and benefits from Pan-Alberta's marketing efforts now pass directly to the
producers. As part of the settlement, approximately 50% of PetroCorp's
dedicated gas volumes have been released from the Pan-Alberta contracts. These
released volumes are now sold on the spot market at prevailing prices.
PetroCorp's domestic crude oil and condensate production is sold to a variety
of purchasers typically on a monthly contract basis at posted field prices or
NYMEX prices, as determined by major buyers. In particular areas, where
production volumes are significant or the location is desirable for a
particular purchaser, or both, the Company has successfully negotiated bonuses
over the purchaser's general field postings for its production.
During the year ended December 31, 1998, Pan-Alberta, Conoco Inc. (the
purchaser of a portion of the Company's U.S. gas) and EOTT Energy Operated
Limited Partnership (one of the Company's purchasers of oil) accounted for 23%,
10% and 10% of the Company's total sales, respectively. The Company does not
believe the loss of any purchaser would have a material adverse effect on its
financial position since the Company believes alternative sales arrangements
could be made on relatively comparable terms.
In general, prices of oil and gas are dependent on numerous factors beyond
the control of the Company, such as competition, international events and
circumstances (including actions taken by the Organization of Petroleum
Exporting Countries (OPEC)), and certain economic, political and regulatory
developments. Since demand for natural gas is generally highest during winter
months, prices received for the Company's natural gas are subject to seasonal
variations.
Hedging Activities
Prior to 1997, the Company utilized hedging transactions to manage its
exposure to price fluctuations in crude oil and natural gas. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
Note 13 to the Consolidated Financial Statements.
Competition
The oil and gas industry is highly competitive. The Company competes in
acquisitions and in the exploration, development, production and marketing of
oil and gas with major oil companies, larger independent oil and gas concerns
and individual producers and operators. Many of these competitors have
substantially greater financial and other resources than the Company.
4
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Regulation
United States
General. The Company's business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation and tax laws.
For example, state and federal agencies have issued rules and regulations that
require permits for the drilling of wells, regulate the spacing of wells,
prevent the waste of reserves through proration, and regulate oilfield and
pipeline environmental and safety matters. Changes in any of these laws could
have a material adverse effect on the Company's business, and the Company
cannot predict the overall effects of such laws and regulations on its future
operations. Although these regulations have an impact on the Company and
others in the oil and gas industry, the Company does not believe that it is
affected in a significantly different manner by these regulations than are its
competitors in the oil and gas industry.
The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.
Regulation of Transportation and Sale of Natural Gas and Oil. Various
aspects of the Company's oil and gas operations are regulated by agencies of
the federal government. The transportation of natural gas in interstate
commerce is generally regulated by the Federal Energy Regulatory Commission
(FERC) pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas
Policy Act of 1978 (NGPA). The intrastate transportation and gathering of
natural gas (and operational and safety matters related thereto) may be
subject to regulation by state and local governments.
In the past, the federal government regulated the prices at which the
Company's produced oil and gas could be sold. Currently, "first sales" of
natural gas by producers and marketers, and all sales of crude oil, condensate
and natural gas liquids, can be made at uncontrolled market prices, but
Congress could reenact price controls at any time.
Within the past decade, the FERC has issued numerous orders and policy
statements designed to create a more competitive environment in the national
natural gas marketplace, including orders promoting "open-access"
transportation on natural gas pipelines subject to the FERC's NGA and NGPA
jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed
to restructure the interstate natural gas transportation and marketing system
and to promote competition within all phases of the natural gas industry.
Among other things, Order 636 required interstate pipelines to separate the
transportation of gas from the sale of gas, to change the manner in which
pipeline rates were designed and to implement other changes intended to
promote the growth of market centers. Subsequent FERC initiatives have
attempted to standardize interstate pipeline business practices and to allow
pipelines to implement market-based, negotiated and incentive rates. The
restructured services implemented by Order 636 and successor orders have now
been in effect for a number of winter heating seasons and have significantly
affected the manner in which natural gas (both domestic and foreign) is
transported and sold to consumers.
Although Order 636 has generally been upheld in judicial appeals to date,
petitions for court review are still pending and it is not possible to predict
the ultimate outcome of such appeals or the effect, if any, of future
restructuring orders or policies on the Company's operations. In addition,
FERC has recently announced that it will convene in the near future a public
conference to consider whether FERC's current approach to regulation of the
natural gas industry should be changed and whether further refinements or
changes to existing policies should be made in view of developments in the
natural gas industry since Order 636 was originally issued. Although FERC has
indicated that it remains committed to Order 636's "fundamental goal" of
"improving the competitive structure of the natural gas industry in order to
maximize the benefits of wellhead decontrol," the future regulatory goals and
priorities of FERC may be altered as a result of such conference and related
inquiries. FERC's policies may also be impacted by the ongoing restructuring
of the electric power industry pursuant to FERC Order No. 888.
5
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While Order 636 and related orders do not directly regulate either the
production or sale of gas that may be produced from the Company's properties,
the increased competition and changes in business practices within the natural
gas industry resulting from such orders have affected the terms and conditions
under which the Company markets and transports its available gas supplies. To
date, the FERC's pro-competition policies have not materially affected the
Company's business or operations. On a prospective basis, however, such orders
may substantially increase the burden on producers and transporters to
accurately nominate and deliver on a daily basis specified volumes of natural
gas, or to bear penalties or increased costs in the event scheduled deliveries
are not made.
Environmental Regulation. Various federal, state and local laws and
regulations governing the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs. In particular, the Company's exploration,
exploitation and production operations, its activities in connection with
storage and transportation of crude oil and other liquid hydrocarbons and its
use of facilities for treating, processing or otherwise handling hydrocarbons
and wastes therefrom are subject to stringent environmental regulation.
Although compliance with these regulations increases the cost of Company
operations, such compliance has not in the past had a material effect on the
Company's capital expenditures, earnings or competitive position. Environmental
regulations have historically been subject to frequent change by regulatory
authorities. The recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation has
been proposed in Congress from time to time that would reclassify certain oil
and gas exploration and production wastes as "hazardous wastes," which would
make the reclassified wastes subject to much more stringent handling, disposal
and cleanup requirements. If such legislation were to be enacted, it could have
a significant impact on the operating costs of the Company, as well as the oil
and gas industry in general. Also under consideration at the federal level are
laws and regulations that would require owners and operators of oil and gas
facilities to meet an environmental "financial responsibility requirement"
(with current proposals ranging from $35 million to $150 million) that could
have a significant adverse impact on small oil and gas companies like
PetroCorp. State initiatives to further regulate the disposal of oil and gas
wastes are also pending in certain states, and these various initiatives could
have a similar impact on the Company. The Company is unable to predict the
ongoing cost to it of complying with these laws and regulations or the future
impact of such regulations on its operation. Management believes that the
Company is in substantial compliance with current applicable environmental laws
and regulations and that continued compliance with existing requirements will
not have a material adverse impact on the Company. A catastrophic discharge of
hydrocarbons into the environment could, to the extent such event is not
insured, subject the Company to substantial expense.
Canada
In Canada, the petroleum industry operates under federal, provincial and
municipal legislation and regulations governing taxes, land tenure, royalties,
production rates, environmental protection, exports and other matters. Prices
of oil and natural gas in Canada have been deregulated and are determined by
market conditions and negotiations between buyers and sellers, although oil
production volumes are regulated. Various matters relating to the
transportation and distribution of natural gas are the subject of hearings
before various regulatory tribunals. In addition, although the price of natural
gas exported from Canada is subject to negotiation between buyers and sellers,
the National Energy Board, which regulates exports of natural gas, requires
that natural gas export contracts meet certain criteria as a condition of
approving such contracts. These criteria, including price considerations, are
designed to demonstrate that the export is in the Canadian public interest.
Several provincial governments have introduced a number of programs to
encourage and assist the oil and natural gas industry, including incentive
payments, royalty holidays and royalty tax credits. Canadian governmental
regulations may have a material effect on the economic parameters for engaging
in oil and gas activities in Canada and may have a material effect on the
advisability of investments in Canadian oil and gas drilling activities.
6
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Employees
At December 31, 1998, PetroCorp had 53 full-time employees.
Item 2. Properties.
Principal Properties
The Company's proved oil and gas properties are relatively concentrated.
Approximately 78% of the PV-10 from the Company's proved reserves at December
31, 1998 was attributable to five principal areas.
The following table presents data regarding the estimated quantities of
proved oil and gas reserves and the PV-10 attributable to the Company's
principal properties as of December 31, 1998, all of which are taken from
reports prepared by Huddleston & Co., Inc. in accordance with the rules and
regulations of the Securities and Exchange Commission (SEC).
<TABLE>
<CAPTION>
December 31, 1998
---------------------------------
Estimated Proved
Reserves
----------------------
Oil Gas
Property/Area (MBbls) (MMcf) MMcfe PV-10
------------- ------- ------ ------- ----------
(in
thousands)
<S> <C> <C> <C> <C>
Hanlan-Robb............................. 108 50,157 50,805 $37,972
South Louisiana Area.................... 118 5,330 6,038 9,797
Oklahoma City Area...................... 1,644 3,120 12,984 5,510
McLeod Field............................ 568 4,536 7,944 5,394
South Texas Area........................ 24 1,939 2,083 2,537
----- ------ ------- -------
Subtotal.............................. 2,462 65,082 79,854 61,210
----- ------ ------- -------
Others.................................. 1,528 14,310 23,478 17,270
----- ------ ------- -------
Total................................. 3,990 79,392 103,332 $78,480
===== ====== ======= =======
</TABLE>
Hanlan-Robb. PetroCorp's largest single producing area is the Hanlan-Robb
natural gas production complex located in the foothills region of western
Alberta, Canada, which accounted for 40% of the Company's 1998 net daily gas
production. The Company owns an interest in ten producing fields in this area,
covering 47,000 developed acres, with current combined production of 220
MMcf/D. PetroCorp has additional interests in 73,900 undeveloped acres in this
area. The key field is the world-class Hanlan Swan Hills Gas Unit #1, with an
estimated ultimate recovery of 1.4 Tcf and current gross production of 160
MMcf/D. PetroCorp's ownership is part of a joint venture managed by the Company
with institutional investors that collectively own 21.6% of the field.
PetroCorp's working interest in this field is 35% of the joint venture, or
7.6%. Petro-Canada (not an affiliate of PetroCorp) is the largest interest
owner in the area and operates the Hanlan-Robb area fields and the related
gathering system and processing plant.
South Louisiana Area. Includes ownership in the East Riceville Field in
Vermillion Parish and the Scott Field in Lafayette Parish. East Riceville is a
two-well gas field producing 28 MMcf/D from a Miogyp reservoir at approximately
17,000 feet. PetroCorp owns a 13.8% working interest in this field, which is
operated by Murphy Exploration and Production Company. The Company owns a 3.6%
working interest in the Scott Field, which is operated by Hallwood Petroleum,
Inc. The majority of the current production and asset value in the Scott Field
is attributable to two wells producing from a Bol Mex reservoir below 13,000
feet at a combined rate of approximately 50 MMcf/D.
Oklahoma City Area. Includes the Southwest Oklahoma City Field located within
the metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect located
just north of Oklahoma City. In the
7
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Southwest Oklahoma City Field area, PetroCorp operates 61 wells and has a
working interest in two additional wells. The Company also owns a 4% working
interest in the adjacent Will Rogers Unit, operated by Marathon. The key
property is the PetroCorp operated SW Oklahoma City Unit, a field-wide
waterflood unit, approved in 1996, targeting the Prue formation at 6,500 feet.
Current unit production is approximately 225 BOPD and 2,500 Mcf/D. The Company
owns an 86.4% working interest in the unit.
McLeod Field. As part of an acquisition in late 1996, the Company acquired
one shut-in oil well in this field in west central Alberta, Canada. Since then,
the PetroCorp has drilled six wells to develop production from three
formations. The Company's working interests vary from 12% to 100% in 9.8
sections (approximately 6,240 acres).
South Texas Area. Located in western Duval County, Texas, the Rich Hurt Field
is a four-well gas field currently producing approximately 24 MMcf/D from an
Upper Wilcox sand interval at approximately 8,700 feet. PetroCorp acquired its
interest in the field in June 1998, coincident with the completion of the
discovery well, the Mobil Ponciano Ruiz #1. Since then, the Company has
participated in three consecutive successful development wells in the field.
PetroCorp owns a 17.5% working interest in all four wells.
Other Properties. Other significant U.S. properties include the Glick field
located in south-central Kansas, the Hunter Misener Unit located in Alfalfa
County, Oklahoma, the Maynor Creek Field in Wayne County, Mississippi, the
Harris Field in Live Oak County, Texas, and the Paradox Basin area of southwest
Colorado. Other significant Canadian properties include the Trochu Prospect in
south-central Alberta and the Worsley Triassic A Pool located on the north
flank of the Peace River Arch in Alberta.
Title to Properties
United States. Except for the Company-owned mineral fee, royalty and
overriding royalty interests shown in the "Acreage and Wells" table below,
substantially all of the Company's United States property interests are held
pursuant to leases from third parties. The Company believes that it has
satisfactory title to its properties in accordance with standards generally
accepted in the oil and gas industry. In numerous instances the Company has
acquired legal title to producing properties and has carved out of the
properties so acquired net profits royalty interests in favor of institutional
investors who supplied a substantial portion of the funds for the acquisition
of such properties. The producing property reserves of the Company are stated
after giving effect to the reduction in cash flow attributable to such net
profits royalty interests. In addition, the Company's properties are subject to
customary royalty interests, liens for current taxes and other burdens that the
Company believes do not materially interfere with the use of or affect the
value of such properties.
Canada. Canadian property interests are held primarily under leases from the
Crown. A small percentage are from freehold owners. Prior to drilling on a non-
Crown lease or acquiring a non-Crown producing lease, the Company generally
obtains a title opinion covering the "historical" (freehold) title. The Company
generally relies on a title certificate under Canada's Torrens title
registration system to verify "current" (leasehold) ownership. Except for these
differences, title matters in Canada are similar to those in the United States.
Oil and Gas Reserves
All information herein regarding estimates of the Company's proved reserves,
related future net revenues and PV-10 is taken from reports prepared by
Huddleston & Co., Inc. (the Independent Engineers) in accordance with the rules
and regulations of the SEC. The Independent Engineers' estimates were based
upon a review of production histories and other geologic, economic, ownership
and engineering data provided by the Company.
8
<PAGE>
The following table sets forth summary information with respect to the
estimates made by the Independent Engineers of the Company's proved oil and gas
reserves as of December 31, 1998. The PV-10 values shown in the table are not
intended to represent the current market value of the estimated oil and gas
reserves owned by the Company.
<TABLE>
<CAPTION>
December 31, 1998
------------------------
United
States Canada Total
------- ------- --------
<S> <C> <C> <C>
Proved reserves:
Oil (Mbbls)................................... 2,578 1,412 3,990
Gas (MMcf).................................... 21,970 57,422 79,392
Gas equivalents (MMcfe)....................... 37,438 65,894 103,332
Future net revenues ($000s)(1).................. $43,471 $87,445 $130,916
Present value of future net revenues ($000s)(2). $30,964 $47,516 $ 78,480
Proved developed reserves:
Oil (Mbbls)................................... 2,499 1,132 3,631
Gas (MMcf).................................... 19,454 47,460 66,914
Gas equivalents (MMcfe)....................... 34,448 54,252 88,700
Future net revenues ($000s)(1).................. $38,860 $71,882 $110,742
Present value of future net revenues ($000s)(2). $28,019 $39,783 $ 67,802
</TABLE>
- --------
(1) Proved and proved developed future net revenues include $862,000 related to
the sale of sulfur.
(2) Proved and proved developed present values of future net revenues include
$468,000 related to the sale of sulfur.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and future amounts and
timing of development expenditures, including many factors beyond the control
of the Company. Reserve engineering is a subjective process of estimating
underground accumulations of crude oil and natural gas that cannot be measured
in an exact manner, and the accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Estimates of proved undeveloped reserves are inherently less
certain than estimates of proved developed reserves. The quantities of oil and
gas that are ultimately recovered, production and operating costs, the amount
and timing of future development expenditures, geologic success and future oil
and gas sales prices may all differ from those assumed in these estimates. In
addition, the Company's reserves may be subject to downward or upward revision
based upon production history, purchases or sales of properties, results of
future development, prevailing oil and gas prices and other factors. Therefore,
the present value shown above should not be construed as the current market
value of the estimated oil and gas reserves attributable to the Company's
properties.
In accordance with SEC guidelines, the Independent Engineers' estimates of
future net revenues from the Company's proved reserves and the present value
thereof are made using oil, gas and sulfur sales prices in effect as of the
dates of such estimates and are held constant throughout the life of the
properties except where such guidelines permit alternate treatment, including,
in the case of gas contracts, the use of fixed and determinable contractual
price escalations. See "Marketing" under Item 1 of this report, "Management's
Discussion and Analysis of Financial Condition and Results of Operations" under
Item 7 of this report and "Supplemental Information to Consolidated Financial
Statements" in the Notes to the Consolidated Financial Statements of the
Company. Estimates of the Company's proved oil and gas reserves were not filed
with or included in reports to any other federal authority or agency other than
the SEC during the fiscal year ended December 31, 1998.
9
<PAGE>
Acreage and Wells
The following table sets forth certain information with respect to the
Company's developed and undeveloped leased acreage as of December 31, 1998.
<TABLE>
<CAPTION>
Developed Acres Undeveloped Acres(1)
---------------------------- ----------------------------
Net Net
Participating Participating
Gross Net Interest(2) Gross Net Interest(2)
------- ------ ------------- ------- ------ -------------
<S> <C> <C> <C> <C> <C> <C>
United States:
Colorado........... 10,186 7,958 7,958 4,280 3,670 3,670
Kansas............. 5,360 3,520 667 10 6 1
Louisiana.......... 2,615 272 272 532 67 67
Mississippi........ 640 405 405 12,818 7,841 7,932
Oklahoma........... 40,770 14,953 11,058 16,479 9,342 9,166
Texas.............. 21,736 5,804 2,711 76,563 11,158 11,128
Other.............. 2,207 542 542 4,829 405 405
Canada:
Alberta............ 61,680 18,475 10,296 76,160 27,246 17,827
------- ------ ------ ------- ------ ------
Total............ 145,194 51,929 33,909 191,671 59,735 50,196
======= ====== ====== ======= ====== ======
</TABLE>
- --------
(1) Approximately 36% of net (approximately 23% of net participating interest)
undeveloped acres are covered by leases that expire during 1999.
(2) Net participating interest represents the Company's net working interest
less net profits royalty interests carved out and reconveyed to
institutional investors.
As of December 31, 1998, the Company had working interests in 230 gross (74
net) producing oil wells and 187 gross (36 net) producing gas wells. Of these
wells, 19 gross (17 net) oil wells and 46 gross (9 net) gas wells were in
Canada, and the remainder of the oil and gas wells were in the United States.
10
<PAGE>
Drilling Activities
All of PetroCorp's drilling activities are conducted through arrangements
with independent contractors, and it owns no drilling equipment. Certain
information with regard to the Company's drilling activities, during the years
ended December 31, 1998, 1997 and 1996 is set forth below:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------------------------
1998 1997 1996
---------------------------- ---------------------------- ----------------------------
Net Net Net Net Net Net
Working Participating Working Participating Working Participating
Type of Well Gross Interest Interest(1) Gross Interest Interest(1) Gross Interest Interest(1)
------------ ----- -------- ------------- ----- -------- ------------- ----- -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
United States
Development:
Oil.................... 6 1.4 1.2 6 3.6 3.3
Gas.................... 9 1.3 1.3 3 .6 .6 5 .1 0.0(2)
Nonproductive.......... 3 1.0 .8 5 2.2 2.2
--- --- --- --- ---- ---- --- ---- ----
Total................ 9 1.3 1.3 12 3.0 2.6 16 5.9 5.5
--- --- --- --- ---- ---- --- ---- ----
Exploratory:
Oil.................... 2 .6 .6 1 .3 .3
Gas.................... 2 .3 .3 1 .5 .5 2 .5 .4
Nonproductive.......... 8 2.7 2.6 6 2.2 2.2 6 3.5 3.5
--- --- --- --- ---- ---- --- ---- ----
Total................ 10 3.0 2.9 9 3.3 3.3 9 4.3 4.2
--- --- --- --- ---- ---- --- ---- ----
Canada
Development:
Oil.................... 2 .5 .5
Gas.................... 2 .2 .1 5 1.7 1.4
Nonproductive..........
--- --- --- --- ---- ---- --- ---- ----
Total................ 2 .2 .1 7 2.2 1.9
--- --- --- --- ---- ---- --- ---- ----
Exploratory:
Oil.................... 1 1.0 1.0
Gas.................... 2 1.3 1.1 8 2.6 2.2 1 .3 .1
Nonproductive.......... 2 1.5 1.2 4 .6 .4 1 .5 .5
--- --- --- --- ---- ---- --- ---- ----
Total................ 4 2.8 2.3 13 4.2 3.6 2 .8 .6
--- --- --- --- ---- ---- --- ---- ----
Total................... 25 7.3 6.6 41 12.7 11.4 27 11.0 10.3
=== === === === ==== ==== === ==== ====
</TABLE>
- --------
(1) Net participating interest represents the Company's net working interest
less net profits royalty interests carved out and reconveyed to
institutional investors.
(2) The Company has a net participating interest less than 0.05% in this well.
At December 31, 1998, the Company was participating in the drilling of 1
gross (.2 net) well in the United States.
Hanlan-Robb Natural Gas Processing Plant and Gas Gathering Systems
PetroCorp owns interests in a centrally located gas processing plant and in a
gas gathering system that connects all of the Company's currently producing
Hanlan-Robb fields to the Hanlan-Robb plant. Commissioned in 1983, the
estimated replacement value is approximately $325 ($C500) million. The original
design capacity of 300 MMcf/D was recently expanded to 380 MMcf/D and two new
major pipeline systems have recently begun delivering third-party gas to the
plant for processing. This new third-party gas, for which processing fees are
received, has increased plant throughput from 220 MMcf/D to approximately 300
MMcf/D at year-end 1998. PetroCorp owns a 24.5% working interest in the plant
and varying working interests in the gathering systems, dehydration and
compression facilities that deliver gas to the plant.
11
<PAGE>
Previously a wholly-owned subsidiary of the Company, Fidelity Gas Systems,
Inc. ("FGS"), owned and operated the Anasazi Gas Gathering System, which
gathers gas produced from the Company-operated lease in the Paradox Basin area
of southwest Colorado. In December 1997, FGS was merged into the Company. The
working interest owners have entered into contracts with the Company pursuant
to which the Company purchases all of the gas produced from the area. This gas
is then resold by the Company to a purchaser at a redelivery point on the
national transmission pipeline system. Proceeds payable by the Company are
based upon the Company's resale price less a contractually agreed-upon fee.
Amounts received by the Company are distributed to all working interest and
royalty owners in the producing area in accordance with their ownership
interests. Because it is a gas gathering system, the Anasazi Gas Gathering
System has been deemed nonjurisdictional with respect to existing FERC rules
and regulations.
Other Facilities
The Company leases approximately 31,600 square feet in Houston, Texas for
its primary office. The Company also leases approximately 8,200 square feet in
Oklahoma City, Oklahoma and approximately 4,000 square feet in Calgary,
Alberta for divisional offices. Additionally, the Company owns an 18,400
square-foot building and surface pads covering approximately 42 acres related
to its Southwest Oklahoma City Field operations.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Current and prospective stockholders should carefully consider the following
risk factors in evaluating an investment in PetroCorp. 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, including those set forth in the following risk
factors.
All subsequent written and oral forward-looking statements attributable to
the Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
Volatile Nature of Oil and Gas Markets; Fluctuations in Prices
The Company's future financial condition and results of operations are
highly dependent on the demand and prices received for oil and gas production
and on the costs of acquiring, developing and producing reserves. Oil and gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the Company's control. These factors include political
conditions in the Middle East and elsewhere, domestic and foreign supply of
oil and gas, the level of consumer demand, weather conditions, domestic and
foreign government regulations and taxes, the price and availability of
alternative fuels and overall economic conditions. A decline in oil or gas
prices may adversely affect the Company's cash flow, liquidity and
profitability. Lower oil or gas prices also may reduce the amount of the
Company's oil and gas that can be produced economically.
12
<PAGE>
Dependence on Acquiring and Finding Additional Reserves
The Company's prospects for future growth and profitability will depend
predominantly on its ability to replace present reserves through acquisitions
and exploratory drilling, as well as on its ability to successfully develop
additional reserves. There can be no assurance that the Company's acquisition
and exploration activities or planned development projects will result in
significant additional reserves or that the Company will have continuing
success at drilling economically productive wells.
Substantial Capital Requirements
The Company has made substantial capital expenditures in connection with the
acquisition, exploration and development of oil and gas properties. Future cash
flows and the availability of credit are subject to a number of variables, such
as the level of production from existing wells, prices of oil and gas and the
Company's success in locating and producing new reserves. If revenues were to
decrease as a result of lower oil and gas prices, decreased production or
otherwise, and the Company had no available credit, the Company could be
limited in its ability to replace its reserves or to maintain production at
current levels, resulting in a decrease in production and revenue over time. If
the Company's cash flow from operations and available credit are not sufficient
to satisfy its capital expenditure requirements, there can be no assurance that
additional debt or equity financing will be available to meet these
requirements.
Reliance on Estimates of Reserves and Future Net Cash Flows
There are numerous uncertainties inherent in estimating quantities of proved
oil and gas reserves, including many factors beyond the Company's control.
Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flow necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other
producing areas, the assumed effects of regulation by governmental agencies,
assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net cash flows
expected therefrom prepared by different engineers or by the same engineers at
different times may vary significantly. Actual production, revenues and
expenditures with respect to the Company's reserves likely will vary from
estimates, and such variances may be material. In addition, the Company's
reserves and future cash flows may be subject to revisions based upon
production history, results of future development, oil and gas prices,
performance of counterparties under agreements to which the Company is a party,
operating and development costs and other factors.
The PV-10 values referred to herein should not be construed as the current
market value of the estimated oil and gas reserves attributable to the
Company's properties. In accordance with applicable requirements of the SEC,
PV-10 is generally based on prices and costs as of the date of the estimate,
whereas actual future prices and costs may be materially higher or lower.
Actual future net cash flows also will be affected by factors such as the
amount and timing of actual production, supply and demand for oil and gas,
curtailments or increases in consumption by natural gas purchasers and changes
in governmental regulations or taxation. The timing of actual future net cash
flows from proved reserves, and thus their actual present value, will be
affected by the timing of both the production and the incurrence of expenses in
connection with development and production of oil and gas properties. In
addition, the 10% discount factor (which is required by the SEC to be used to
calculate PV-10 for reporting purposes), is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company and its properties or the oil and gas
industry in general.
13
<PAGE>
Exploration Risks
Exploratory drilling activities are subject to many risks, including the risk
that no commercially productive reservoirs will be encountered, and there can
be no assurance that new wells drilled by the Company will be productive or
that the Company will recover all or any portion of its investment. Drilling
for oil and gas may involve unprofitable efforts, not only from non-productive
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs. The cost
of drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.
Marketing Risks
The Company's ability to market its oil and gas production at commercially
acceptable prices is dependent on, among other factors, the availability and
capacity of gathering systems and pipelines, federal and state regulation of
production and transportation, general economic conditions, and changes in
supply and in demand.
Acquisition Risks
Acquisitions of oil and gas businesses and properties and volumetric
production payments have been an important element of the Company's success,
and the Company will continue to seek acquisitions in the future. Even though
the Company performs a review (including a limited review of title and other
records) of the major properties it seeks to acquire that it believes is
consistent with industry practices, such reviews are inherently incomplete and
it is generally not feasible for the Company to review in-depth every property
and all records. Even an in-depth review may not reveal existing or potential
problems or permit the Company to become familiar enough with the properties to
assess fully their deficiencies and capabilities, and the Company often assumes
environmental and other liabilities in connection with acquired businesses and
properties.
Operating Risks
The Company's operations are subject to numerous risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as
oil spills, natural gas leaks, ruptures or discharges of toxic gases, the
occurrence of any of which could result in substantial losses to the Company
due to injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. The Company's operations may be materially curtailed,
delayed or canceled as a result of numerous factors, including the presence of
unanticipated pressure or irregularities in formations, accidents, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment. In accordance with customary
industry practice, the Company maintains insurance against some, but not all,
of the risks described above. There can be no assurance that the levels of
insurance maintained by the Company will be adequate to cover any losses or
liabilities.
Competitive Industry
The oil and gas industry is highly competitive. The Company competes for
corporate and property acquisitions and the exploration, development,
production, transportation and marketing of oil and gas, as well as contracting
for equipment and securing personnel, with major oil and gas companies, other
independent oil and gas concerns and individual producers and operators. Many
of these competitors have financial and other resources which substantially
exceed those available to the Company.
14
<PAGE>
Government Regulation
The Company's business is subject to certain federal, state and local laws
and regulations relating to the drilling for and production, transportation and
marketing of oil and gas, as well as environmental and safety matters. Such
laws and regulations have generally become more stringent in recent years,
often imposing greater liability on an increasing number of parties. Because
the requirements imposed by such laws and regulations are frequently changed,
the Company is unable to predict the effect or cost of compliance with such
requirements or their effects on oil and gas use or prices. In addition,
legislative proposals are frequently introduced in Congress and state
legislatures which, if enacted, might significantly affect the oil and gas
industry. In view of the many uncertainties which exist with respect to any
legislative proposals, the effect on the Company of any legislation which might
be enacted cannot be predicted.
Item 3. Legal Proceedings.
The Company is a party to various lawsuits and governmental proceedings, all
arising in the ordinary course of business. Although the outcome of these
lawsuits cannot be predicted with certainty, the Company does not expect such
matters to have a material adverse effect, either singly or in the aggregate,
on the financial position of the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
The Company's Common Stock is currently listed on the American Stock Exchange
(the "AMEX") and trades under the symbol PEX. The Company's Common Stock has
been listed with the AMEX since September 17, 1998. Prior to that time, the
Company's Common Stock had been listed on The Nasdaq Stock Market since October
28, 1993. The following table presents the high and low closing prices for the
Company's Common Stock for each quarter during 1997 and 1998, and for a portion
of the Company's current quarter, as reported by the AMEX.
<TABLE>
<CAPTION>
1997 1998 1999
------------------------------- ------------------------------- ------------------
First Second Third Fourth First Second Third Fourth First Quarter
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter (through March 17)
------- ------- ------- ------- ------- ------- ------- ------- ------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
High.................... $10.13 $9.13 $9.38 $10.00 $9.31 $9.00 $8.25 $7.88 $5.88
Low..................... 8.50 8.00 8.25 7.56 7.75 7.13 5.13 5.25 5.19
</TABLE>
As of March 17, 1999, the closing price for the Company's Common Stock was
$5.25 per share. As of March 17, 1999, there were approximately 500 holders of
record of the Common Stock.
The Company has not declared or paid any cash dividends on its Common Stock
to date. The Board of Directors of the Company does not intend to declare cash
dividends on its Common Stock in the foreseeable future. The Company intends
instead to retain its earnings to support the growth of the Company's business.
Any future cash dividends would depend on future earnings, capital
requirements, the Company's financial condition and other factors deemed
relevant by the Company's Board of Directors.
Certain senior notes were issued pursuant to a note purchase agreement that
prohibited the declaration or payment of any cash dividends by the Company
prior to July 1, 1995. In addition, other provisions of the note purchase
agreement impose upon the Company certain financial covenants and other
restrictive covenants that have the effect of restricting the amount of
dividends on the Common Stock that may be paid by the Company after June 30,
1995. The terms of the Company's credit facility also prohibit the declaration
or payment of any dividends.
15
<PAGE>
Item 6. Selected Financial Data.
The following table summarizes consolidated financial data of the Company and
should be read in conjunction with the "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements of the Company, including the Notes thereto, included elsewhere in
this report.
<TABLE>
<CAPTION>
For the Year Ended December 31,
------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues:
Oil and gas................ $ 23,621 $ 33,502 $ 29,718 $ 24,448 $ 25,176
Plant processing........... 1,550 1,420 1,658 1,880 1,852
Other...................... 36 172 170 1,037 923
-------- -------- -------- -------- --------
25,207 35,094 31,546 27,365 27,951
-------- -------- -------- -------- --------
Expenses:
Production costs........... 7,344 7,793 6,660 7,304 7,156
Depreciation, depletion and
amortization.............. 16,568 17,065 12,433 13,300 12,800
Oil and gas property
valuation adjustment...... 33,600 8,500
General and administrative. 4,482 4,846 4,542 5,544 5,067
Other operating expenses... 265 367 333 256 98
-------- -------- -------- -------- --------
62,259 30,071 23,968 34,904 25,121
-------- -------- -------- -------- --------
Income (loss) from
operations.................. (37,052) 5,023 7,578 (7,539) 2,830
-------- -------- -------- -------- --------
Other income (expenses):
Investment and other
income.................... 1,151 558 1,910 1,470 1,411
Interest expense........... (3,622) (3,528) (3,391) (3,917) (3,229)
Preferred dividends of
subsidiary................ (648)
Other income (expenses).... 14 (47) (46) (159) (131)
-------- -------- -------- -------- --------
(2,457) (3,017) (1,527) (2,606) (2,597)
-------- -------- -------- -------- --------
Income (loss) before income
taxes....................... (39,509) 2,006 6,051 (10,145) 233
Income tax provision
(benefit)................... (15,114) 136 1,807 (608) 114
-------- -------- -------- -------- --------
Net income (loss)............ $(24,395) $ 1,870 $ 4,244 $ (9,537) $ 119
======== ======== ======== ======== ========
Net income (loss) per share--
basic....................... $ (2.82) $ 0.22 $ 0.49 $ (1.11) $ 0.01
======== ======== ======== ======== ========
Net income (loss) per share--
diluted..................... $ (2.82) $ 0.22 $ 0.49 $ (1.11) $ 0.01
======== ======== ======== ======== ========
Weighted average number of
common shares--basic........ 8,637 8,586 8,585 8,585 8,585
======== ======== ======== ======== ========
Weighted average number of
common shares-- diluted..... 8,699 8,688 8,669 8,585 8,698
======== ======== ======== ======== ========
Balance Sheet Data:
Working capital.............. $ 2,080 $ 2,638 $ 1,946 $ 6,344 $ 11,767
Total assets................. 103,992 130,924 122,864 114,839 133,403
Long-term debt............... 47,305 42,192 33,462 36,513 41,587
Shareholders' equity......... 40,744 66,557 65,665 61,521 70,328
</TABLE>
16
<PAGE>
Item 7. 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 Year Ended
December 31,
--------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Production:
United States:
Oil (MBbls)............................................. 422 580 662
Gas (MMcf).............................................. 4,932 4,853 5,155
Gas equivalents (MMcfe)................................. 7,464 8,333 9,127
Canada:
Oil (MBbls)............................................. 143 142 5
Gas (MMcf).............................................. 4,579 4,787 3,182
Gas equivalents (MMcfe)................................. 5,437 5,639 3,212
Total:
Oil (MBbls)............................................. 565 722 667
Gas (MMcf).............................................. 9,511 9,640 8,337
Gas equivalents (MMcfe)................................. 12,901 13,972 12,339
Average sales prices (includes the effects of hedging):
United States:
Oil (per Bbl)........................................... $12.55 $19.57 $19.89
Gas (per Mcf)........................................... 2.15 2.62 2.36
Canada:
Oil (per Bbl)........................................... 11.59 17.19 23.12
Gas (per Mcf)........................................... 1.32 1.46 1.34
Weighted average:
Oil (per Bbl)........................................... 12.31 19.10 19.91
Gas (per Mcf)........................................... 1.75 2.04 1.97
Selected data per Mcfe:
Average sales price...................................... $ 1.83 $ 2.39 $ 2.41
Production costs......................................... 0.57 0.56 0.54
General and administrative expenses...................... 0.35 0.35 0.37
Oil and gas depreciation, depletion and amortization..... 1.16 1.10 0.87
</TABLE>
Restructuring
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
17
<PAGE>
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.
The Company opened a data room in February, 1999 and to date has received
various offers from third parties to purchase certain assets of, or merge with,
the Company. The Board of Directors and management are currently assessing and
evaluating the specific terms of these offers. At this time, it is not possible
to determine the likelihood that one or more of these offers would be accepted,
or that another course of action would ultimately be followed.
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 24 MMcf/D
at year-end 1998. PetroCorp's net share of this production is approximately 3.2
MMcf/D. The alliance has identified more than 80 prospects/leads in the area
and currently has a leasehold position over 35 of these ideas.
Results of Operations
1998 Compared to 1997
Overview. Primarily resulting from a 36% decrease in oil prices and a 14%
decrease in gas prices, coupled with an 8% decrease in production volumes, cash
flow before changes in operating assets and liabilities decreased 44% to $10.7
million during 1998. This compares to $19.1 million in 1997.
Under rules promulgated by the Securities and Exchange Commission (the SEC),
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. As a result of low U.S. product prices at December 31,
1998, the Company recorded a valuation adjustment to its U.S. oil and gas
property balances, resulting in a non-cash after-tax charge against earnings of
$21.2 million ($33.6 million pre-tax). Excluding the valuation adjustment, the
Company recorded a net loss of $3.2 million, or $0.37 per share, in 1998
compared to net income of $1.9 million, or $0.22 per share, recorded in the
prior year.
Revenues. Total revenues decreased 28% to $25.2 million in 1998 compared to
$35.1 million in 1997. Oil and gas revenues decreased 29% to $23.6 million in
1998 from $33.5 million in the prior year as a result of the lower oil and gas
prices, coupled with the lower production volumes.
The Company's oil production decreased 22% to 565 MBbls while its natural gas
production remained almost level at 9,511 MMcf for an overall decline in
production of 8% to 12,901 MMcfe from 13,972 MMcfe. The decreased oil
production reflects normal production declines at the Hunter Misener Unit
waterflood project located in northern Oklahoma and the Maynor Creek field in
Mississippi. The Company had increases in gas production from the South Texas
Acquisition and new wells in the U.S. and Canada. However, these increases were
offset by lower gas volumes resulting from an unexpected mechanical problem,
which has since been remedied, in a significant gas well located in South
Louisiana, non-strategic property sales and natural production declines.
18
<PAGE>
The Company's composite average oil price decreased 36% to $12.31 per barrel
in 1998 from $19.10 per barrel in 1997. The Company's average U.S. natural gas
price decreased 18% to $2.15 per Mcf in 1998 from $2.62 per Mcf in the prior
year, while the average Canadian natural gas price decreased 10% to $1.32 per
Mcf from $1.46 per Mcf.
Plant processing revenues increased 9% to $1.6 million in 1998 from $1.4
million in 1997 as a result of new third party gas processing fees received at
the Company's Hanlan-Robb gas processing plant in Canada; beginning in August
1998.
Production Costs. Production costs decreased 6% to $7.3 million in 1998
while production costs per Mcfe remained almost level at $0.57. The decrease
in absolute dollars reflects a reduction in production taxes and the Company's
continued effort to reduce operating costs.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 3% to
$16.6 million in 1998 from $17.1 million in 1997. This decrease reflects the
impact of lower production volumes partially offset by a 5% increase in the
oil and Gas DD&A rate to $1.16 per Mcfe from $1.10 per Mcfe.
Oil and Gas Property Valuation Adjustment. The Company follows the full cost
method of accounting for its oil and gas properties. Under this method. all
productive and non-productive exploration and development costs, incurred for
the purpose of finding oil and gas reserves, are capitalized and may not
exceed a calculated ceiling computed on a country-by-country basis. The
ceiling is calculated on a quarterly basis as the sum of (i) the present value
(discounted at 10%) of future net revenues from estimated production of proved
oil and gas reserves plus (ii) the lower of cost or estimated fair market
value of the unproved properties, less (iii) the related income tax effects.
At December 31, 1998, as a result of low oil and gas prices, the Company's net
capitalized costs for its U.S. oil and gas properties exceeded the ceiling by
$21.2 million resulting in a pre-tax non-cash valuation adjustment of $33.6
million. The ceiling was calculated using a Koch WTI posting price of $9.50
per barrel of oil and a Henry Hub cash price of $2.14 per mcf of natural gas
as benchmark prices.
General and Administrative Expenses. General and administrative expenses
decreased 8% to $4.5 million in 1998 from $4.8 million in 1997 as a result of
the Company's focus on reducing costs.
Investment and Other Income. Investment and other income increased
significantly to $1.2 million in 1998 from $558,000 in 1997. The Company
recorded an additional $762,000 in 1998 related to gas contract settlements
and other items.
Interest Expense. Interest expense increased 3% to $3.6 million in 1998 from
$3.5 million in the prior year, reflecting the impact of increased debt
associated with a producing property acquisition completed in July 1997.
Income Taxes. Reflecting the U.S. valuation adjustment, the Company recorded
a $15.1 million income tax benefit with an effective tax rate of 38% on a pre-
tax loss of $39.5 million in 1998. This compares to an income tax provision of
$136,000 with an effective tax rate of 7% on pre-tax income of $2.0 million in
1997. During 1997 the Company recorded an income tax provision for its
Canadian operations with an effective tax rate of 15% which was partially
offset by an income tax benefit for its U.S. operations with an effective tax
rate of 29%, resulting in an overall effective tax rate of 7%.
1997 Compared to 1996
Overview. As a result of a 13% increase in production, cash flow before
changes in operating assets and liabilities increased 9% to $19.1 million in
1997 compared to $17.5 million in 1996. Net income decreased 48% to $1.9
million, or $0.22 per share, compared to $3.6 million, or $0.42 per share
(excluding a $629,000, or $.07 per share, after-tax gain on the sale of a gas
gathering system) for the
19
<PAGE>
corresponding periods. Net income in 1997 was significantly impacted by
increased DD&A largely due to the year-end 1996 reduction in proved reserves at
the Company's Texas waterflood project. Assuming the reduction in reserves
occurred at the beginning of 1996 rather than at the end and excluding the gain
on the 1996 sale of the gas gathering system, 1997 net income would have
decreased by 6% compared to 1996.
Revenues. Total revenues increased 11% to $35.1 million in 1997 compared to
$31.5 million in 1996. Oil production increased 8% to 722 MBbls from 667 MBbls.
Natural gas production increased 16% to 9,640 MMcf from 8,337 MMcf, resulting
in overall production increasing 13% to 13,974 MMcfe from 12,336 MMcfe. The
increase in oil production is primarily related to the acquisition of Canadian
properties in late 1996. The increase in natural gas production reflects the
impact of producing property acquisitions coupled with an increase in the
Company's share of gas production in the Hanlan-Robb area in western Alberta as
a result of an increase in ownership following a February 1997 payout to its
joint venture partner.
The Company's average U.S. natural gas price increased 11% to $2.62 per Mcf
in 1997 from $2.36 per Mcf in 1996, while the average Canadian natural gas
price increased 9% to $1.46 from $1.34. The Company's composite average oil
price decreased 4% to $19.10 per barrel in 1997 from $19.91 per barrel in 1996.
As a result of hedging transactions, the Company's 1996 average oil price was
reduced by $1.15 per barrel from the average price that would have otherwise
been received. No hedging transactions were in place during 1997. Primarily as
a result of the increases in production volumes, oil and gas revenues increased
13% to $33.5 million in 1997 from $29.7 million in 1996. Plant processing
revenues decreased 14% to $1.4 million from $1.7 million primarily as a result
of the Company's sale of a portion of its interest in the Canadian Hanlan-Robb
gas processing plant in May 1996.
Production Costs. Production costs increased 17% to $7.8 million in 1997
compared to $6.7 million in 1996 primarily as a result of the 13% increase in
production volumes and initiation of waterflood operations in the SW Oklahoma
City field. Production costs per Mcfe slightly increased by 4% to $0.56 from
$0.54.
Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 37% to
$17.1 million in 1997 from $12.4 million in 1996 primarily as a result of the
increase in the oil and gas DD&A rate to $1.10 per Mcfe from $0.87 per Mcfe.
The increase in the DD&A rate reflects the impact of the year-end 1996
reduction in proved reserves due to the lack of commercial oil response at the
Company's Richardson-Mueller Caddo Unit waterflood project in northern Texas.
General and Administrative Expenses. General and administrative expenses
increased 7% to $4.8 million in 1997 from $4.5 million in 1996. This increase
is primarily due to an increase in contract and temporary personnel associated
with the producing property acquisitions and other ongoing projects and a
decrease in the Company's drilling and operating overhead recoveries which
reduce general and administrative expenses.
Investment and Other Income. Investment and other income decreased 71% to
$558,000 in 1997 from $1.9 million in 1996 primarily as a result of a $1.0
million pre-tax gain on the sale of the Company's Oklahoma gas gathering system
included in investment and other income in 1996. Additionally, less funds were
available for investment in 1997.
Interest Expense. Interest expense increased 4% to $3.5 million in 1997 from
$3.4 million in 1996, reflecting the impact of increased debt associated with a
producing property acquisition completed in July 1997.
Income Taxes. The Company recorded a $136,000 income tax provision on pre-tax
income of $2.0 million with an effective tax rate of 7% in 1997 compared to an
income tax provision of $1.8 million on pre-tax income of $6.1 million with an
effective tax rate of 30% in 1996. During 1997 the Company
20
<PAGE>
recorded an income tax provision for its Canadian operations with an effective
tax rate of 15% which was partially offset by an income tax benefit for its
U.S. operations with an effective tax rate of 29%, resulting in an overall
effective tax rate of 7%.
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 December 31, 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 $10.7 million, $19.1 million and $17.5
million in 1998, 1997 and 1996, respectively.
The Company's total capital expenditures, including capitalized internal
costs, were $19.4 million, $28.0 million and $29.5 million for 1998, 1997 and
1996, respectively. During 1998, the Company spent $11.6 million related to
exploration and development and $4.8 million related to acquisitions. In 1997,
the Company spent $16.4 million related to exploration and development and
$11.0 million related to acquisitions. In 1996, the Company spent $11.4
million related to exploration and development and $17.3 million related to
acquisitions.
Sales of non-strategic oil and gas properties totaled $2.8 million, $1.4
million, and $6.3 million in 1998, 1997 and 1996, respectively.
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
December 31, 1998, $1.8 million has been recognized, leaving a balance of
$257,000 in "deferred revenue" on the consolidated balance sheet as of
December 31, 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 producing properties completed in early July 1997 and to
fund certain debt repayments. During 1998, the Company borrowed $12.0 million
to fund additional acquisitions and other debt repayments. At December 31,
1998, the Company had a total of $25.0 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. 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 6.6%
during 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%.
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<PAGE>
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 December 31, 1998, the remaining
principal balances for the Series A and B Notes were $875,000 and $20.3
million, respectively. Of the total $21.2 million, $3.8 million 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.
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, 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 Series A and Series B note holders
have waived such provisions for one year.
As the Company has both the ability and intent to refinance $2.0 million of
its current maturities of long-term debt utilizing its revolving credit
facility, $2.0 million has been reclassified from "current" to "long-term" on
the Company's accompanying consolidated balance sheet as of December 31, 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 December
31, 1998, the nonrecourse long-term notes payable balance was $3.9 million, of
which $910,000 was classified as "current."
Product prices continue to be volatile subsequent to December 31, 1998. In
the future, should prices decline further and depending on drilling results,
the Company could be required to record an additional valuation adjustment to
its oil and gas property balances, resulting in a future non-cash charge
against earnings.
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 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.
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<PAGE>
PetroCorp has formed a Year 2000 compliance team and has been addressing Year
2000 issues since 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 June 30, 1999 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.
Item 7A. Quantitative and Qualitative Disclosure 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. As discussed in Note 13 to the Consolidated Financial
Statements, no hedge transactions were in place in 1997 and 1998.
Interest Rate Risk
Total debt at December 31, 1998, included $24.1 million of fixed-rate debt
attributed to Series B Senior Notes and Nonrecourse Notes Payable, and $25.9
million of floating-rate debt attributed to Series A Senior Notes and the TD
Bank Credit Agreement. As a result, the Company's annual interest cost in 1999
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 approximately
$184,000.
At December 31, 1998, the Company's fixed rate Series B Senior Notes had a
book value of $20.8 million and a fair market value of $26.5 million. Due to
the nature of the Nonrecourse Notes Payable, the Company believes that it is
not practicable to estimate the fair value. See Note 6 to the Consolidated
Financial Statements for information regarding future maturities of the
Company's debt.
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
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<PAGE>
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.
Item 8. Financial Statements and Supplementary Data.
The information required by this item appears on pages 27 through 54 of this
report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
There is no matter required to be disclosed in response to this item.
PART III
In accordance with paragraph (3) of General Instruction G to Form 10-K, Part
III of this Report is omitted because the Company will file with the Securities
and Exchange Commission not later than 120 days after the end of the fiscal
year ended December 31, 1998 a definitive proxy statement pursuant to
Regulation 14A involving the election of directors, which proxy statement is
incorporated herein by reference (with the exception of certain portions noted
therein that are not so incorporated by reference).
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements
<TABLE>
<CAPTION>
Page
of
this
Report
------
<S> <C>
Report of Independent Accountants....................................... 27
Consolidated Balance Sheets as of December 31, 1998 and December 31,
1997................................................................... 28
Consolidated Statement of Operations for the Years Ended December 31,
1998, 1997
and 1996............................................................... 29
Consolidated Statement of Shareholders' Equity for the Years Ended
December 31, 1998,
1997 and 1996.......................................................... 30
Consolidated Statement of Cash Flows for the Years Ended December 31,
1998, 1997
and 1996............................................................... 31
Notes to Consolidated Financial Statements.............................. 32
</TABLE>
2. Financial Statement Schedules
Not Applicable.
3. Exhibits
<TABLE>
<C> <S>
2.1* Plan of Merger and Combination Agreement, dated September 18, 1991, by
and among Park Avenue Exploration Corporation, PetroCorp, L.S. Holding
Company, PetroCorp Incorporated, PetroPartners Limited Partnership,
PetroCorp Acquisition Corporation and Management Shareholders, as amended
by the First Amendment, dated October 1, 1992, and by the Simplification
Agreement described in Exhibit 2.2 hereto. Incorporated by reference to
Exhibit 2.1 to the Company's Registration Statement on Form S-1
(Registration No. 33-36972)
initially filed with the Securities and Exchange Commission (SEC) on
August 26, 1993 (the "Registration Statement").
</TABLE>
24
<PAGE>
<TABLE>
<C> <S>
2.2* Simplification Agreement, dated August 24, 1993, by and among Park
Avenue Exploration Corporation, L.S. Holding Company, PetroCorp,
PetroCorp Incorporated, PetroPartners Limited Partnership, PetroCorp
Employees Partnership, L.P., Lealon L. Sargent, W. Neil McBean, Don A.
Turkleson, Michael L. Lord, Antonio F. Pelletier, David G. Campbell,
Fletcher S. Hicks, Craig K. Townsend, Clifford G. Zwahlen, Charles L.
Zorio, Rodney Rother, Mark Meyer and Carl Campbell (the "Simplification
Agreement"). Incorporated by reference to Exhibit 2.2 to the
Registration Statement.
3.1* Amended and Restated Articles of Incorporation of PetroCorp
Incorporated. Incorporated by reference to Exhibit 3.2 to the
Registration Statement.
3.2* Amended and Restated Bylaws of PetroCorp Incorporated. Incorporated by
reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 1996.
3.3* Statement of Designations, Preferences, Limitations and Relative Rights
of Its Series A Junior Participating Preferred Stock (incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K, dated November 20,
1998).
3.4* Rights Agreement dated as of November 12, 1998, between PetroCorp
Incorporated and First Union National Bank, as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company's Form 8-K,
dated November 20, 1998).
3.5* Form of Right Certificate (incorporated by reference to Exhibit 4.2 to
the Company's Form 8-K, dated November 20, 1998).
4.1* Specimen certificate for shares of Common Stock. Incorporated by
reference to Exhibit 4.1 to the Registration Statement.
4.2* Note Purchase Agreement, dated July 29, 1993, among PetroCorp
Incorporated, United States Fidelity and Guaranty Company, Connecticut
General Life Insurance Company, Indiana Insurance Company, Security Life
of Denver Insurance Company, Southland Life Insurance Company, Life
Insurance Company of Georgia and Life Insurance Company of North
America. Incorporated by reference to Exhibit 4.2 to the Registration
Statement.
9.1* Voting Agreement, dated January 18, 1994, by and among USF&G
Corporation, Park Avenue Exploration Corporation, United States Fidelity
and Guaranty Company, CIGNA Corporation, L.S. Holding Company, American
Oil & Gas Investors, AmGO II, First Reserve Fund V, Limited Partnership,
First Reserve Fund V-2, Limited Partnership, First Reserve Fund VI,
Limited Partnership and First Reserve Corporation. Incorporated by
reference to Exhibit 9.2 to the Form 8-K.
10.1* Amended and Restated 1992 PetroCorp Stock Option Plan. Incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 1996.
10.2* Hanlan-Robb Area Agreement of Purchase and Sale, effective August 1,
1991, between Gulf Canada Resources Limited and Petro-Canada and PCC
Energy Inc. Incorporated by reference to Exhibit 10.3 to the
Registration Statement.
10.3* Registration Rights Agreement, dated August 24, 1993, between L.S.
Holding Company (assigned to Kaiser-Francis Oil Company) and PetroCorp
Incorporated. Incorporated by reference to Exhibit 10.5 to the
Registration Statement.
10.4* Registration Rights Agreement, dated August 24, 1993, between Park
Avenue Exploration Corporation and PetroCorp Incorporated. Incorporated
by reference to Exhibit 10.6 to the Registration Statement.
10.5* Registration Rights Agreement, dated January 18, 1994, between PetroCorp
Incorporated and American Oil & Gas Investors, AmGO II, First Reserve
Fund V, Limited Partnership, First Reserve Fund V-2, Limited
Partnership, First Reserve Fund VI, Limited Partnership and First
Reserve Corporation (assigned to Kaiser-Francis Oil Company).
Incorporated by reference to Exhibit 10.1 to the Form 8-K.
</TABLE>
25
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<TABLE>
<C> <S>
10.6* Piggyback Registration Rights Agreement, dated October 27, 1993,
between Lealon L. Sargent and PetroCorp Incorporated. Incorporated by
reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993. This is a management
contract or compensatory plan or arrangement required to be filed as an
exhibit.
10.7* Separation Benefits Agreement, dated September 27, 1993, between Lealon
L. Sargent and PetroCorp Incorporated. Incorporated by reference to
Exhibit 10.8 to the Registration Statement. This is a management
contract or compensatory plan or arrangement required to be filed as an
exhibit.
10.8* Executive Management Annual Incentive Compensation Plan, effective
January 1, 1994. Incorporated by reference to Exhibit 10.8 to the
Company's Annual Report on Form 10-K for the fiscal year ended December
31, 1994 (1994 Form 10-K). This is a management contract or
compensatory plan or arrangement required to be filed as an exhibit.
10.9* Share Purchase Agreement, dated December 13, 1996, between 702056
Alberta Ltd. and shareholders of Millarville Oil & Gas Ltd.
Incorporated by reference to Exhibit 2 to the Company's Current Report
on Form 8-K, dated December 23, 1996.
10.10* Agreement for Purchase and Sale dated June 5, 1997 between PetroCorp
Incorporated and Great River Oil and Gas Corporation. Incorporated by
reference to Exhibit 2.1 to the Company's current report on Form 8-K
dated July 1, 1997.
10.11* First Amendment to Agreement for Purchase and Sale dated June 30, 1997
between PetroCorp Incorporated and Great River Oil and Gas Corporation.
Incorporated by reference to Exhibit 2.2 to the Company's current
report on Form 8-K dated July 1, 1997.
10.12* Credit Agreement dated as of June 26, 1997 among PetroCorp
Incorporated, PCC Energy Limited, PCC Energy Corp, and Toronto-Dominion
(Texas), Inc. and Toronto-Dominion Bank. Incorporated by reference to
Exhibit 10 to the Company's current report on Form 8-K dated July 1,
1997.
10.13* 1997 Non-Employee Director Stock Option Plan. Incorporated by reference
to Appendix A to the Company's Proxy Statement for the Annual Meeting
of Shareholders held on May 16, 1997.
21 List of material subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Huddleston & Co., Inc.
27 Financial Data Schedule.
99.1* Agreement to furnish document relating to subsidiary. Incorporated by
reference to Exhibit 99.1 to the 1994 Form 10-K.
</TABLE>
- --------
* Incorporated by reference.
(b) Reports on Form 8-K
Report dated November 20, 1998 regarding adoption of a shareholder rights
agreement.
26
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
PetroCorp Incorporated
In our opinion, the consolidated balance sheets and the related consolidated
statements of operations, shareholders' equity and of cash flows present
fairly, in all material respects, the financial position of PetroCorp
Incorporated (the Company) and its subsidiaries at December 31, 1998 and 1997,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As further discussed in Note 2, the Company has retained CIBC Oppenheimer
Corp. to advise the Board of Directors with respect to strategic alternatives
for maximizing shareholder value.
/s/ PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 30, 1999
27
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEETS
December 31, 1998 and 1997
(in thousands, except per share amounts)
<TABLE>
<CAPTION>
1998 1997
ASSETS -------- --------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................ $ 7,786 $ 9,391
Accounts receivable, net................................. 4,569 6,608
Other current assets..................................... 326 337
-------- --------
Total current assets................................... 12,681 16,336
-------- --------
Property, plant and equipment:
Proved oil and gas properties, at cost, full cost method,
net of accumulated depreciation, depletion and
amortization............................................ 64,179 99,038
Unproved oil and gas properties, not subject to
depletion............................................... 9,151 9,592
Plant and related facilities............................. 3,768 3,922
Other, net............................................... 1,144 1,717
-------- --------
78,242 114,269
-------- --------
Deferred income taxes...................................... 12,761
Other assets, net.......................................... 308 319
-------- --------
Total assets........................................... $103,992 $130,924
======== ========
<CAPTION>
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
Current liabilities:
Accounts payable......................................... $ 4,424 $ 6,167
Accrued liabilities...................................... 3,467 3,345
Current portion of long-term debt........................ 2,710 4,186
-------- --------
Total current liabilities.............................. 10,601 13,698
-------- --------
Long-term debt............................................. 47,305 42,192
-------- --------
Deferred revenue........................................... 257 685
-------- --------
Deferred income taxes...................................... 5,085 7,792
-------- --------
Commitments and contingencies (Note 14)
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 8,591,519 shares
outstanding at December 31, 1998 and 1997,
respectively)........................................... 87 86
Additional paid-in capital............................... 71,245 71,143
Retained earnings (accumulated deficit).................. (24,324) 71
Accumulated other comprehensive loss..................... (6,264) (4,496)
Treasury stock, at cost (nil and 24,697 shares held at
December 31, 1998 and 1997, respectively)............... (247)
-------- --------
Total shareholders' equity............................. 40,744 66,557
-------- --------
Total liabilities and shareholders' equity............. $103,992 $130,924
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
28
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
Years Ended December 31, 1998, 1997 and 1996
(in thousands, except per share data)
<TABLE>
<CAPTION>
1998 1997 1996
-------- ------- -------
<S> <C> <C> <C>
Revenues:
Oil and gas....................................... $ 23,621 $33,502 $29,718
Plant processing.................................. 1,550 1,420 1,658
Other............................................. 36 172 170
-------- ------- -------
25,207 35,094 31,546
-------- ------- -------
Expenses:
Production costs.................................. 7,344 7,793 6,660
Depreciation, depletion and amortization.......... 16,568 17,065 12,433
Oil and gas property valuation adjustment......... 33,600
General and administrative........................ 4,482 4,846 4,542
Other operating expenses.......................... 265 367 333
-------- ------- -------
62,259 30,071 23,968
-------- ------- -------
Income (loss) from operations....................... (37,052) 5,023 7,578
-------- ------- -------
Other income (expenses):
Investment and other income....................... 1,151 558 1,910
Interest expense.................................. (3,622) (3,528) (3,391)
Other income (expenses)........................... 14 (47) (46)
-------- ------- -------
(2,457) (3,017) (1,527)
-------- ------- -------
Income (loss) before income taxes................... (39,509) 2,006 6,051
Income tax provision (benefit)...................... (15,114) 136 1,807
-------- ------- -------
Net income (loss)................................... $(24,395) $ 1,870 $ 4,244
======== ======= =======
Net income (loss) per common share--basic........... $ (2.82) $ 0.22 $ 0.49
======== ======= =======
Net income (loss) per common share--diluted......... $ (2.82) $ 0.22 $ 0.49
======== ======= =======
Weighted average number of common shares--basic..... 8,637 8,586 8,585
======== ======= =======
Weighted average number of common shares--diluted... 8,699 8,688 8,669
======== ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
29
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
Retained Accumulated
Additional earnings other
Shares paid-in (accumulated comprehensive Treasury
issued Amount capital deficit) loss stock Total
------ ------ ---------- ------------ ------------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31,
1995................... 8,616 $86 $71,170 $ (6,043) $(3,375) $(317) $61,521
Net income............ 4,244 4,244
Accumulated other
comprehensive loss... (100) (100)
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1996................... 8,616 86 71,170 (1,799) (3,475) (317) 65,665
Net income............ 1,870 1,870
Additional paid-in
capital.............. (27) (27)
Accumulated other
comprehensive loss... (1,021) (1,021)
Treasury stock........ 70 70
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1997................... 8,616 86 71,143 71 (4,496) (247) 66,557
Net loss.............. (24,395) (24,395)
Additional paid-in
capital.............. 40 1 102 103
Accumulated other
comprehensive loss... (1,768) (1,768)
Treasury stock........ 247 247
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1998................... 8,656 $87 $71,245 $(24,324) $(6,264) $ -- $40,744
===== === ======= ======== ======= ===== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
30
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 1998, 1997 and 1996
(in thousands)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)............................... $(24,395) $ 1,870 $ 4,244
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization....... 16,568 17,065 12,433
Deferred income tax provision (benefit)........ (15,114) 136 1,807
Gain on sale of gas gathering system........... (999)
Oil and gas property valuation adjustment...... 33,600
-------- -------- --------
10,659 19,071 17,485
Changes in operating assets and liabilities:
Accounts receivable........................... 2,039 1,506 (482)
Other current assets.......................... 11 (25) 1,121
Accounts payable.............................. (1,743) 160 748
Accrued liabilities........................... 122 (224) 199
Other.......................................... (437) (710) (693)
-------- -------- --------
Net cash provided by operating activities.... 10,651 19,778 18,378
-------- -------- --------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties.... 2,812 1,408 6,304
Additions to oil and gas properties............. (18,260) (27,425) (28,683)
Additions to plant and related facilities....... (919) (285) (261)
Additions to other property, plant and
equipment...................................... (71) (125) (537)
Additions to other assets....................... (144) (211) (31)
Proceeds from sale of interest in plant and
related facilities............................. 1,211
Proceeds from sale of gas gathering system...... 3,835
-------- -------- --------
Net cash used in investing activities........ (16,582) (26,638) (18,162)
-------- -------- --------
Cash flows from financing activities:
Proceeds from long-term debt.................... 14,845 13,244 3,908
Repayment of long-term debt..................... (10,876) (5,757) (7,028)
Other........................................... 350 43
-------- -------- --------
Net cash provided by (used in) financing
activities.................................. 4,319 7,530 (3,120)
-------- -------- --------
Effect of exchange rate changes on cash.......... 7 (138) (1)
-------- -------- --------
Net increase (decrease) in cash and cash
equivalents..................................... (1,605) 532 (2,905)
Cash and cash equivalents at beginning of year... 9,391 8,859 11,764
-------- -------- --------
Cash and cash equivalents at end of year......... $ 7,786 $ 9,391 $ 8,859
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
31
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1998, 1997 and 1996
1. Summary of Accounting Policies
General
PetroCorp Incorporated, a Texas corporation, is engaged in the acquisition,
exploration, development, and the production and sale of crude oil and natural
gas in North America. The terms "PetroCorp" and "Company" refer to PetroCorp
Incorporated and its subsidiaries. PetroCorp operates in Canada through its
wholly-owned Canadian subsidiaries as follows: PCC Energy Inc. (PCC Inc.), PCC
Energy Limited and PCC Energy Corp. PetroCorp's wholly-owned subsidiary,
Fidelity Gas Systems, Inc. (FGS), was merged into PetroCorp in 1997.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
the Company and its wholly-owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated. Certain prior-period amounts
have been reclassified to conform to the current-year presentation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires the Company to make estimates and assumptions
that affect the amounts reported in the financial statements and the
accompanying notes. Actual results may differ from such estimates.
Property, Plant and Equipment
The Company follows the full cost method of accounting for oil and gas
properties 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. At December 31, 1998, the Company's
net capitalized costs of its U.S. oil and gas properties exceeded the
capitalization ceiling by $21,168,000 resulting in a pre-tax valuation
adjustment of $33,600,000. Such valuation adjustment is reflected in the
Company's results of operations for the year ended December 31, 1998.
Plant and related facilities, consisting principally of a gas processing
plant in Alberta, Canada, are being depreciated on a straight-line basis over a
remaining estimated useful life of approximately four years. Other property and
equipment are depreciated by the straight-line method at rates based on the
estimated useful lives of the assets ranging from five to ten years.
32
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
At December 31, 1998 and 1997, the cumulative amount of accrued site
restoration and dismantlement costs approximated $154,000 and $357,000,
respectively.
Revenue Recognition
Revenues from the sale of petroleum produced are recognized upon the passage
of title, net of royalties and net profits royalty interests.
Revenues from natural gas production are recorded using the sales method, net
of royalties and net profits royalty interests. When sales volumes exceed the
Company's entitled share, an overproduced imbalance occurs. To the extent the
overproduced imbalance exceeds the Company's share of the remaining estimated
proved natural gas reserves for a given property, the Company records a
liability. At December 31, 1998 and 1997, the Company included $35,000 in
accrued liabilities with respect to overproduced imbalances.
The Company hedged a portion of its oil and gas sales in 1996. No hedges were
in place during 1997 or 1998. See Note 13--Hedging Program.
Revenues from plant processing are recognized at the time associated natural
gas is processed and sold at the plant tailgate. Other revenues include fees
associated with the field gathering of third-party natural gas from certain
properties in which the Company has an interest and revenues from the sale of
sulfur in Canada.
Accounts Receivable
Accounts receivable relate primarily to sales of oil and gas and amounts due
from joint-interest partners for expenditures made by the Company on behalf of
such partners. The Company reviews the financial condition of potential
purchasers and partners prior to signing sales or joint-interest agreements. At
December 31, 1998 and 1997, the Company's allowance for doubtful accounts
receivable, which is reflected in the consolidated balance sheet as a reduction
in accounts receivable, totaled $50,000.
Income Taxes
The Company utilizes the asset and liability method under which deferred tax
assets and liabilities are recognized for the estimated future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Foreign Currency Translation
The "functional currency" for translating the Company's Canadian accounts is
the Canadian dollar. Assets and liabilities are translated into the reporting
currency at the rate of exchange in effect at the balance sheet date while
revenues, expenses, gains and losses are translated at the average exchange
rate for the period. The resulting translation adjustments are accumulated in
the other comprehensive loss component of shareholders' equity. Foreign
currency transaction gains and losses are recognized currently. For the years
ended December 31, 1998, 1997 and 1996, the Company recognized foreign currency
losses of $2,000, $36,000 and $24,000, respectively. At December 31, 1998, 1997
and 1996, the exchange rates were ($1 CAN = $U.S.) $0.6535, $0.6992 and
$0.7297, respectively, while the average exchange rates during such years were
$0.6721, $0.7201 and $0.7334, respectively.
33
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
Cash Equivalents
For purposes of the consolidated statement of cash flows, the Company
considers all highly liquid debt instruments purchased with a maturity date of
three months or less to be cash equivalents. Cash equivalents at December 31,
1998, 1997 and 1996 were $5,875,000, $4,730,000 and $7,407,000, respectively.
Other
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.
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 partial or full sale 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 had 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.
The Company opened a data room in February 1999 and, to date, has received
various offers from third parties to purchase certain assets of, or merge with,
the Company. The Board of Directors and management are currently assessing and
evaluating the specific terms of these offers. At this time, it is not possible
to determine the likelihood that one or more of these offers would be accepted,
or that another course of action would ultimately be followed.
34
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
3. 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 adjustment. 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 years ended December 31, 1998, 1997 and 1996 are as follows (amounts in
thousands):
<TABLE>
<CAPTION>
Years ended December
31,
------------------------
1998 1997 1996
-------- ------ ------
<S> <C> <C> <C>
Net income (loss)............................... $(24,395) $1,870 $4,244
Foreign currently translation................... (1,768) (1,021) (100)
-------- ------ ------
Comprehensive income (loss)..................... $(26,163) $ 849 $4,144
======== ====== ======
</TABLE>
4. Acquisitions
Gulf Coast Acquisition
On July 1, 1997, the Company acquired producing oil and gas properties
located primarily in Louisiana for a cash purchase price of $9.2 million (the
Gulf Coast Acquisition). This acquisition has been accounted for as a purchase
and the results of operations of the oil and gas properties acquired are
included in the Company's results of operations effective July 1, 1997.
Millarville Acquisition
On December 23, 1996, the Company, through a wholly-owned Canadian
subsidiary, acquired all of the outstanding common shares of Millarville Oil
and Gas Ltd., a privately held Alberta Corporation that owns and operates oil
and gas properties in Alberta, Canada (the Millarville Acquisition). The cash
acquisition purchase price was $11.8 million which was allocated to oil and gas
properties. This acquisition has been accounted for as a purchase and the
results of operations of the oil and gas properties acquired are included in
the Company's results of operations effective December 23, 1996.
Pro Forma Information
The following unaudited pro forma financial information has been prepared to
give effect to the Gulf Coast Acquisition as if such transaction had occurred
at the beginning of 1997 and 1996 and the Millarville Acquisition as if such
transaction had occurred at the beginning of 1996. The historical results of
the Company's operations have been adjusted to reflect (i) the increase in
revenues and operating expenses directly attributable to the acquisitions, (ii)
increases in depletion, depreciation and amortization directly attributable to
the acquisitions, (iii) the increase in interest expense related to the bank
debt incurred as a result of the acquisitions and (iv) the increase in income
taxes resulting from future income directly attributable to the acquisitions.
The pro forma amounts do not purport to be indicative of the results of
operations that would have been reported had the acquisitions occurred as of
the date indicated, or that may be reported in the future (in thousands, except
per share amounts).
35
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
Unaudited pro
forma financial
information for
the years ended
December 31,
---------------
1997 1996
------- -------
<S> <C> <C>
Revenues................................................ $37,654 $42,565
Income from operations.................................. 6,108 12,813
Net income.............................................. 2,359 7,027
Net income per share--basic............................. 0.27 0.82
</TABLE>
5. Property, Plant and Equipment
Investments in property, plant and equipment were as follows at December 31,
1998 and 1997 (amounts in thousands):
<TABLE>
<CAPTION>
1998 1997
--------- ---------
<S> <C> <C>
Oil and gas properties:
Proved........................................... $ 208,354 $ 195,270
Unproved......................................... 9,151 9,592
--------- ---------
217,505 204,862
Plant and related facilities....................... 9,094 8,766
Gas gathering facilities........................... 1,698 1,685
Furniture, fixtures and equipment.................. 1,878 2,600
--------- ---------
230,175 217,913
Less--accumulated depreciation, depletion and
amortization...................................... (151,933) (103,644)
--------- ---------
$ 78,242 $ 114,269
========= =========
</TABLE>
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 1998, 1997 and 1996 was $16,406,000,
$16,880,000 and $12,279,000, respectively. Oil and gas property depreciation,
depletion and amortization for the years ended December 31, 1998, 1997 and 1996
was $14,961,000, $15,383,000 and $10,788,000, respectively. Depreciation,
depletion and amortization per equivalent Mcf (using a Mcf-to-barrel conversion
factor of 6 to 1) for the years ended December 31, 1998, 1997 and 1996 was
$1.62, $1.51 and $1.06, respectively, for U.S. operations and $0.53, $0.50 and
$0.34, respectively, for Canadian operations. The total composite rates were
$1.16, $1.10 and $0.87 for the years ended December 31, 1998, 1997 and 1996,
respectively.
Product prices continue to be volatile subsequent to December 31, 1998. 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 future noncash charge against earnings.
36
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
6. Long-Term Debt
The Company's total long-term debt is payable as follows (amounts in
thousands):
<TABLE>
<CAPTION>
1998 1997
------- -------
<S> <C> <C>
Current portion of long-term debt....................... $ 4,710 $ 8,186
Reclassified to long-term debt.......................... (2,000) (4,000)
------- -------
Total current portion of long-term debt................. $ 2,710 $ 4,186
======= =======
Series A & B Senior Notes............................... $17,350 $21,150
TD Bank Credit Agreement................................ 25,000 11,000
RBC Credit Agreement.................................... 2,741
Nonrecourse Notes Payable............................... 2,955 3,301
------- -------
45,305 38,192
Reclassified from current portion of long-term debt..... 2,000 4,000
------- -------
Total long-term debt.................................... $47,305 $42,192
======= =======
</TABLE>
Debt maturing in each of the years during the five-year period subsequent to
December 31, 1998 is as follows: $4,710,000 in 1999, $10,285,000 in 2000,
$9,085,000 in 2001, $8,160,000 in 2002 and $9,325,000 in 2003.
Reclassification of current debt maturities to long term represents unused
capacity under the TD Bank credit agreement at December 31, 1997 and 1998. The
Company has both the intent and ability to refinance this debt on a long-term
basis.
Series A and Series B Senior Notes
Series A and Series B Senior Notes at December 31, 1998 and 1997 consisted
of the following (amounts in thousands):
<TABLE>
<CAPTION>
1998 1997
------- -------
<S> <C> <C>
Series A, senior adjustable rate notes payable to a
shareholder affiliate.................................. $ 875 $ 2,550
Series B, 7.55% senior notes payable to nonaffiliates... 20,275 23,300
------- -------
$21,150 $25,850
======= =======
</TABLE>
Redemption payments to affiliates and nonaffiliates were $1,675,000 and
$3,025,000 in 1998 and $2,025,000 and $2,975,000 in 1997 and $4,142,000 and
$808,000 in 1996, respectively.
Interest paid to affiliates and nonaffiliates for the years ended December
31, 1998, 1997 and 1996 amounted to $173,000 and $1,689,000; $303,000 and
$1,941,000; $1,883,000 and $706,000, respectively.
On July 29, 1993, the Company entered into the Note Purchase Agreement with
subsidiaries of CIGNA Corporation and USF&G Corporation together with certain
other insurance companies to refinance existing notes totaling $36,976,000
with $40,000,000 in proceeds received under the Note Purchase Agreement. At
that time, subsidiaries of CIGNA Corporation and USF&G Corporation were
37
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
shareholder affiliates of the Company. In October 1996, the subsidiary of CIGNA
Corporation sold its shares of the Company and is, therefore, no longer a
shareholder affiliate. The Note Purchase Agreement provides for $10,000,000 in
aggregate principal amount of senior adjustable rate notes, Series A, due June
30, 1999, payable to a subsidiary of USF&G Corporation, and $30,000,000 in
aggregate principal amount of 7.55% senior notes, Series B, due June 30, 2008,
payable to two subsidiaries of CIGNA Corporation and to four unaffiliated
insurance companies, in the amounts of $20,000,000 and $10,000,000,
respectively.
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 period selected. Interest rates on the
Series A notes ranged from 6.6% to 7.0%, 6.7% to 7.0% and 6.7% to 7.1% during
1998, 1997 and 1996, respectively. Interest on the Series B notes is fixed at a
rate of 7.55% and is payable semiannually in arrears.
Mandatory redemptions commenced in 1994 and are payable semiannually based on
a fixed schedule. Series A and B redemption payments are scheduled through June
30, 1999 and June 30, 2008, respectively. Series A notes are callable at par.
Series B notes are callable at the greater of the outstanding principal or a
formula-based make-whole amount.
The Note Purchase Agreement imposes upon the Company certain financial
covenants and other restrictive covenants that have the effect of restricting
the amount of dividends on the common stock that may be paid by the Company.
The Note Purchase Agreement contains provisions that limit the Company's debt
levels based on undiscounted and discounted oil and gas reserves using 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, 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 Series A and Series B noteholders
have waived such provisions for one year.
Bank Debt
On June 26, 1997, the Company entered into a $50 million, five-year revolving
credit agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the
Bank of Nova Scotia. 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, 2000. 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 $50 million revolving credit agreement prohibits the declaration and
payment of dividends on the common stock of the Company.
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 $3,500,000 to partially fund the
Millarville Acquisition. 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 and 1997 was 6.6% and 5.8%, respectively.
38
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
Nonrecourse Notes Payable
On December 12, 1991, the Company (through its Canadian subsidiary, PCC Inc.)
acquired an interest in certain oil and gas properties and related gas
processing facilities located in the Hanlan-Robb area in western Alberta,
Canada. The Company used the proceeds from the issuance of redeemable preferred
stock of PCC Inc. to partially fund the acquisition. The holders of the
preferred stock also separately and concurrently acquired an interest in the
same oil and gas properties as the Company.
On August 9, 1994, PCC Inc. entered into agreements whereby PCC Inc. redeemed
the remaining shares of its redeemable preferred stock for $7,034,000.
Simultaneously, PCC Inc. issued $7,034,000 in nonrecourse long-term notes
payable (the Nonrecourse Notes Payable) to the previous holders of the
preferred stock with financial terms similar to the redeemable preferred stock.
Consistent with the redeemable preferred stock, the Nonrecourse Notes Payable
are denominated in Canadian dollars.
During 1998, 1997 and 1996, interest payments were $1,126,000, $669,000 and
$896,000, respectively, while principal payments totaled $2,017,000, $757,000
and $1,938,000, respectively. Additionally, in 1998, 1997 and 1996, the Company
issued $846,000, $245,000 and $261,000 of additional notes, respectively, as
provided under the provisions of the agreements.
Interest accrues and is payable on a quarterly basis at a rate of 15% per
annum. In addition, redemptions are required to be made quarterly, based on a
fixed schedule through December 31, 2002. Interest and redemption payments are
made only to the extent there are sufficient cash proceeds from production and
sale of oil and gas reserves related to the interest in the Hanlan-Robb assets
acquired by the holders of the Nonrecourse Notes Payable. To the extent
interest and redemptions exceed such cash proceeds, the excess amount is
carried forward to the next quarter.
7. Deferred Revenue
In March 1996, FGS sold its Southwest Oklahoma City Field gas gathering
system for $3,835,000. The Company's total gain on the sale was $3,088,000,
with $999,000 being recognized in the first quarter of 1996 in "investment and
other income" on the consolidated statement of operations while the remaining
$2,089,000 of the gain was deferred. The $2,089,000 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 Southwest Oklahoma City Field. To date, $1,832,000 has been
recognized, leaving a balance of $257,000 in "deferred revenue" on the
consolidated balance sheet as of December 31, 1998.
8. Preferred Stock
The Company is authorized to issue up to 1,000,000 shares of preferred stock,
par value $0.01 per share. However, no preferred shares have been issued. The
Company's Board of Directors is authorized to divide the preferred stock into
series and, with respect to each series, to determine the dividend rights,
dividend rate, conversion rights, voting rights, redemption rights and terms,
liquidation preferences, sinking fund provisions, the number of shares
constituting the series and the designation of such series. The Board of
Directors could, without shareholder approval, issue preferred stock with
voting rights and other rights that could adversely affect the voting power of
holders of common stock and could be used to prevent a third party from
acquiring control of the Company (see Note 2).
39
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
9. Income Taxes
The components of income (loss) before income taxes for the years ended
December 31, 1998, 1997 and 1996 consisted of the following (amounts in
thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- ------- ------
<S> <C> <C> <C>
United States operations....................... $(40,630) $(1,269) $4,096
Canadian operations............................ 1,121 3,275 1,955
-------- ------- ------
$(39,509) $ 2,006 $6,051
======== ======= ======
</TABLE>
The provision (benefit) for income taxes consists of the following (amounts
in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- ----- ------
<S> <C> <C> <C>
Deferred:
U.S.--federal................................... $(14,348) $(344) $1,475
U.S.--state..................................... (820) (20) 84
Canada.......................................... 54 500 248
-------- ----- ------
$(15,114) $ 136 $1,807
======== ===== ======
</TABLE>
A reconciliation of the Company's United States income tax provision
(benefit) computed by applying the statutory United States federal income tax
rate to the Company's income (loss) before income taxes for the years ended
December 31, 1998, 1997 and 1996 is presented in the following table (amounts
in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- ------- ------
<S> <C> <C> <C>
United States federal income taxes (benefit) at
statutory rate of 35%.............................. $(13,828) $ 702 $2,118
Increases (reductions) resulting from:
Canadian earnings not subject to United States
taxes............................................ (392) (1,146) (684)
Canadian income taxes............................. 54 500 248
State income taxes................................ (820) (20) 84
Other............................................. (128) 100 41
-------- ------- ------
$(15,114) $ 136 $1,807
======== ======= ======
</TABLE>
40
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
Deferred tax assets and liabilities consist of the following at December 31,
1998 and 1997 (amounts in thousands):
<TABLE>
<CAPTION>
1998 1997
------- --------
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforward--U.S...................... $14,884 $ 6,573
Net operating loss carryforward--Canada................... 2,775 2,318
------- --------
Gross deferred tax asset.................................... 17,659 8,891
------- --------
Deferred tax liabilities:
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--U.S............... (2,123) (8,980)
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--Canada............ (7,860) (7,703)
------- --------
Gross deferred tax liability................................ (9,983) (16,683)
------- --------
$ 7,676 $ (7,792)
======= ========
</TABLE>
As of December 31, 1998, the Company has U.S. net operating loss (NOL)
carryforwards of $40,228,000 and $33,499,000 for regular tax and alternative
minimum tax purposes, respectively. Alternative minimum tax NOL carryforwards
begin to expire in 2008 and regular tax NOL carryforwards expire as follows:
<TABLE>
<CAPTION>
NOL Carryforwards expiring in
-----------------------------
<S> <C>
2001......................................................... $ 262,000
2002......................................................... 412,000
2003......................................................... 300,000
2004......................................................... 432,000
2005......................................................... 202,000
Thereafter................................................... 38,620,000
-----------
$40,228,000
===========
</TABLE>
Certain future changes in the Company's shareholders may impose restrictions
under Section 382 on the annual utilization of a portion of its net operating
loss carryforwards.
Prior to 1998, under SFAS 109, the Company was required to increase deferred
income taxes and oil and gas properties by $3,736,000 for the deferred tax
effect of the excess of the Company's book basis of the stock acquired in the
Millarville Acquisition over the tax basis of the net assets acquired.
The provision for Canadian income taxes differs from the amount of income tax
determined by applying the Canadian statutory income tax rate to pretax
Canadian income as a result of the following (amounts in thousands):
<TABLE>
<CAPTION>
Years ended December
31,
-------------------------
1998 1997 1996
------- ------- -------
<S> <C> <C> <C>
Tax computed at statutory rate of 44.62%....... $ 500 $ 1,461 $ 872
Nondeductible crown royalties.................. 973 1,160 510
Resource allowance............................. (1,342) (1,948) (1,134)
Alberta royalty tax credit..................... (77) (173)
------- ------- -------
$ 54 $ 500 $ 248
======= ======= =======
</TABLE>
41
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
10. Stock Option and Other Employee Benefit Plans
In 1992, the Company established the 1992 PetroCorp Stock Option Plan (the
Option Plan). The Option Plan allows up to 957,357 option shares to be granted
and outstanding. The following table summarizes these options:
<TABLE>
<CAPTION>
Exercise
Options price
------- ------------
<S> <C> <C>
Outstanding at December 31, 1995.................... 717,740 $5.00-$10.00
Granted........................................... 200,000 $6.38
Forfeited......................................... (47,000) $10.00
Exercised.........................................
-------
Outstanding at December 31, 1996.................... 870,740 $5.00-$10.00
Granted...........................................
Forfeited.........................................
Exercised......................................... (5,000) $5.00
-------
Outstanding at December 31, 1997.................... 865,740 $5.00-$10.00
Granted...........................................
Forfeited.........................................
Exercised.........................................
-------
Outstanding at December 31, 1998.................... 865,740 $5.00-$10.00
=======
</TABLE>
The weighted average exercise prices for options under the Option Plan
outstanding at December 31, 1998, 1997 and 1996 were $7.86, $7.86 and $7.84,
respectively.
In October 1996, all granted stock options under the Option Plan were fully
vested and exercisable as a change in control, defined in the Option Plan as
the change in ownership of more than 30% of the outstanding common shares of
the Company, occurred after Kaiser Francis Oil Company purchased the common
shares owned by investment funds managed by First Reserve Corporation and the
common shares owned by a subsidiary of CIGNA Corporation.
In 1997, the Company established the 1997 PetroCorp Non-Employee Director
Stock Option Plan (the Director Option Plan) for the benefit of the Company's
Board of Directors. This plan allows up to 75,000 option shares to be granted
and outstanding. The following table summarizes these options.
<TABLE>
<CAPTION>
Exercise
Options price
------- -----------
<S> <C> <C>
Outstanding at December 31, 1996......................
Granted............................................. 25,000 $8.63
Forfeited...........................................
Exercised...........................................
------
Outstanding at December 31, 1997...................... 25,000 $8.63
Granted............................................. 6,000 $8.25
Forfeited...........................................
Exercised...........................................
------
Outstanding at December 31, 1998.................... 31,000 $8.25-$8.63
======
</TABLE>
The Director Options were fully vested at the date of grant.
42
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
Stock options under both plans expire ten years from the date of grant.
The Company adopted SFAS No. 123, "Accounting for Stock Based Compensation,"
effective July 1, 1996. While SFAS No. 123 encourages entities to adopt the
fair value based method of accounting for their stock-based compensation plans,
the Company has elected to continue to utilize the intrinsic value method under
Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued
to Employees." Accordingly, no compensation expense has been recognized for
these stock-based compensation plans. Had compensation cost for the Option Plan
and the Director Option Plan been determined based upon the fair value at the
grant date for awards under the plans consistent with the methodology
prescribed under SFAS No. 123, the Company's 1998 and 1997 net income and
earnings per share would have been reduced by approximately $16,000 and
$79,000, or nil and $0.01 per share, respectively. The fair value of the
options granted during 1998 is estimated as $26,000 on the date of grant using
the Black-Scholes option-pricing model with the following assumptions: dividend
yield of 0%, volatility of 26%, risk-free interest rate of 5.8% and an expected
life of ten years.
Effective January 1, 1993, the Company established a savings plan, which is
available to eligible employees and qualifies as a deferred compensation plan
under Section 401(k) of the Internal Revenue Code. The Company matches employee
contributions for an amount up to 6% of each employee's salary. The Company's
contributions to the plan, which are charged to expense, totaled $192,000,
$188,000 and $208,000 in 1998, 1997 and 1996, respectively.
11. Earnings Per Share
The following is a reconciliation of the numerators and denominators of the
basic and diluted per share computations for the periods presented.
<TABLE>
<CAPTION>
Per share
Income Shares amount
-------- ------ ---------
<S> <C> <C> <C>
Year ended December 31, 1998:
Basic EPS:
Net loss..................................... $(24,395) 8,637 $(2.82)
Effect of dilutive securities:
Options...................................... 62
-------- ----- ------
Diluted EPS:
Net loss..................................... $(24,395) 8,699 $(2.82)
======== ===== ======
Year ended December 31, 1997:
Basic EPS:
Net income................................... $ 1,870 8,586 $ 0.22
Effect of dilutive securities:
Options...................................... 102
-------- ----- ------
Diluted EPS:
Net income................................... $ 1,870 8,688 $ 0.22
======== ===== ======
Year ended December 31, 1996:
Basic EPS:
Net income................................... $ 4,244 8,585 $ 0.49
Effect of dilutive securities:
Options...................................... 84
-------- ----- ------
Diluted EPS:
Net income................................... $ 4,244 8,669 $ 0.49
======== ===== ======
</TABLE>
43
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
The 1998 $2.82 loss per share does not include the effect of dilutive
securities as their impact would be antidilutive given the Company's loss
position.
Options to purchase 415,000, 445,740 and 445,740 shares of common stock at
$8.25-10.00, $10.00 and $10.00 per share were outstanding during the years
ended December 31, 1998, 1997 and 1996 but were not included in the computation
of diluted EPS because the options exercise price was greater than the average
market price of the common shares.
12. Geographic Area Information
The principal business of the Company is oil and gas, which consists of the
exploration, development, acquisition, exploitation and operation of oil and
gas properties and the production and sale of crude oil and natural gas in
North America. Pertinent information with respect to the Company's oil and gas
business is presented in the following table (amounts in thousands):
<TABLE>
<CAPTION>
United General
States Canada Corporate Total
-------- ------- --------- --------
<S> <C> <C> <C> <C>
1998:
Revenues............................... $ 15,911 $ 9,296 $ 25,207
Income (loss) from operations.......... (35,593) 3,381 $(4,840) (37,052)
Depreciation, depletion and
amortization.......................... 12,511 3,698 359 16,568
Capital expenditures................... 11,673 7,653 68 19,394
Identifiable assets at December 31..... 64,408 38,930 654 103,992
1997:
Revenues............................... $ 24,068 $11,026 $ 35,094
Income (loss) from operations.......... 4,902 5,748 $(5,627) 5,023
Depreciation, depletion and
amortization.......................... 12,925 3,565 575 17,065
Capital expenditures................... 20,565 7,172 309 28,046
Identifiable assets at December 31..... 88,132 41,803 989 130,924
1996:
Revenues............................... $ 25,452 $ 6,094 $ 31,546
Income (loss) from operations.......... 9,446 3,433 $(5,301) 7,578
Depreciation, depletion and
amortization.......................... 9,886 1,918 629 12,433
Capital expenditures................... 15,201 13,899 412 29,512
Identifiable assets at December 31..... 80,706 40,961 1,197 122,864
</TABLE>
The following table reflects purchasers which accounted for more than 10% of
the Company's oil and gas revenues:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Pan-Alberta Gas Ltd........................................ 23% 21% 17%
EOTT Energy Operating Limited Partnership.................. 10% 26% 20%
Conoco Inc................................................. 10%
Sun Refining and Marketing Company......................... 14%
</TABLE>
During 1998 and prior, the majority of the Company's Canadian gas was
dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian
aggregator. However, as part of a legal settlement effective December 31, 1998,
approximately 50% of PetroCorp's dedicated gas volumes have been released
44
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
from Pan-Alberta contracts. These released volumes are now sold on the spot
market at prevailing prices. The Company does not believe the loss of any
purchaser would have a material adverse effect on its financial position since
the Company believes alternative sales arrangements could be made on relatively
comparable terms.
13. Hedging Program and Fair Value of Financial Instruments
Hedging Program
During 1996, the Company utilized hedging transactions to manage its exposure
to price fluctuations on its sales of oil and natural gas. The Company used oil
and natural gas futures contracts traded on the NYMEX to hedge its oil and gas
sales. Realized gains and losses from the Company's hedging activities were
included in oil and gas revenues in the period of the hedged production.
The Company recorded realized hedging losses of $918,000 in 1996. No hedges
were in place in 1997 or 1998.
Fair Value of Financial Instruments
The following information discloses the fair value of the Company's financial
instruments in accordance with SFAS 107, "Disclosures About Fair Value of
Financial Instruments" (amounts in thousands):
<TABLE>
<CAPTION>
Carrying Fair
amount value
-------- -------
<S> <C> <C>
1998:
Long-term debt:
Series B, 7.55% senior notes.......................... $20,275 $26,505
1997:
Long-term debt:
Series B, 7.55% senior notes.......................... 23,300 23,772
1996:
Long-term debt:
Series B, 7.55% senior notes.......................... 26,275 27,105
</TABLE>
The carrying amounts approximate fair value for the Company's cash and cash
equivalents, accounts receivable, accounts payable, the Series A, senior
adjustable rate notes and bank debt. Due to the nature and terms of the
Nonrecourse Notes Payable, the Company believes that it is not practicable to
estimate the fair value. The Company estimates the fair value of the Series B,
7.55% senior notes using discounted cash flow analysis based on interest rates
in effect at year end for the Company's Series A, senior adjustable rate notes.
14. Commitments and Contingencies
The Company has entered into operating lease agreements with noncancelable
terms in excess of one year for office space. Future minimum lease payments are
$506,000, $528,000, $447,000, $419,000 and nil for the years ended December 31,
1999, 2000, 2001, 2002 and 2003, respectively. Total rental expense for office
space for the years ended December 31, 1998, 1997 and 1996 was $560,000,
$648,000 and $646,000, respectively.
45
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1998, 1997 and 1996
There are other 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 or results of operations.
15. Related Party Transactions
The Company has engaged an engineering consulting company to procure certain
services and equipment pertaining to its Canadian operations. The consulting
company solicits bids from various vendors in order to obtain competitive
pricing. During 1998 and 1997, the consulting company procured $236,000 and
$148,000 in an arm's-length transaction from an equipment supplier partly owned
by a director of the Company's Canadian subsidiaries who is a relative of the
Company's Chief Executive Officer.
The Company is a joint-interest owner in a project operated by Kaiser Francis
Oil Company, a shareholder affiliate. During 1998, 1997 and 1996, the Company
remitted $181,000, $914,000 and $133,000, respectively, to Kaiser Francis as
payment of the Company's share of the joint operation. Amounts payable to
Kaiser Francis at December 31, 1998 and 1997 were $5,000 and $97,000,
respectively.
46
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
December 31, 1998, 1997 and 1996
(unaudited)
Costs Incurred in Oil and Gas Producing Activities
Presented below are costs incurred in petroleum property acquisition,
exploration and development activities (amounts in thousands):
<TABLE>
<CAPTION>
U.S. Canada Total
------- ------- -------
<S> <C> <C> <C>
1998:
Acquisition of properties:
Proved properties.................................... $ 4,260 $ 595 $ 4,855
Unproved properties.................................. 1,227 1,227
Exploration costs..................................... 3,168 4,436 7,604
Development costs..................................... 2,861 1,713 4,574
------- ------- -------
Total.................................................. $11,516 $ 6,744 $18,260
======= ======= =======
1997:
Acquisition of properties:
Proved properties.................................... $ 9,993 $ 954 $10,947
Unproved properties.................................. 1,671 537 2,208
Exploration costs..................................... 4,827 3,757 8,584
Development costs..................................... 4,047 1,639 5,686
------- ------- -------
Total.............................................. $20,538 $ 6,887 $27,425
======= ======= =======
1996:
Acquisition of properties:
Proved properties.................................... $ 5,157 $11,468 $16,625
Unproved properties.................................. 645 861 1,506
Exploration costs..................................... 3,029 770 3,799
Development costs..................................... 6,214 539 6,753
------- ------- -------
Total.............................................. $15,045 $13,638 $28,683
======= ======= =======
</TABLE>
Included in the above amounts for the years ended December 31, 1998, 1997 and
1996 were $1,811,000, $1,897,000 and $1,690,000, respectively, of capitalized
internal costs related to property acquisition, exploration and development.
Under SFAS 109, the Company was required to increase deferred income taxes and
oil and gas properties by $3,736,000 for the deferred tax effect of the excess
of the Company's book basis of the stock acquired in the Millarville
Acquisition over the tax basis of the net assets acquired. Such increase in oil
and gas properties is not included in the above amounts.
47
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents total capitalized costs of proved and unproved
properties and accumulated depreciation, depletion and amortization related to
petroleum producing operations (amounts in thousands):
<TABLE>
<CAPTION>
U.S. Canada Total
--------- -------- ---------
<S> <C> <C> <C>
1998:
Proved properties............................ $ 168,071 $ 40,283 $ 208,354
Unproved properties.......................... 7,417 1,734 9,151
--------- -------- ---------
175,488 42,017 217,505
Accumulated depreciation, depletion and
amortization................................ (133,914) (10,261) (144,175)
--------- -------- ---------
$ 41,574 $ 31,756 $ 73,330
========= ======== =========
1997:
Proved properties............................ $ 157,370 $ 37,900 $ 195,270
Unproved properties.......................... 7,877 1,715 9,592
--------- -------- ---------
165,247 39,615 204,862
Accumulated depreciation, depletion and
amortization................................ (88,226) (8,006) (96,232)
--------- -------- ---------
$ 77,021 $ 31,609 $ 108,630
========= ======== =========
1996:
Proved properties............................ $ 141,096 $ 33,228 $ 174,324
Unproved properties.......................... 3,887 1,392 5,279
--------- -------- ---------
144,983 34,620 179,603
Accumulated depreciation, depletion and
amortization................................ (75,638) (5,525) (81,163)
--------- -------- ---------
$ 69,345 $ 29,095 $ 98,440
========= ======== =========
</TABLE>
Of the unproved properties capitalized cost at December 31, 1998,
approximately $1,627,000 and $4,174,000 was incurred in 1998 and 1997,
respectively. The Company anticipates evaluating these properties during
subsequent years.
48
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
Results of Operations From Petroleum Producing Activities
The results of operations from petroleum producing activities, which do not
include revenues associated with the production and sale of sulfur, are as
follows (amounts in thousands):
<TABLE>
<CAPTION>
U.S. Canada Total
-------- ------ --------
<S> <C> <C> <C>
1998:
Revenues......................................... $ 15,911 $7,710 $ 23,621
Production costs................................. (5,171) (2,173) (7,344)
Depreciation, depletion and amortization......... (12,105) (2,856) (14,961)
Oil and gas property valuation adjustment........ (33,600) (33,600)
Income tax benefit (expense)..................... (12,937) 134 (12,803)
-------- ------ --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................. $(47,902) $2,815 $(45,087)
======== ====== ========
1997:
Revenues......................................... $ 24,068 $9,434 $ 33,502
Production costs................................. (6,080) (1,713) (7,793)
Depreciation, depletion and amortization......... (12,589) (2,794) (15,383)
Income tax expense............................... (1,998) (739) (2,737)
-------- ------ --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................. $ 3,401 $4,188 $ 7,589
======== ====== ========
1996:
Revenues......................................... $ 25,329 $4,389 $ 29,718
Production costs................................. (5,917) (743) (6,660)
Depreciation, depletion and amortization......... (9,700) (1,088) (10,788)
Income tax expense............................... (3,593) (307) (3,900)
-------- ------ --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................. $ 6,119 $2,251 $ 8,370
======== ====== ========
</TABLE>
Reserve Quantities
Estimates of proved reserves of the Company and the related standardized
measure of discounted future net cash flow information are based on the reports
of independent petroleum engineers. These estimates represent the Company's
interest in the reserves associated with properties held directly and its
proportionate share of reserves held indirectly through partnerships or joint
ventures.
49
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
The Company's estimates of its proved reserves and proved developed reserves
of oil and gas as of December 31, 1998, 1997 and 1996 and the changes in its
proved reserves are as follows:
<TABLE>
<CAPTION>
U.S. Canada Total
--------------- -------------- ---------------
Oil Gas Oil Gas Oil Gas
(Mbbls) (MMcf) (Mbbls) (MMcf) (Mbbls) (MMcf)
------- ------ ------- ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
1998:
Proved reserves:
Beginning of year............ 3,473 27,279 1,562 60,025 5,035 87,304
Production................... (422) (4,932) (143) (4,579) (565) (9,511)
Purchase of minerals-in-
place....................... 22 1,807 4 382 26 2,189
Extensions and discoveries... 11 694 155 4,613 166 5,307
Sales of minerals-in-place... (53) (3) (48) (2,746) (101) (2,749)
Revisions to previous
estimates................... (453) (2,875) (118) (273) (571) (3,148)
------ ------ ----- ------ ------ ------
End of year.................. 2,578 21,970 1,412 57,422 3,990 79,392
====== ====== ===== ====== ====== ======
Proved developed reserves:
Beginning of year............ 3,385 24,011 1,469 55,204 4,854 79,215
====== ====== ===== ====== ====== ======
End of year.................. 2,499 19,454 1,081 47,460 3,580 66,914
====== ====== ===== ====== ====== ======
1997:
Proved reserves:
Beginning of year............ 4,108 26,620 1,124 54,153 5,232 80,773
Production................... (580) (4,853) (142) (4,787) (722) (9,640)
Purchase of minerals-in-
place....................... 228 5,830 21 408 249 6,238
Extensions and discoveries... 72 1,553 248 12,795 320 14,348
Sales of minerals-in-place... (19) (840) (19) (840)
Revisions to previous
estimates................... (355) (1,871) 330 (1,704) (25) (3,575)
------ ------ ----- ------ ------ ------
End of year.................. 3,473 27,279 1,562 60,025 5,035 87,304
====== ====== ===== ====== ====== ======
Proved developed reserves:
Beginning of year............ 2,414 22,517 941 46,125 3,355 68,642
====== ====== ===== ====== ====== ======
End of year.................. 3,385 24,011 1,469 55,204 4,854 79,215
====== ====== ===== ====== ====== ======
1996:
Proved reserves:
Beginning of year............ 6,740 29,345 24 53,496 6,764 82,841
Production................... (662) (5,155) (5) (3,182) (667) (8,337)
Purchase of minerals-in-
place....................... 281 3,187 1,107 6,787 1,388 9,974
Extensions and discoveries... 388 3,098 5 2,139 393 5,237
Sales of minerals-in-place... (49) (1,655) (5,858) (49) (7,513)
Revisions to previous
estimates................... (2,590) (2,200) (7) 771 (2,597) (1,429)
------ ------ ----- ------ ------ ------
End of year.................. 4,108 26,620 1,124 54,153 5,232 80,773
====== ====== ===== ====== ====== ======
Proved developed reserves:
Beginning of year............ 2,617 28,256 21 45,339 2,638 73,595
====== ====== ===== ====== ====== ======
End of year.................. 2,414 22,517 941 46,125 3,355 68,642
====== ====== ===== ====== ====== ======
</TABLE>
50
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows was calculated
by applying current prices to estimated future production, less future
expenditures (based on current costs) to be incurred in developing and
producing such proved reserves and the estimated effect of future income taxes
based on the current tax law. The resulting future net cash flows were
discounted using a rate of 10% per annum.
The standardized measure of discounted future net cash flow amounts contained
in the following tabulation do not purport to represent the fair market value
of oil and gas properties. No value has been given to unproved properties.
There are significant uncertainties inherent in estimating quantities of proved
reserves and in projecting rates of production and the timing and amount of
future costs. Future realization of oil and gas prices over the remaining
reserve lives may vary significantly from current prices. In addition, the
method of valuation utilized, based on current prices and costs and the use of
a 10% discount rate, is not necessarily appropriate for determining fair value.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (amounts in thousands):
<TABLE>
<CAPTION>
U.S. Canada Total
-------- -------- --------
<S> <C> <C> <C>
1998:
Future gross revenues.............................. $ 73,407 $107,803 $181,210
Less--future costs:
Production........................................ 27,841 17,501 45,342
Development and dismantlement..................... 2,094 3,719 5,813
-------- -------- --------
Future net cash flows before income taxes.......... 43,472 86,583 130,055
Less--10% annual discount for estimated timing of
cash flows........................................ 12,508 39,535 52,043
-------- -------- --------
Present value of future net cash flows before
income taxes...................................... 30,964 47,048 78,012
Less--present value of future income taxes......... 16,470 16,470
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 30,964 $ 30,578 $ 61,542
======== ======== ========
1997:
Future gross revenues.............................. $131,220 $112,021 $243,241
Less--future costs:
Production........................................ 28,274 36,584 64,858
Development and dismantlement..................... 3,519 3,735 7,254
-------- -------- --------
Future net cash flows before income taxes.......... 99,427 71,702 171,129
Less--10% annual discount for estimated timing of
cash flows........................................ 30,800 29,517 60,317
-------- -------- --------
Present value of future net cash flows before
income taxes...................................... 68,627 42,185 110,812
Less--present value of future income taxes......... 7,388 11,137 18,525
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 61,239 $ 31,048 $ 92,287
======== ======== ========
1996:
Future gross revenues.............................. $201,711 $156,207 $357,918
Less--future costs:
Production........................................ 38,528 29,367 67,895
Development and dismantlement..................... 4,119 3,487 7,606
-------- -------- --------
Future net cash flows before income taxes.......... 159,064 123,353 282,417
Less--10% annual discount for estimated timing of
cash flows........................................ 55,919 49,741 105,660
-------- -------- --------
Present value of future net cash flows before
income taxes...................................... 103,145 73,612 176,757
Less--present value of future income taxes......... 23,176 22,202 45,378
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 79,969 $ 51,410 $131,379
======== ======== ========
</TABLE>
51
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows (amounts in
thousands):
<TABLE>
<CAPTION>
U.S. Canada Total
-------- ------- --------
<S> <C> <C> <C>
1998:
Standardized measure--beginning of period........ $ 61,239 $31,048 $ 92,287
Sales of oil and gas produced, net of production
costs.......................................... (10,740) (5,537) (16,277)
Purchases of minerals-in-place.................. 2,547 437 2,984
Extensions and discoveries...................... 609 2,833 3,442
Sales of minerals-in-place...................... (266) (1,432) (1,698)
Net changes in prices and production costs...... (29,854) 11,599 (18,255)
Development costs incurred and changes in
estimated future development and dismantlement
costs.......................................... 1,870 714 2,584
Revisions to previous quantity estimates........ (4,790) (1,191) (5,981)
Accretion of discount........................... 6,863 4,219 11,082
Changes in timing of production and other....... (4,378) (6,622) (11,000)
Net changes in income taxes..................... 7,864 (5,490) 2,374
-------- ------- --------
Standardized measure--end of period.............. $ 30,964 $30,578 $ 61,542
======== ======= ========
1997:
Standardized measure--beginning of period........ $ 79,969 $51,410 $131,379
Sales of oil and gas produced, net of production
costs.......................................... (17,988) (7,721) (25,709)
Purchases of minerals-in-place.................. 14,138 382 14,520
Extensions and discoveries...................... 2,371 7,296 9,667
Sales of minerals-in-place...................... (582) (582)
Net changes in prices and production costs...... (35,621) (35,279) (70,900)
Development costs incurred and changes in
estimated future development and dismantlement
costs.......................................... 2,086 1,367 3,453
Revisions to previous quantity estimates........ (5,479) 175 (5,304)
Accretion of discount........................... 10,315 7,361 17,676
Changes in timing of production and other....... (5,052) (4,775) (9,827)
Net changes in income taxes..................... 16,500 11,414 27,914
-------- ------- --------
Standardized measure--end of period.............. $ 61,239 $31,048 $ 92,287
======== ======= ========
1996:
Standardized measure--beginning of period........ $ 65,322 $19,489 $ 84,811
Sales of oil and gas produced, net of production
costs.......................................... (19,412) (3,646) (23,058)
Purchases of minerals-in-place.................. 8,840 16,834 25,674
Extensions and discoveries...................... 11,010 3,038 14,048
Sales of minerals-in-place...................... (1,562) (3,065) (4,627)
Net changes in prices and production costs...... 48,122 36,851 84,973
Development costs incurred and changes in
estimated future development and dismantlement
costs.......................................... 4,276 (50) 4,226
Revisions to previous quantity estimates........ (33,836) 884 (32,952)
Accretion of discount........................... 7,825 2,255 10,080
Changes in timing of production and other....... (770) (2,113) (2,883)
Net changes in income taxes..................... (9,846) (19,067) (28,913)
-------- ------- --------
Standardized measure--end of period.............. $ 79,969 $51,410 $131,379
======== ======= ========
</TABLE>
52
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
The standardized measure amounts are based on current prices at each year end
and reflect overall weighted average prices of:
<TABLE>
<CAPTION>
U.S. Canada Total
------ ------ ------
<S> <C> <C> <C>
1998:
Oil (per BBL)............................................ $10.15 $ 8.63 $ 9.63
Gas (per Mcf)............................................ 2.15 1.66 1.80
1997:
Oil (per BBL)............................................ $17.31 $15.18 $16.65
Gas (per Mcf)............................................ 2.61 1.46 1.84
1996:
Oil (per BBL)............................................ $25.24 $23.18 $24.80
Gas (per Mcf)............................................ 3.68 2.40 2.82
</TABLE>
Information relating to sulfur in Canada which has not been included in the
standardized measure is summarized as follows:
<TABLE>
<CAPTION>
1998 1997 1996
-------- ---------- --------
<S> <C> <C> <C>
Revenues for the year ended December 31........... $ 55,000 $ 183,000 $ 99,000
Production (long tons) for the year ended December
31............................................... 15,000 15,546 13,337
Estimated proved reserves (long tons) as of
December 31...................................... 221,000 202,000 191,000
Present value (10%), before income taxes, of
future net revenues.............................. 468,000 1,080,000 132,000
Price per long ton, net of transportation costs,
used to determine future revenues at December 31. $ 3.90 $ 9.36 $ 1.16
</TABLE>
53
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1998, 1997 and 1996
(unaudited)
Summarized Quarterly Financial Data
(unaudited)
(amounts in thousands, except per share data)
<TABLE>
<CAPTION>
First Second Third Fourth
quarter quarter quarter quarter Year
------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1998:
Revenues......................... $6,506 $6,086 $ 6,173 $ 6,442 $ 25,207
Gross profit(1).................. 728 157 20 (33,475) (32,570)
Income from operations........... (450) (998) (1,106) (34,498) (37,052)
Net loss......................... (636) (1,029) (764) (21,966) (24,395)
Net income per share--basic...... $(0.07) $(0.12) $ (0.09) $ (2.54) $ (2.82)
Year ended December 31, 1997:
Revenues......................... $9,394 $7,586 $ 8,738 $ 9,376 $ 35,094
Gross profit(1).................. 3,655 1,752 2,366 2,302 10,075
Income from operations........... 2,357 401 1,224 1,041 5,023
Net income....................... 975 244 227 424 1,870
Net income per share--basic...... $ 0.11 $ 0.03 $ 0.03 $ 0.05 $ 0.22
</TABLE>
- --------
(1) Revenues less operating expenses other than general and administrative.
54
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this amended report to be
signed on its behalf by the undersigned, thereunto duly authorized.
PetroCorp Incorporated
(Registrant)
/s/ W. Neil McBean
By:__________________________________
W. Neil McBean
President and Chief Executive
Officer
(Principal Executive Officer)
Date: April 12, 1999
55
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
No. Item
--- ----
<C> <S>
23.1 --Consent of PricewaterhouseCoopers LLP
</TABLE>
56
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-8 (No. 33-75870), Form S-8 (No. 333-05645) and on Form S-8
(No. 333-52955) of PetroCorp Incorporated of our report dated March 30, 1999,
appearing on page 27 of the Annual Report of Petrocorp Incorporated on
Form 10-K for the year ended December 31, 1998.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
April 12, 1999
