<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
----------------
COMMISSION FILE NUMBER 0-22650
----------------
PETROCORP INCORPORATED
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0380430
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
SUITE 300, NORTH ATRIUM
16800 GREENSPOINT DRIVE 77060-2391
HOUSTON, TEXAS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 875-2500
----------------
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 March 17, 1998 was $35,307,342. Indicate the number of shares
outstanding of each of the registrant's classes of common stock, as of March
17, 1998:
Common Stock, par value $.01 per share: 8,591,519
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held May 7, 1998 (to be filed within 120 days of the close of registrant's
fiscal year) is incorporated by reference into Part III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
ITEM TITLE PAGE
---- ----- ----
PART I
<C> <S> <C>
1 Business.......................................................... 1
2 Properties........................................................ 8
3 Legal Proceedings................................................. 16
4 Submission of Matters to a Vote of Security Holders............... 16
PART II
5 Market for Registrant's Common Equity and Related Stockholder
Matters........................................................... 16
6 Selected Financial Data........................................... 17
7 Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 18
7A Quantitative and Qualitative Disclosure about Market Risk......... 24
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, "BOE" means barrel of oil equivalent determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, "MBOE" means thousand
barrels of oil equivalents, "MMBOE" means million barrels of oil equivalents,
"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.
<PAGE>
PART I
ITEM 1. BUSINESS.
GENERAL
PetroCorp Incorporated is an independent energy company engaged in the
exploration, development and acquisition 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, 1997, the Company's proved reserves totaled 5.0 MMBbls of oil
and 87.3 Bcf of natural gas and had an estimated pretax present value of future
net revenues (PV-10) of $112 million. On a BOE 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 $9.6 million,
as well as interests in natural gas processing and gathering facilities with a
net book value of $3.9 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
Historically, the Company's strategy has been to increase its reserves, cash
flow and underlying net asset value through a combination of exploration and
development and acquisition activities.
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 3-D seismic technology)
available to its exploration and development teams, and developed major
exploration and development projects in Mississippi, Oklahoma, Texas and
Alberta, Canada. PetroCorp has the capability to perform reprocessing,
visualization and interpretation of its seismic database completely in-house.
Acquisition Strategy. PetroCorp has grown, in large part, through the
acquisition of producing oil and gas properties, and it intends to continue to
take advantage of opportunities to purchase properties with proved reserves
that meet the Company's acquisition criteria. Prevailing market conditions
significantly influence the implementation of the Company's acquisition
strategy. The Company generally focuses on acquisitions of long-lived natural
gas reserves located onshore in North America and prefers acquisitions that
provide potential through additional development or exploitation efforts as
well as exploratory drilling opportunities.
EXPLORATION AND DEVELOPMENT ACTIVITIES
In recent years, the Company has placed increasing emphasis on the
exploration and development component of its business strategy.
Mississippi Salt Basin. The Mississippi Salt Basin is one of PetroCorp's most
active and aggressive exploration plays. Through year-end 1997, PetroCorp had
drilled five exploratory prospects in Wayne, Greene and Smith Counties,
yielding two new field discoveries and seven successful wells out of 10 total
1
<PAGE>
wells drilled. The most recent completion was in the Smithtown Field in Greene
County, Mississippi, where the Southern Mineral Corp. #2 well was successfully
completed in the Hosston formation at a depth below 14,000 feet. After fracture
stimulation, the well is producing 300 BOPD. PetroCorp owns a 25% working
interest in the well. Drilling is expected to begin in April 1998 on the Quito
Prospect, which is a 17,000 foot test in the Cotton Valley formation. PetroCorp
retains a 20% working interest in the prospect, which is supported by 3-D
seismic acquired last year. In September 1996, PetroCorp entered into a joint
venture agreement with a subsidiary of Shell Oil Company (Shell) which allows
PetroCorp to use approximately 13,000 line-miles of Shell's 2-D seismic
database covering 18 counties. Thus far, the Company has ordered approximately
2,000 miles of the data, and after in-house reprocessing has identified
numerous leads. Leasing has been completed on the first two exploration
projects. One is ready for drilling, while the second will require a 3-D
seismic survey to further define the initial drilling location.
Hanlan-Robb Area. The Company owns interests in five proved developed
producing fields and two proved developed nonproducing fields in the Hanlan-
Robb area of western Alberta, Canada. It intends to connect the two
nonproducing fields to the Hanlan-Robb gas gathering system as declining
production from the currently producing fields makes capacity available at the
gas processing plant in which the Company owns an interest. During 1997, the
Company continued its strategy of drilling horizontal lateral wells from
existing wells in the area in order to improve productivity and to mitigate the
impact of natural production declines in the fields. To date, five horizontal
wells have been completed, resulting in a three or four fold increase in
production from each well.
Recent activity for the biggest field in the area, the Hanlan Swan Hills
Unit, includes the 1996 installation and start-up of a $10 million field
compression facility designed to extend the life of the field into the next
century. In February 1997, the Company increased its share of production in the
Unit following a payout to its joint venture partner. The Company currently
owns a 7.6% working interest in the Unit, which is operated by Petro-Canada. In
1997, the Hanlan 6-23 well was deviated laterally almost 1,000 feet to a
measured depth of 16,880 feet, resulting in an increase in the production rate
from approximately 6 MMcf/D to 24 MMcf/D. The Hanlan 7-27 well was horizontally
sidetracked at a measured depth of 16,904 feet, resulting in increased
production from approximately 4 MMcf/D to 12.5 MMcf/D.
Located approximately seven miles east of the plant, the Erith 8-13 well was
producing approximately 6 MMcf/D and now has been tested at 21 MMcf/D following
horizontal sidetracking at a depth of 14,300 feet. The Company owns a 12.5%
working interest in the well.
Approximately ten miles west of the plant are the Shaw/Basing and
Coalbranch/Coalspur areas. After acquiring in excess of 100 line-miles of high
resolution 2-D seismic data in 1995, PetroCorp is now actively involved in two
separate exploration plays in the area. Two wells have been successfully re-
entered and drilled horizontally in the 12,500 foot Mississippian Turner Valley
formation. The Coalbranch 16-33 and the Coalspur 9-27 are now producing at 5.1
MMcf/D and 2.1 MMcf/D, respectively. The other exploration play in this area
involves drilling for the shallower Cardium formation at 5,000 to 7,000 depth.
The Shaw 7-8 is now producing 4 MMcf/D. The Basing 10-25 is currently testing.
In 1997, the Basing 2-9 was drilled 1,600 feet laterally at approximately
12,000 feet and tested at 4.5 MMcf/D. It is currently being tied into the
plant, with production expected in the second quarter of 1998.
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.
Worsley Field. The largest of the producing properties acquired in the year-
end 1996 Millarville Acquisition (described below) is the Worsley property in
northwest Alberta, Canada. The Company has modified the pipeline system,
installed compression and commenced sales of 800 Mcf/D of natural gas that had
previously been flared or shut-in. Additional development activity is planned
in 1998 in the field.
2
<PAGE>
McLeod Field. As part of the Millarville Acquisition, the Company acquired
one oil shut-in well in this field in west central Alberta, Canada. During
1997, three additional oil wells and two natural gas wells were drilled with a
100% success rate. The Company is the operator and owns working interests in
these wells ranging from 50% to 100%. Completion and tie-in of these new wells
is planned for 1998. Following additions to its acreage position in this area
during 1997, the Company holds 6,080 gross (3,776 net) acres in the field.
Trochu Area. Also part of the Millarville Acquisition and a subsequent
acquisition, the Company acquired a 100% working interest in three oil wells
and two natural gas wells in this area of central Alberta, Canada. In December
1997, the Company completed a 3-D seismic survey that will be used to plan
further drilling for later in 1998. The Company operates all five wells.
Oklahoma. North of Oklahoma City in Edmond, Oklahoma, the Company drilled the
Marks 6B-2 well to a depth of 6,500 feet, encountering 15 feet of net pay in
the Prue sand. This well is on trend with the successful Jackson 2B-4 well
drilled in 1996, which is currently producing 2.1 MMcf/D. Due to its location
in an urban environment, testing on the new well is awaiting a pipeline
connection, which is expected by mid-year 1998. The Company owns a 75% working
interest in the Marks 6B-2 and a 47% interest in the Jackson 2B-4. The Company
is also active in northern Oklahoma. Exploration activities are currently
focused on Cottage Grove and Tonkawa gas targets at 4,000-5,000 feet within the
Misener Trend/Northern Shelf Play of the Anadarko Basin. This activity has been
driven by the integration of PetroCorp's extensive seismic database, which now
includes in excess of 2,000 miles of 2-D and 12 square miles of 3-D seismic
data in this area.
In April 1996, following approval of the Oklahoma Corporation Commission the
SW Oklahoma City Unit was formed for the purposes of water flooding and
repressurizing the field to improve ultimate oil recovery. Water injection
commenced in September 1996. Phase I of the program was completed during the
third quarter of 1997, and oil production response is expected in 1999. The
PetroCorp-operated, 56 well unit has produced 2.4 MMBbls of oil and 19.8 Bcf of
gas through year-end. PetroCorp owns an 86.4% working interest in the SW
Oklahoma City Unit which is currently producing 235 BOPD and 3.1 MMcf/D with an
average daily injection rate of 4,400 barrels of water per day. The adjacent
Will Rogers Unit, operated by another party, has already shown a positive
response to waterflood operations initiated in 1993. PetroCorp is also
currently involved in waterflood projects on three fields in the Northern
Oklahoma Area.
Southeast Texas. In 1997, the Company participated in a 3-D seismic program
covering approximately 60 square miles in Newton County, Texas and Calcasieu
Parish, Louisiana. Primary objectives are the expanded and overpressured Yegua
formation along with the Frio Nodosaria sands. The West New York prospect (in
which the Company has a 15% interest) is currently being drilled to a targeted
depth of 12,750 feet.
ACQUISITION ACTIVITIES
In July 1997, the Company completed the acquisition of producing oil and gas
properties located primarily in Louisiana for $9.2 million (the Gulf Coast
Acquisition). Proved reserves acquired totaled 6.0 Bcf of natural gas and
200,000 barrels of oil (1.2 MMBOE). Funding for the acquisition was provided
through a new $50 million credit facility with the Toronto-Dominion Bank and
the Bank of Nova Scotia. Initial borrowing availability under this new facility
was $25 million.
The Company completed the purchase of Millarville Oil and Gas Ltd., a
privately held Canadian corporation that owned and operated properties in
Alberta, Canada, in December 1996 for a cash acquisition price of $11.8 million
(the Millarville Acquisition). Proved reserves acquired were 1.1 million
barrels of oil and 6.8 Bcf of natural gas (2.2 MMBOE).
3
<PAGE>
The Company expects to continue to pursue acquisition opportunities. The
Company's acquisition team annually screens a large number of potential
prospects; however, only a comparatively smaller number of prospects have the
potential to satisfy the Company's acquisition criteria and are studied in
detail.
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,
1997, 1996, and 1995. See Note 10 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,
--------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Net oil produced (MBbls):
United States........................................... 580 662 656
Canada.................................................. 142 5 2
------ ------ ------
Total................................................. 722 667 658
Average oil sales price (per Bbl):
United States........................................... $19.57 $19.89 $17.80
Canada.................................................. 17.19 23.12 17.86
Weighted average........................................ 19.10 19.91 17.80
Net gas produced (MMcf):
United States........................................... 4,853 5,155 6,084
Canada.................................................. 4,787 3,182 3,199
------ ------ ------
Total................................................. 9,640 8,337 9,283
Average gas sales price (per Mcf):
United States........................................... $ 2.62 $ 2.36 $ 1.62
Canada.................................................. 1.46 1.34 .90
Weighted average........................................ 2.04 1.97 1.37
Oil equivalents produced (MBOE):
United States........................................... 1,389 1,521 1,670
Canada.................................................. 940 535 535
------ ------ ------
Total................................................. 2,329 2,056 2,205
Average sales price (per BOE):
United States........................................... $17.33 $16.65 $12.89
Canada.................................................. 10.04 8.20 5.48
Weighted average........................................ 14.38 14.45 11.09
Production costs (per BOE):
United States........................................... $ 4.38 $ 3.89 $ 3.75
Canada.................................................. 1.82 1.39 1.95
Weighted average........................................ 3.35 3.24 3.31
</TABLE>
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. Currently, the majority of the
Company's Canadian gas is dedicated under long-term contracts to Pan-Alberta
Gas Ltd. (Pan-Alberta), a major Canadian gas marketer affiliated with the
pipeline authorized to gather all gas in the province of Alberta. Approximately
60% of the Company's Canadian gas is resold into the United States,
predominantly to markets in the upper midwest region. PetroCorp receives from
Pan-
4
<PAGE>
Alberta a price per Mcf equal to Pan-Alberta's resale price, less certain
costs permitted to be recovered by Pan-Alberta under the contracts.
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, 1997, Pan-Alberta (the purchaser of most
of the Company's Canadian gas) and EOTT Energy Operated Limited Partnership
(one of the Company's purchasers of oil) accounted for 21% and 26% 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 has 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 11 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.
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)
5
<PAGE>
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.
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
6
<PAGE>
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.
EMPLOYEES
At December 31, 1997, PetroCorp had 57 full-time employees.
7
<PAGE>
ITEM 2. PROPERTIES.
PRINCIPAL PROPERTIES
The Company's proved oil and gas properties are relatively concentrated.
Approximately 80% of the PV-10 from the Company's proved reserves at December
31, 1997 was attributable to eight 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, 1997, 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, 1997
------------------------------------
ESTIMATED PROVED
RESERVES
---------------------
OIL GAS
PROPERTY/AREA (MBBLS) (MMCF) MBOE PV-10
------------- ------- ------ ------ --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Hanlan-Robb.......................... 86 45,977 7,749 $ 28,173
Oklahoma City Area................... 2,006 8,328 3,394 27,691
Riceville Field...................... 121 5,389 1,019 11,954
Mississippi Salt Basin............... 479 59 489 5,103
Worsley Field........................ 699 1,442 939 4,432
Trochu Field......................... 238 3,478 818 3,876
McLeod Field......................... 269 5,704 1,220 3,767
Northern Oklahoma Area............... 219 516 305 3,116
----- ------ ------ --------
Subtotal........................... 4,117 70,893 15,933 88,112
----- ------ ------ --------
Others............................... 918 16,411 3,653 23,780
----- ------ ------ --------
Total.............................. 5,035 87,304 19,586 $111,892
===== ====== ====== ========
</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 38% of the Company's 1997 net daily gas
production. The Company has ownership interests in seven area fields, but the
majority of its Hanlan-Robb proved reserves and present value are currently
attributable to one field, the Hanlan Swan Hills Gas Unit. PetroCorp's
ownership is part of a joint venture managed by the Company with institutional
investors that collectively own 21.6% of the field. After an ownership
reversion in early 1997, PetroCorp's working interest in this field increased
by 40%, from 5.4% to 7.6%. Petro-Canada is the largest interest owner in the
area and operates the fields and the related gathering system and processing
plant.
Oklahoma City Area. Includes the SW Oklahoma City field located within the
metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect located
just north of Oklahoma City. The SW Oklahoma City field is bounded to the
southeast by the Oklahoma City Prue Unit and to the southwest by the Wheatland
and Will Rogers Units and produces oil with associated casinghead gas. As of
December 31, 1997, PetroCorp also had an undeveloped leasehold position of 815
gross (560 net) acres in the Edmond Prospect.
Riceville Field. The largest of the producing properties acquired in the Gulf
Coast Acquisition in July 1997, this field is located in Vermillion Parish,
Louisiana. PetroCorp acquired a 13.5% non-operated working interest in this two
well field which primarily produces natural gas with associated condensate.
Mississippi Salt Basin. This basin is one of PetroCorp's most active
exploration areas. At the end of 1994, the Company made a new field discovery
of oil and associated natural gas in the Maynor Creek Field
8
<PAGE>
in Wayne County, Mississippi. The largest of its two producing fields in the
basin, the Company has drilled three successful development wells there, two in
1995 and one in December 1996. PetroCorp operates the four wells in the field
and increased its 50% average working interest to 65% when it acquired a
partner's interest in October 1996. In September 1996, expanding on its
successes in the basin, the Company entered into a seismic joint venture
agreement with a subsidiary of Shell Oil Company to extend its exploration
effort into an 18-county area. Under the terms of the agreement, PetroCorp has
access to Shell's extensive 2-D seismic database in the area (approximately
13,000 line-miles of data) and other proprietary information held by Shell. As
of December 31, 1997, PetroCorp also had an undeveloped leasehold position of
18,936 gross (10,773 net) acres in this area.
Worsley Field. The largest of the producing properties acquired from
Millarville Oil & Gas Ltd. in December 1996, this field is located in northwest
Alberta, Canada and primarily produces oil and associated casinghead gas. The
Company operates seven wells in the field and 100% of the working interests. It
also owns an interest in one non-operated well. With an undeveloped leasehold
position of 160 gross (160 net) acres at December 31, 1997, the Company plans
to pursue further development of this field.
Trochu Field. The Company operates and has a 100% working interest in three
oil wells and two gas wells in this area of central Alberta, Canada. A 3-D
seismic survey shot in December 1997 will be used to delineate further drilling
in 1998 on the 960 gross (960 net) acres of undeveloped lands.
McLeod Field. This field is located in west central Alberta, Canada and
consists of one oil well acquired from Millarville and three additional oil
wells and two additional gas wells drilled in 1997. The Company operates all
these wells and holds a 50% to 100% working interest in each. Completion and
tie-in of the new wells is planned for 1998 along with further drilling on
5,920 gross (3,616 net) acres of undeveloped lands.
Northern Oklahoma Area. The Northern Oklahoma Area is located in Alfalfa and
Grant Counties in north central Oklahoma. Production is primarily oil with
associated casinghead gas from five major fields. Three of these fields are the
subject of pressure maintenance waterfloods, of which two are operated by
PetroCorp. PetroCorp continues to actively pursue both exploration and
development in the Northern Oklahoma Area, and at December 31, 1997 had an
undeveloped leasehold position of approximately 13,633 gross (9,974 net) acres.
Other Properties. Other significant properties include the Glick Field
located in Kiowa County in southern Kansas, the Harris Field located in Live
Oak County in south central Texas, and the Paradox Basin area of southwest
Colorado.
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.
9
<PAGE>
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.
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, 1997. 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, 1997
------------------------
UNITED
STATES CANADA TOTAL
------- ------- --------
<S> <C> <C> <C>
PROVED RESERVES:
Oil (MBbls)..................................... 3,473 1,562 5,035
Gas (MMcf)...................................... 27,279 60,025 87,304
Oil equivalents (MBOE).......................... 8,020 11,566 19,586
Future net revenues ($000s)(1).................... $99,427 $73,593 $173,020
Present value of future net revenues ($000s)(2)... $68,627 $43,265 $111,892
PROVED DEVELOPED RESERVES:
Oil (MBbls)..................................... 3,385 1,469 4,854
Gas (MMcf)...................................... 24,011 55,204 79,215
Oil equivalents (MBOE).......................... 7,387 10,670 18,057
Future net revenues ($000s)(1).................... $91,566 $66,874 $158,440
Present value of future net revenues ($000s)(2)... $62,632 $39,833 $102,465
</TABLE>
- --------
(1) Proved and proved developed future net revenues include $1,891,000 related
to the sale of sulfur.
(2) Proved and proved developed present values of future net revenues include
$1,080,000 related to the sale of sulphur.
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.
10
<PAGE>
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, 1997.
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, 1997.
<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 26,726 23,885 23,885
Kansas............. 5,360 3,520 667 10 6 1
Louisiana.......... 2,616 272 272 533 67 67
Mississippi........ 1,398 594 594 18,936 10,773 10,773
Oklahoma........... 42,197 15,667 11,669 20,077 12,852 12,676
Texas.............. 23,772 8,081 4,990 44,261 8,056 8,025
Other.............. 2,206 542 542 6,437 608 607
Canada:
Alberta............ 77,840 21,600 13,295 110,080 41,316 32,043
Other.............. -- -- -- 640 320 320
------- ------ ------ ------- ------ ------
Total............ 165,575 58,234 39,987 227,700 97,883 88,397
======= ====== ====== ======= ====== ======
</TABLE>
- --------
(1) Approximately 67% of net (approximately 47% of net participating interest)
undeveloped acres are covered by leases that expire during 1998.
(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, 1997, the Company had working interests in 288 gross (87
net) producing oil wells and 174 gross (46 net) producing gas wells. Of these
wells, 69 gross (17 net) oil wells and 46 gross (7 net) gas wells were in
Canada, and the remainder of the oil and gas wells were in the United States.
11
<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, 1997, 1996 and 1995 is set forth below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------
1997 1996 1995
---------------------------- ---------------------------- ----------------------------
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 8 3.5 2.9
Gas.................... 3 .6 .6 5 .1 0.0(2) 3 .8 .8
Nonproductive.......... 3 1.0 .8 5 2.2 2.2 6 3.2 3.0
--- ---- ---- --- ---- ---- --- ---- ----
Total................. 12 3.0 2.6 16 5.9 5.5 17 7.5 6.7
--- ---- ---- --- ---- ---- --- ---- ----
Exploratory:
Oil.................... 2 .6 .6 1 .3 .3 4 2.2 2.2
Gas.................... 1 .5 .5 2 .5 .4 3 1.5 1.1
Nonproductive.......... 6 2.2 2.2 6 3.5 3.5 4 2.4 2.4
--- ---- ---- --- ---- ---- --- ---- ----
Total................. 9 3.3 3.3 9 4.3 4.2 11 6.1 5.7
--- ---- ---- --- ---- ---- --- ---- ----
CANADA
Development:
Oil.................... 2 .5 .5
Gas.................... 5 1.7 1.4 1 .3 .1
Nonproductive..........
--- ---- ---- --- ---- ---- --- ---- ----
Total................. 7 2.2 1.9 1 .3 .1
--- ---- ---- --- ---- ---- --- ---- ----
Exploratory:
Oil.................... 1 1.0 1.0
Gas.................... 8 2.6 2.2 1 .3 .1
Nonproductive.......... 4 .6 .4 1 .5 .5
--- ---- ---- --- ---- ---- --- ---- ----
Total................. 13 4.2 3.6 2 .8 .6
--- ---- ---- --- ---- ---- --- ---- ----
Total................... 41 12.7 11.4 27 11.0 10.3 29 13.9 12.5
=== ==== ==== === ==== ==== === ==== ====
</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, 1997, the Company was participating in the drilling or
completion of 1 gross (.3 net) well in the United States and 2 gross (.7 net)
wells in Canada.
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 five of the Company's currently
producing Hanlan-Robb fields to the Hanlan-Robb plant. The gas processing
plant, which is operated by Petro-Canada, was commissioned in 1983 and has a
processing capacity of approximately 300 MMcf/D of natural gas. For the 12
months ended December 31, 1997, plant throughput averaged 216 MMcf/D (72% of
design capacity). In 1996, Hanlan Unit activity included installation and
start-up of a $10 million compression project. Recently, several horizontal
laterals from existing Hanlan area wells have been drilled. These projects,
along with an active exploration and development drilling program in the area,
are designed in part to mitigate natural production declines and keep the plant
operating at high utilization rates. In 1998, two additional pipelines are
expected to be connected to the facility as well as an expansion of plant
capacity, increasing throughput to approximately 340 MMcf/D of natural gas by
year-end 1998. Much of this throughput will be from third party gas for which
the plant owners will receive fees, thus reducing PetroCorp's share of plant
expenses.
12
<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 executive and divisional offices. Additionally, the Company leases
approximately 8,200 square feet in Oklahoma City, Oklahoma and approximately
4,000 square feet in Calgary, Alberta for divisional offices.
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.
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
13
<PAGE>
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, and likely will continue to make, 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.
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
14
<PAGE>
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.
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
15
<PAGE>
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 has been listed on The Nasdaq Stock Market since
October 28, 1993 and trades under the symbol PETR. The following table presents
the high and low closing prices for the Company's Common Stock for each quarter
during 1996 and 1997, and for a portion of the Company's current quarter, as
reported by The Nasdaq Stock Market.
<TABLE>
<CAPTION>
1996 1997 1998
------------------------------- ------------------------------- ------------------
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.................... $7.50 $10.00 $9.63 $10.00 $10.13 $9.13 $9.38 $10.00 $9.50
Low..................... 5.88 6.75 8.25 8.13 8.50 8.00 8.25 7.56 7.75
</TABLE>
As of March 17, 1998, the closing price for the Company's Common Stock was
$8.38 per share. As of March 17, 1998, there were approximately 560 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.
16
<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,
------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
REVENUES:
Oil and gas................ $ 33,502 $ 29,718 $ 24,448 $ 25,176 $ 30,129
Plant processing........... 1,420 1,658 1,880 1,852 2,054
Other...................... 172 170 1,037 923 705
-------- -------- -------- -------- --------
35,094 31,546 27,365 27,951 32,888
-------- -------- -------- -------- --------
EXPENSES:
Production costs........... 7,793 6,660 7,304 7,156 8,011
Depreciation, depletion and
amortization.............. 17,065 12,433 13,300 12,800 13,058
Oil and gas property
valuation adjustment...... -- -- 8,500 -- --
General and administrative. 5,052 4,672 5,544 5,067 5,210
Other operating expenses... 161 203 256 98 299
-------- -------- -------- -------- --------
30,071 23,968 34,904 25,121 26,578
-------- -------- -------- -------- --------
INCOME (LOSS) FROM
OPERATIONS.................. 5,023 7,578 (7,539) 2,830 6,310
-------- -------- -------- -------- --------
OTHER INCOME (EXPENSES):
Investment and other
income.................... 558 1,910 1,470 1,411 1,264
Interest expense........... (3,528) (3,391) (3,917) (3,229) (2,333)
Preferred dividends of
subsidiary................ -- -- -- (648) (1,214)
Other expenses............. (47) (46) (159) (131) (68)
-------- -------- -------- -------- --------
(3,017) (1,527) (2,606) (2,597) (2,351)
-------- -------- -------- -------- --------
INCOME (LOSS) BEFORE INCOME
TAXES....................... 2,006 6,051 (10,145) 233 3,959
Income tax provision
(benefit)................... 136 1,807 (608) 114 2,116
-------- -------- -------- -------- --------
INCOME (LOSS) BEFORE
CUMULATIVE EFFECT OF
ACCOUNTING CHANGE........... 1,870 4,244 (9,537) 119 1,843
Cumulative effect of
accounting change(1)........ -- -- -- -- 481
-------- -------- -------- -------- --------
NET INCOME (LOSS)............ $ 1,870 $ 4,244 $ (9,537) $ 119 $ 2,324
======== ======== ======== ======== ========
Net income (loss) per share--
basic....................... $ .22 $ 0.49 $ (1.11) $ 0.01 $ 0.33
======== ======== ======== ======== ========
Net income (loss) per share--
diluted..................... $ .22 $ 0.49 $ (1.11) $ 0.01 $ 0.33
======== ======== ======== ======== ========
Weighted average number of
common shares--basic........ 8,586 8,585 8,585 8,585 6,992
======== ======== ======== ======== ========
Weighted average number of
common shares--diluted...... 8,688 8,669 8,585 8,698 7,103
======== ======== ======== ======== ========
BALANCE SHEET DATA:
Working capital............ $ 2,638 $ 1,946 $ 6,344 $ 11,767 $ 30,156
Total assets............... 130,924 122,864 114,839 133,403 140,381
Long-term debt............. 42,192 33,462 36,513 41,587 39,200
Redeemable preferred stock
of subsidiary............. -- -- -- -- 7,691
Shareholders' equity....... 66,557 65,665 61,521 70,328 71,517
</TABLE>
- --------
(1) Effective January 1, 1993, the Company adopted Statement of Financial
Standards No. 109, "Accounting for Income Taxes."
17
<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,
--------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
PRODUCTION:
United States:
Oil (MBbls)............................................. 580 662 656
Gas (MMcf).............................................. 4,853 5,155 6,084
Oil equivalents (MBOE).................................. 1,389 1,521 1,670
Canada:
Oil (MBbls)............................................. 142 5 2
Gas (MMcf).............................................. 4,787 3,182 3,199
Oil equivalents (MBOE).................................. 940 535 535
Total:
Oil (MBbls)............................................. 722 667 658
Gas (MMcf).............................................. 9,640 8,337 9,283
Oil equivalents (MBOE).................................. 2,329 2,056 2,205
AVERAGE SALES PRICES (includes the effects of hedging):
United States:
Oil (per Bbl)........................................... $19.57 $19.89 $17.80
Gas (per Mcf)........................................... 2.62 2.36 1.62
Canada:
Oil (per Bbl)........................................... 17.19 23.12 17.86
Gas (per Mcf)........................................... 1.46 1.34 .90
Weighted average:
Oil (per Bbl)........................................... 19.10 19.91 17.80
Gas (per Mcf)........................................... 2.04 1.97 1.37
SELECTED DATA PER BOE:
Average sales price...................................... $14.38 $14.45 $11.09
Production costs......................................... 3.35 3.24 3.31
General and administrative expenses...................... 2.17 2.27 2.51
Oil and gas depreciation, depletion and amortization..... 6.60 5.24 5.22
</TABLE>
ACQUISITIONS
The Company completed the purchase of Millarville Oil and Gas Ltd., a
privately held Alberta corporation that owns and operates oil and gas
properties in Alberta, Canada, in December 1996 for a cash acquisition price of
$11.8 million (the Millarville Acquisition). In July 1997, the Company
completed the purchase of producing properties located primarily in Louisiana
for $9.2 million (the Gulf Coast Acquisition). These two acquisitions had a
significant impact on the Company's results of operations in 1997.
18
<PAGE>
RESULTS OF OPERATIONS
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 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 2,329 MBOE from 2,056 MBOE. The
increase in oil production is primarily related to the Millarville Acquisition.
The increase in natural gas production reflects the impact of the two
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 BOE slightly increased by 3% to $3.35 per BOE
from $3.24 per BOE.
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 $6.60 per BOE from $5.24 per BOE. 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 8% to $5.1 million in 1997 from $4.7 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.
19
<PAGE>
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
the Gulf Coast 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 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%.
1996 Compared to 1995
Overview. Cash flow before changes in operating assets and liabilities
increased 50% to $17.5 million in 1996 compared to $11.7 million in 1995,
primarily as a result of increased product prices and decreased cash expenses.
During 1996, the Company recorded net income of $4.2 million, or $0.49 per
share, which included $629,000, or $0.07 per share, related to the after-tax
gain on the sale of the gas gathering system in Oklahoma. In 1995, the Company
recorded a net loss of $9.5 million, or $1.11 per share, which included an
$8.5 million, or $0.99 per share, oil and gas property valuation adjustment.
Revenues. Total revenues increased 15% to $31.5 million in 1996 from $27.4
million in 1995. Oil production increased slightly to 667 MBbls from 658
MBbls. Natural gas production decreased 10% to 8,337 MMcf in 1996 from 9,283
MMcf in 1995, resulting in an overall production decrease of 7% to 2,056 MBOE
from 2,205 MBOE. The decrease in natural gas production is primarily the
result of U.S. and Canadian property sales and normal production declines in
the Company's U.S. properties.
The Company's average U.S. natural gas price increased 46% to $2.36 per Mcf
in 1996 from $1.62 per Mcf in 1995 while the average Canadian natural gas
price increased 49% to $1.34 from $0.90. The Company's composite average oil
price increased 12% to $19.91 per barrel in 1996 from $17.80 per barrel in
1995. 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 while the 1995 average price was increased by $0.49
per barrel. As a result of the increases in natural gas and oil prices,
partially offset by a decrease in production, oil and gas revenues increased
22% to $29.7 million in 1996 from $24.4 million in 1995. Plant processing
revenues declined to $1.7 million from $1.9 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. Other revenues declined 84% to $170,000 in
1996 from $1.9 million in 1995 due to reduced gas gathering fees resulting
from the March 1996 sale of the Company's Oklahoma gas gathering system, and
lower average sulfur prices of $7.40 per long-ton compared to $31.97 per long-
ton.
Production Costs. Production costs declined 9% to $6.7 million in 1996
compared to $7.3 million in 1995, while production costs per BOE decreased 2%
to $3.24 per BOE from $3.31 per BOE. The decrease in production costs in
absolute dollars and on a BOE basis resulted from the Company's focus on
reducing costs.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 7% to
$12.4 million in 1996 from $13.3 million in 1995, primarily as a result of the
decrease in production volumes. On a BOE basis, the oil and gas DD&A rate
increased slightly to $5.24 per BOE from $5.22 per BOE.
Oil and Gas Property Valuation Adjustment. At June 30, 1995, primarily as a
result of the impairment of the Company's valuation of its unproved fee
mineral interests and a decline in oil and gas prices, the Company recorded an
$8.5 million valuation adjustment to its oil and gas property balance in
accordance with the full cost method of accounting.
20
<PAGE>
General and Administrative Expenses. General and administrative expenses
decreased 16% to $4.7 million in 1996 from $5.5 million in 1995 primarily due
to a reduction in personnel associated with the Company's asset rationalization
efforts.
Investment and Other Income. Investment and other income increased 30% to
$1.9 million in 1996 from $1.5 million in 1995. In 1996, the Company included a
$1.0 million gain on the sale of its Oklahoma gas gathering system in
investment and other income. In 1995, the Company included in investment and
other income a $1.6 million settlement of a long standing gas contract claim
against Columbia Gas System and a $1.0 million loss related to the Company's
natural gas hedging activities. The hedging loss was recorded in the fourth
quarter of 1995 when certain New York Mercantile Exchange (NYMEX) natural gas
futures contracts no longer qualified for hedge accounting as a result of the
decoupling of the relationship between the pricing of natural gas futures
contracts for the first quarter of 1996 and the Company's field prices for the
same period. Absent these special items, investment and other income would have
increased 10% to $910,000 in 1996 from $826,000 in 1995 primarily as a result
of increased funds available for investment.
Interest Expense. Interest expense decreased 13% to $3.4 million in 1996 from
$3.9 million in 1995, due to reductions in outstanding debt.
Income Taxes. The Company recorded a $1.8 million income tax provision on
pre-tax income of $6.1 million in 1996 with an effective tax rate 30% compared
to an income tax benefit of $608,000 on a pre-tax loss of $1.6 million in 1995
(excluding the effect of the oil and gas property valuation adjustment of $8.5
million which is calculated on an after-tax basis and has no effect on the
income tax benefit) with an effective tax rate of 37%.
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, 1997,
the Company had working capital of $2.6 million as compared to $1.9 million at
December 31, 1996. Working capital increased slightly as cash provided by
operating activities before changes in operating assets and liabilities plus
proceeds from new bank borrowings were mostly offset by capital expenditures
and the transfer of long-term debt to current. Net cash provided by operating
activities was $19.8 million, $18.4 million and $10.5 million in 1997, 1996 and
1995, respectively, while net cash provided by operating activities before
changes in operating assets and liabilities for the same periods was $19.1
million, $17.5 million and $11.7 million, respectively.
The Company's total capital expenditures, including capitalized internal
costs, for 1997, 1996 and 1995 were $28.0 million, $29.5 million and $16.6
million, respectively. Capital expenditures in 1997 included $12.6 million in
exploration and development drilling costs, $3.8 million in lease acquisitions,
geological and geophysical costs and $11.0 million in producing property
acquisitions. The largest of the Company's acquisitions in 1997 was the $9.2
million Gulf Coast Acquisition. Capital expenditures in 1996 included $8.7
million in exploration and development drilling expenditures, $2.7 million in
lease acquisitions, geological and geophysical costs and $17.3 million in
producing property acquisitions. The largest of the Company's acquisitions in
1996 was the $11.8 million Millarville Acquisition. Capital expenditures in
1995 included $10.2 million in exploration and development costs, $5.1 million
in lease acquisitions, geological and geophysical costs and $138,000 in
producing property acquisitions.
Oil and gas property sales totaled $1.4 million for 1997, down significantly
from the $6.3 million in 1996 and $4.4 million in 1995. In 1996, the Company
completed its three-year program of rationalizing its asset base by selling its
Oklahoma gas gathering system and its interest in 438 wells in various
locations. The wells sold represented 53% of the Company's total well count but
less than 2% of proved reserves. Additionally in 1996, the Company received an
unsolicited offer and sold a portion of its reserves in the
21
<PAGE>
Hanlan Swan Hills Unit along with a portion of its interest in the related
Hanlan-Robb gas processing plant in Alberta, Canada. The Company received $3.8
million from the 1996 sale of the Oklahoma gas gathering system (see discussion
below) and $1.2 million from the partial sale of its interest in the Hanlan-
Robb gas processing plant. Oil and gas property sales in 1995 were primarily
non-performing fee mineral interests.
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,
1997, $1.4 million has been recognized, leaving a balance of $685,000 in
"deferred revenue" on the consolidated balance sheet as of December 31, 1997.
The Company has entered into a $50.0 million revolving credit agreement dated
June 26, 1997 with the Toronto-Dominion Bank, the agent, and the Bank of Nova
Scotia. Initial borrowing availability under this new facility was $25.0
million. On June 30, 1997, the Company was advanced $13.0 million to fund the
Gulf Coast Acquisition and to replace amortizing principal payments under the
Series A and B Notes of the Company. The Company has classified $11.0 million
as "long-term" and $2.0 million as "current" on the accompanying consolidated
balance sheet as of December 31, 1997. The facility is for a five-year term
through July 1, 2002 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 5/8%
to 1 1/4% on Eurodollar loans and 1/8% to 1/4% on Prime loans. The Company's
average interest rate on the 1997 outstanding borrowings under this facility
was 6.8%.
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
Millarville Acquisition. Such agreement was amended on November 20, 1997. The
amended agreement allows the Company to forego principal payments during the
first year and a half. Additionally, the Company may elect to pay interest only
(Interest Only Period) in subsequent years if the Company's Canadian subsidiary
meets certain borrowing base tests. Otherwise, the loan becomes payable over a
three-year period beginning as of July 1 as follows: $1,510,000 in the first
year, $1,147,000 in the second year and $839,000 in the third year (the Term
Period). The Company classified $2.7 million as "long-term" and $756,000 as
"current" on the accompanying consolidated balance sheet as of December 31,
1997. The borrowings may be funded by RBC Prime loans or Bankers' Acceptances
(BA) loans. During the Interest Only Period, the Company pays interest at the
RBC prime rate plus 1/2% on Prime loans and pays the BA rate plus 1/2% and an
acceptance fee on BA loans. During the Term Period, the Company pays interest
at the RBC prime rate plus 3/4% on Prime loans and pays the BA rate plus 3/4%
and an acceptance fee on BA loans. The Company 's average interest rate on the
1997 outstanding borrowings under this agreement was 5.8%.
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
22
<PAGE>
December 31, 1995 for the Series B Notes. As of December 31, 1997, the
remaining principal balances for the Series A and B Notes were $2.5 million and
$23.4 million, respectively, for a total of $25.9 million, of which $4.7
matures in 1997. 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 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, 1997, the nonrecourse long-term notes payable balance was $4.0 million, of
which $730,000 was classified as "current."
As the Company has both the ability and intent to refinance $4.0 million of
its current maturities of long-term debt utilizing its new revolving credit
facility, $4.0 million has been reclassified from "current" to "long-term " on
the Company's accompanying consolidating balance sheet as of December 31, 1997.
Product prices continue to be volatile. Since December 1997, U.S. and
Canadian oil and gas prices have declined significantly. Under rules
promulgated by the Securities and Exchange Commission, companies that follow
the full cost accounting method are required to make quarterly "ceiling test"
calculations using product prices in effect at that time (see Note 3 to the
Consolidated Financial Statements--Property, Plant and Equipment). In the
future, should prices remain depressed or 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 charge against
earnings.
Prior to 1997, the Company has utilized hedging transactions to manage its
exposure to price fluctuations on its sales of oil and natural gas. Realized
gains and losses from the Company's hedging activities were included in oil and
gas revenues in the period of the hedged production. Normally, any realized and
unrealized gains and losses prior to the period when the hedged production
occurs would be deferred. Previously, the Company has used oil and natural gas
futures contracts or natural gas option contracts traded on the NYMEX to hedge
its oil and gas sales. The Company had no open hedging positions as of December
31, 1997, and has not hedged any of its production since October 1996.
The Company's Board of Directors has approved a capital budget of $12.0
million for 1998. The approved 1998 capital budget includes expenditures for
exploration and development projects and for producing property acquisitions.
However, actual levels of expenditures for planned exploration and development
projects and producing property acquisitions may vary significantly due to many
factors, including drilling results, oil and gas prices, industry conditions
and acquisition opportunities, among others.
The Company plans to finance its 1998 capital expenditures with its cash flow
from operations and working capital. If the Company increases its exploration,
development and acquisition activities in the future, capital expenditures may
require additional funding obtained through borrowings from commercial banks
and other institutional sources, public offerings of equity or debt securities
and existing and future relationships with institutional investment partners.
YEAR 2000 ISSUES
The Year 2000 presents significant issues for many computer systems. Much of
the software in use today may not be able to accurately process data beyond the
year 1999. The vast majority of computer systems process transactions using two
digits for the year of the transaction, rather than the full four digits,
making such systems unable to distinguish January 1, 2000 from January 1, 1900.
Such systems may encounter significant processing inaccuracies or become
inoperable when Year 2000 transactions are
23
<PAGE>
processed. Such matters could not only impact the Company in its day-to-day
operations but also impact the Company's financial institutions, customers and
vendors. The Company's Management is in the process of identifying or
remediating Year 2000 issues and does not expect any issues to arise that would
materially impact the Company's financial condition or operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not Applicable
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, 1997 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 Sheet as of December 31, 1997 and December 31,
1996................................................................... 28
Consolidated Statement of Operations for the Years Ended December 31,
1997, 1996 and 1995.................................................... 29
Consolidated Statement of Shareholders' Equity for the Years Ended De-
cember 31, 1997, 1996 and 1995......................................... 30
Consolidated Statement of Cash Flows for the Years Ended December 31,
1997, 1996 and 1995.................................................... 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.
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.
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.
</TABLE>
25
<PAGE>
<TABLE>
<C> <S>
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.
21 List of material subsidiaries.
23.1 Consent of Price Waterhouse 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
None.
26
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
PetroCorp Incorporated
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(1) on page 24 present fairly, in all material
respects, the financial position of PetroCorp Incorporated and its subsidiaries
at December 31, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1997,
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.
PRICE WATERHOUSE LLP
Houston, Texas
March 11, 1998
27
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
<TABLE>
<CAPTION>
ASSETS 1997 1996
------ -------- --------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................ $ 9,391 $ 8,859
Accounts receivable, net................................. 6,608 8,114
Other current assets..................................... 337 312
-------- --------
Total current assets................................... 16,336 17,285
-------- --------
Property, plant and equipment:
Proved oil and gas properties, at cost, full cost method,
net of accumulated depreciation, depletion and
amortization............................................ 99,038 93,161
Unproved oil and gas properties, not subject to
depletion............................................... 9,592 5,279
Plant and related facilities............................. 3,922 4,585
Other, net............................................... 1,717 2,257
-------- --------
114,269 105,282
-------- --------
Other assets, net.......................................... 319 297
-------- --------
Total assets........................................... $130,924 $122,864
======== ========
<CAPTION>
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
<S> <C> <C>
Current liabilities:
Accounts payable......................................... $ 6,167 $ 6,007
Accrued liabilities...................................... 3,345 3,569
Current portion of long-term debt........................ 4,186 5,763
-------- --------
Total current liabilities.............................. 13,698 15,339
-------- --------
Long-term debt............................................. 42,192 33,462
-------- --------
Deferred revenue........................................... 685 1,395
-------- --------
Deferred income taxes...................................... 7,792 7,003
-------- --------
Commitments and contingencies (Note 12)
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, 8,616,216 shares issued
(8,591,519 shares and 8,584,519 shares outstanding at
December 31, 1997 and 1996, respectively)............... 86 86
Additional paid-in capital............................... 71,143 71,170
Retained earnings (accumulated deficit).................. 71 (1,799)
Foreign currency translation adjustment and other........ (4,496) (3,475)
Treasury stock, at cost (24,697 shares).................. (247) (317)
-------- --------
Total shareholders' equity............................. 66,557 65,665
-------- --------
Total liabilities and shareholders' equity............. $130,924 $122,864
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
28
<PAGE>
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
REVENUES:
Oil and gas........................................ $33,502 $29,718 $24,448
Plant processing................................... 1,420 1,658 1,880
Other.............................................. 172 170 1,037
------- ------- -------
35,094 31,546 27,365
------- ------- -------
EXPENSES:
Production costs................................... 7,793 6,660 7,304
Depreciation, depletion and amortization........... 17,065 12,433 13,300
Oil and gas property valuation adjustment.......... 8,500
General and administrative......................... 5,052 4,672 5,544
Other operating expenses........................... 161 203 256
------- ------- -------
30,071 23,968 34,904
------- ------- -------
INCOME (LOSS) FROM OPERATIONS........................ 5,023 7,578 (7,539)
------- ------- -------
OTHER INCOME (EXPENSES):
Investment and other income........................ 558 1,910 1,470
Interest expense................................... (3,528) (3,391) (3,917)
Other expenses..................................... (47) (46) (159)
------- ------- -------
(3,017) (1,527) (2,606)
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES.................... 2,006 6,051 (10,145)
Income tax provision (benefit)....................... 136 1,807 (608)
------- ------- -------
NET INCOME (LOSS).................................... $ 1,870 $ 4,244 $(9,537)
======= ======= =======
Net income (loss) per common share--basic............ $ 0.22 $ 0.49 $ (1.11)
======= ======= =======
Net income (loss) per common share--diluted.......... $ 0.22 $ 0.49 $ (1.11)
======= ======= =======
Weighted average number of common shares--basic...... 8,586 8,585 8,585
======= ======= =======
Weighted average number of common shares--diluted.... 8,688 8,669 8,585
======= ======= =======
</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>
FOREIGN
RETAINED CURRENCY
ADDITIONAL EARNINGS TRANSLATION
SHARES PAID-IN (ACCUMULATED ADJUSTMENT TREASURY
ISSUED AMOUNT CAPITAL DEFICIT) AND OTHER STOCK TOTAL
------ ------ ---------- ------------ ----------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31,
1994................... 8,616 $86 $71,170 $ 3,494 $(4,105) $(317) $70,328
Net loss.............. (9,537) (9,537)
Foreign currency
translation
adjustment and other. 730 730
----- --- ------- ------- ------- ----- -------
BALANCE, DECEMBER 31,
1995................... 8,616 86 71,170 (6,043) (3,375) (317) 61,521
Net income............ 4,244 4,244
Foreign currency
translation
adjustment and other. (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)
Foreign currency
translation
adjustment........... (1,021) (1,021)
Treasury stock........ 70 70
----- --- ------- ------- ------- ----- -------
BALANCE, DECEMBER 31,
1997................... 8,616 $86 $71,143 $ 71 $(4,496) $(247) $66,557
===== === ======= ======= ======= ===== =======
</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, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)............................... $ 1,870 $ 4,244 $ (9,537)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization....... 17,065 12,433 13,300
Deferred income tax provision (benefit)........ 136 1,807 (608)
Gain on sale of gas gathering system........... (999)
Oil and gas property valuation adjustment...... 8,500
-------- -------- --------
19,071 17,485 11,655
Changes in operating assets and liabilities:
Accounts receivable........................... 1,506 (482) (182)
Other current assets.......................... (25) 1,121 (289)
Accounts payable.............................. 160 748 (688)
Accrued liabilities........................... (224) 199 (98)
Other.......................................... (710) (693) 126
-------- -------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES.... 19,778 18,378 10,524
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties.... 1,408 6,304 4,421
Additions to oil and gas properties............. (27,425) (28,683) (15,394)
Additions to plant and related facilities....... (285) (261) (416)
Additions to other property, plant and
equipment...................................... (125) (537) (751)
Additions to other assets....................... (211) (31) (9)
Proceeds from sale of interest in plant and
related facilities............................. 1,211
Proceeds from sale of gas gathering system...... 3,835
Proceeds from sale of short-term investment..... 6,682
-------- -------- --------
NET CASH USED IN INVESTING ACTIVITIES........ (26,638) (18,162) (5,467)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt.................... 13,244 3,908 665
Repayment of long-term debt..................... (5,757) (7,028) (4,257)
Other........................................... 43
-------- -------- --------
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES.................................. 7,530 (3,120) (3,592)
-------- -------- --------
Effect of exchange rate changes on cash.......... (138) (1) 172
-------- -------- --------
Net increase (decrease) in cash and cash equiva-
lents........................................... 532 (2,905) 1,637
Cash and cash equivalents at beginning of year... 8,859 11,764 10,127
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR......... $ 9,391 $ 8,859 $ 11,764
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
31
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
1. SUMMARY OF ACCOUNTING POLICIES
General
PetroCorp Incorporated, a Texas corporation, is engaged in the exploration,
development, acquisition 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 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.
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 five 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.
At December 31, 1997 and 1996, the cumulative amount of accrued site
restoration and dismantlement costs approximated $357,000 and $140,000,
respectively.
32
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
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, 1997 and 1996, the Company has included in accrued
liabilities $35,000 and $32,000 with respect to 22,000 Mcf and 20,000 Mcf,
respectively, of overproduced imbalances.
In December 1994, the Company initiated a hedging program to manage its
exposure to price fluctuations on its sales of oil and natural gas. Since
initiating the hedging program, the Company has used oil and natural gas
futures contracts or natural gas option contracts traded on the New York
Mercantile Exchange (NYMEX) to hedge its oil and gas sales. The Company
combines as a unit certain purchased and written natural gas options for
hedging purposes. Realized gains and losses from the Company's hedging
activities are included in oil and gas revenues in the period of the hedged
production. Normally, any realized and unrealized gains and losses prior to the
period when the hedged production occurs are deferred (see Note 11). No hedges
were in place during 1997.
Revenues from plant processing are recognized at the time associated natural
gas is processed and sold at the plant tailgate. Other revenues include
revenues 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, 1997 and 1996, 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 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 foreign currency translation adjustment component of shareholders' equity.
Foreign currency transaction gains and losses are recognized currently. For the
years ended December 31, 1997, 1996 and 1995, the Company recognized
33
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
foreign currency losses of $36,000, $24,000 and $13,000, respectively. At
December 31, 1997, 1996 and 1995, the exchange rates were ($1 CAN = $U.S.)
$0.6992, $0.7297 and $0.7329, respectively, while the average exchange rates
during such years were $0.7201, $0.7334 and $0.7312, respectively.
Earnings Per Share
During the year ended December 31, 1997, the Company adopted Statement of
Financial Accounting Standard (SFAS) No. 128, "Earnings Per Share." SFAS No.
128 establishes new guidelines for computing earnings per share (EPS) and
requires dual presentation of basic and diluted EPS for entities with complex
capital structures. Basic EPS excludes dilution and is computed by dividing net
income by the weighted average number of common shares outstanding during the
period. Dilutive EPS reflects potential dilution and is computed by dividing
net income by the weighted average number of common shares outstanding during
the period increased by the number of additional common shares that would have
been outstanding if the dilutive potential common shares had been issued. All
prior period EPS data has been restated to conform with the provisions of SFAS
No. 128.
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,
1997, 1996 and 1995 were $4,730,000, $7,407,000 and $13,623,000, respectively.
Other
During June 1997, the Financial Accounting Standards Board (FASB) issued SFAS
No. 130, "Reporting Comprehensive Income." This statement requires disclosure
of changes in equity from nonowner sources in a primary financial statement and
the accumulated balance of such items as a separate caption within the
shareholders' equity section of the balance sheet. SFAS No. 130 is effective
for periods beginning after December 15, 1997. This pronouncement will impact
the disclosure of the Company's foreign currency translation adjustment
reported on the accompanying consolidated balance sheet.
During June 1997, the FASB issued SFAS No. 131, "Disclosures About Segments
of an Enterprise and Related Information." SFAS No. 131 establishes standards
for the method public entities report information about operating segments in
both interim and annual financial statements issued to shareholders and
requires related disclosures about products and services, geographic areas and
major customers. This statement is effective for fiscal years beginning after
December 15, 1997. Management believes the disclosure requirements of this
statement will have no impact on its consolidated financial statements.
2. 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.
34
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
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).
<TABLE>
<CAPTION>
UNAUDITED PRO
FORMA FINANCIAL
INFORMATION FOR
THE YEAR 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>
35
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
3. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment were as follows at December 31,
1997 and 1996 (amounts in thousands):
<TABLE>
<CAPTION>
1997 1996
--------- --------
<S> <C> <C>
Oil and gas properties:
Proved............................................. $ 195,270 $174,324
Unproved........................................... 9,592 5,279
--------- --------
204,862 179,603
--------- --------
Plant and related facilities......................... 8,766 8,859
Gas gathering facilities............................. 1,685 1,658
Furniture, fixtures and equipment.................... 2,600 2,507
--------- --------
217,913 192,627
Less--accumulated depreciation, depletion and
amortization........................................ (103,644) (87,345)
--------- --------
$ 114,269 $105,282
========= ========
</TABLE>
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 1997, 1996 and 1995 was $16,880,000,
$12,279,000 and $13,145,000, respectively. Oil and gas property depreciation,
depletion and amortization for the years ended December 31, 1997, 1996 and 1995
was $15,383,000, $10,788,000 and $11,510,000, respectively. Depreciation,
depletion and amortization per equivalent barrel (using a Mcf-to-barrel
conversion factor of 6 to 1) for the years ended December 31, 1997, 1996 and
1995 was $9.06, $6.38 and $6.21, respectively, for U.S. operations and $2.97,
$2.03 and $2.13, respectively, for Canadian operations. The total composite
rates were $6.60, $5.24 and $5.22 for the years ended December 31, 1997, 1996
and 1995, respectively. At June 30, 1995, the Company's net capitalized costs
of its U.S. oil and gas properties exceeded the capitalization ceiling by
$8,500,000. This amount is reflected in the Company's results of operations for
the year ended December 31, 1995.
Product prices continue to be volatile. Since December 1997, U.S. and
Canadian oil and gas prices have declined significantly. In the future, should
prices remain depressed or decline further and depending on drilling results,
the Company could potentially be required to record a valuation adjustment to
its oil and gas property balances, resulting in a charge against earnings.
36
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
4. LONG-TERM DEBT
The Company's total long-term debt is payable as follows (amounts in
thousands):
<TABLE>
<CAPTION>
1997 1996
------- -------
<S> <C> <C>
Current portion of long-term debt........................ $ 8,186 $ 5,763
Reclassified to long-term debt........................... (4,000)
------- -------
Total current portion of long-term debt.................. $ 4,186 $ 5,763
======= =======
Series A & B Senior Notes................................ $21,150 $25,850
TD Bank Credit Agreement................................. 11,000
RBC Credit Agreement..................................... 2,741 3,648
Nonrecourse Notes Payable................................ 3,301 3,964
------- -------
38,192 33,462
Reclassified from current portion of long-term debt...... 4,000
------- -------
Total long-term debt..................................... $42,192 $33,462
======= =======
</TABLE>
Debt maturing in each of the years during the five-year period subsequent to
December 31, 1997 is as follows: $8,186,000 in 1998, $5,900,000 in 1999,
$9,400,000 in 2000, $8,300,000 in 2001 and $9,400,000 in 2002.
Reclassification of current debt maturities to long term represents unused
capacity under the TD Bank credit agreement at December 31, 1997. 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, 1997 and 1996 consisted
of the following (amounts in thousands):
<TABLE>
<CAPTION>
1997 1996
------- -------
<S> <C> <C>
Series A, senior adjustable rate notes payable to a
shareholder affiliate................................... $ 2,550 $ 4,575
Series B, 7.55% senior notes payable to nonaffiliates.... 23,300 26,275
------- -------
$25,850 $30,850
======= =======
</TABLE>
Redemption payments to affiliates and nonaffiliates were $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, 1997, 1996 and 1995 amounted to $303,000 and $1,941,000, $1,883,000 and
$706,000, and $2,150,000 and $755,000, 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, 1997, 1996 AND 1995
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 6.71% to 6.99%, 6.68% to 7.09% and 6.71% to 7.40%
during 1997, 1996 and 1995, 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.
Bank Debt
On June 26, 1997, the Company entered into a $50 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The current borrowing availability under this new facility is $25
million. The facility is for a five-year term through July 1, 2002 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 5/8% to 1 1/4% on Eurodollar
loans and 1/8% to 1/4% on Prime loans.
The Company was advanced $13,000,000 on June 30, 1997 primarily to fund the
Gulf Coast Acquisition and to replace amortizing principal payments under the
Series A and B Notes of the Company. The Company initially funded the
$13,000,000 advance with a Prime loan but rolled over the debt into a six-month
Eurodollar loan on July 7,1997 with an interest rate of 6.8%.
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 $3,496,000 to partially fund the
Millarville Acquisition. Such agreement was amended on November 20, 1997. The
amended agreement allows the Company to forego principal payments in the first
year and a half. Additionally, the Company may elect to pay interest only
(Interest Only Period) during subsequent
38
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
years if the Company's Canadian subsidiary meets certain borrowing base tests.
Otherwise, the loan becomes payable over a three-year period beginning as of
July 1 as follows: $1,510,000 in the first year, $1,147,000 in the second year
and $839,000 in the third year (the Term Period). The borrowings may be funded
by RBC Prime loans or Banker's Acceptances (BA) loans. During the Interest Only
Period, the Company pays interest at the RBC prime rate plus 1/2% on Prime
loans and pays the BA rate plus 1/2% and an acceptance fee on BA loans. During
the Term Period, the Company pays interest at the RBC prime rate plus 3/4% on
Prime loans and pays the BA rate plus 3/4% and an acceptance fee on BA loans.
The Company initially funded the debt with a Prime loan but rolled over the
debt into a twelve-month BA loan on January 9, 1997 with an effective interest
rate of 5.8%.
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 1997 and 1996, interest payments were $669,000 and $896,000,
respectively, while principal payments totaled $757,000 and $1,938,000,
respectively. Additionally, in 1997 and 1996, the Company issued $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.
5. DEFERRED REVENUE
In March 1996, FGS sold its SW 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 SW
Oklahoma City Field. Through December 31, 1997, $1,404,000 has been recognized,
leaving a balance of $685,000 in "deferred revenue" on the consolidated balance
sheet as of December 31, 1997.
39
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
6. 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.
7. INCOME TAXES
The components of income (loss) before income taxes for the years ended
December 31, 1997, 1996 and 1995 consisted of the following (amounts in
thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------ --------
<S> <C> <C> <C>
United States operations.......................... $(1,269) $4,096 $(10,249)
Canadian operations............................... 3,275 1,955 104
------- ------ --------
$ 2,006 $6,051 $(10,145)
======= ====== ========
</TABLE>
The provision (benefit) for income taxes consists of the following (amounts
in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
----- ------ -----
<S> <C> <C> <C>
Deferred:
U.S.--federal......................................... $(344) $1,475 $(560)
U.S.--state........................................... (20) 84 (32)
Canada................................................ 500 248 (16)
----- ------ -----
$ 136 $1,807 $(608)
===== ====== =====
</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, 1997, 1996 and 1995 is presented in the following table (amounts
in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------ ------ -------
<S> <C> <C> <C>
United States federal income taxes (benefit) at
statutory rate of 35%................................ $ 702 $2,118 $(3,551)
Increases (reductions) resulting from:
Canadian earnings not subject to United States
taxes.............................................. (1,146) (684) (36)
Canadian income taxes............................... 500 248 (16)
State income taxes.................................. (20) 84 (32)
Oil and gas property valuation adjustment........... 2,975
Other............................................... 100 41 52
------ ------ -------
$ 136 $1,807 $ (608)
====== ====== =======
</TABLE>
40
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
Deferred tax assets and liabilities consist of the following at December 31,
1997 and 1996 (amounts in thousands):
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforward--U.S..................... $ 6,573 $ 8,900
Net operating loss carryforward--Canada.................. 2,318 1,738
-------- --------
Gross deferred tax asset................................... 8,891 10,638
-------- --------
Deferred tax liabilities:
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--U.S.............. (8,980) (11,671)
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--Canada........... (7,703) (5,970)
-------- --------
Gross deferred tax liability............................... (16,683) (17,641)
-------- --------
$ (7,792) $ (7,003)
======== ========
</TABLE>
As of December 31, 1997, the Company has U.S. net operating loss
carryforwards of $17,765,000 and $11,466,000 for regular tax and alternative
minimum tax purposes, respectively, which begin to expire in 2001. The Company
is subject to certain restrictions under Section 382 on the annual utilization
of a portion of its net operating loss carryforwards. Certain future changes in
the Company's shareholders may impose additional limitations as well.
Under SFAS No. 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>
YEAR ENDED DECEMBER
31,
-----------------------
1997 1996 1995
------- ------- -----
<S> <C> <C> <C>
Tax computed at statutory rate of 44.62%.............. $ 1,461 $ 872 $ 46
Nondeductible crown royalties......................... 1,160 510 535
Resource allowance.................................... (1,948) (1,134) (597)
Alberta royalty tax credit............................ (173)
------- ------- -----
$ 500 $ 248 $ (16)
======= ======= =====
</TABLE>
41
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
8. 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, 1994.................. 737,740 $5.00-$10.00
Granted.........................................
Forfeited....................................... (20,000) $10.00
Exercised.......................................
-------
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
=======
</TABLE>
The weighted average exercise prices for options under the Option Plan
outstanding at December 31, 1997, 1996 and 1995 were $7.86, $7.84 and $8.43,
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
====== =====
</TABLE>
The Director Options were fully vested at the date of grant.
Stock options under both plans expire ten years from the date of grant.
42
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
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 1997 and 1996 net income and
earnings per share would have been reduced by approximately $79,000 and
$450,000 or $0.01 and $0.05 per share, respectively. The fair value of the
options granted during 1997 is estimated as $126,000 on the date of grant using
the Black-Scholes option-pricing model with the following assumptions: dividend
yield of 0%, volatility of 31.1%, risk-free interest rate of 6.74% and an
expected life of ten years. The fair value of the options granted during 1996
is estimated as $720,000 on the date of grant using the Black-Scholes option-
pricing model with the following assumptions: dividend yield of 0%, volatility
of 34.3%, risk-free interest rate of 5.7% and an expected life of ten years.
The Company has a savings plan, which became effective January 1, 1993,
available to qualified employees and is qualified 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
$188,000, $208,000 and $243,000 in 1997, 1996 and 1995, respectively.
9. 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 (amounts in
thousands except per share amounts).
<TABLE>
<CAPTION>
PER SHARE
INCOME SHARES AMOUNT
------- ------ ---------
<S> <C> <C> <C>
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
======= ===== ======
Year ended December 31, 1995:
Basic EPS:
Net income.................................... $(9,537) 8,585 $(1.11)
Effect of dilutive securities:
Options.......................................
------- ----- ------
Diluted EPS:
Net income.................................... $(9,537) 8,585 $(1.11)
======= ===== ======
</TABLE>
43
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
Options to purchase 445,740 shares of common stock at $10.00 per share were
outstanding during the year ended December 31, 1997 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.
10. 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>
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.................... 20,564 7,172 309 28,045
Identifiable assets at December 31...... 88,132 41,803 989 130,924
1996:
Revenues................................ $25,452 $ 6,094 $ 31,546
Income (loss) from operations........... 9,466 3,433 $(5,301) 7,578
Depreciation, depletion and
amortization........................... 9,886 1,918 629 12,433
Capital expenditures.................... 15,200 13,899 412 29,511
Identifiable assets at December 31...... 80,706 40,961 1,197 122,864
1995:
Revenues................................ $22,100 $ 5,265 $ 27,365
Income (loss) from operations........... (3,579) 2,205 $(6,165) (7,539)
Depreciation, depletion and
amortization........................... 10,662 2,017 621 13,300
Oil and gas property valuation
adjustment............................. 8,500 8,500
Capital expenditures.................... 12,938 3,375 257 16,570
Identifiable assets at December 31...... 83,824 29,601 1,414 114,839
</TABLE>
The following table reflects purchasers which accounted for more than 10% of
the Company's oil and gas revenues:
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
EOTT Energy Operating Limited Partnership.................. 26% 20%
Pan-Alberta Gas Ltd........................................ 21% 17% 14%
Sun Refining and Marketing Company......................... 14% 22%
Conoco Inc................................................. 11%
</TABLE>
The majority of the Company's Canadian gas is dedicated under long-term
contracts to Pan-Alberta Gas Ltd., a major Canadian aggregator. 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.
44
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
11. HEDGING PROGRAM AND FAIR VALUE OF FINANCIAL INSTRUMENTS
Hedging Program
Prior to 1997, the Company has utilized hedging transactions to manage its
exposure to price fluctuations on its sales of oil and natural gas. Realized
gains and losses from the Company's hedging activities were included in oil and
gas revenues in the period of the hedged production. Normally, any realized and
unrealized gains and losses prior to the period when the hedged production
occurs would be deferred. Previously, the Company has used oil and natural gas
futures contracts or natural gas option contracts traded on the NYMEX to hedge
its oil and gas sales.
The Company recorded realized hedging losses of $918,000 in 1996 and hedging
gains of $338,000 in 1995. No hedges were in place in 1997.
As a result of the decoupling of the relationship between the pricing of
certain NYMEX natural gas futures contracts for the first quarter of 1996 and
the Company's field prices for the same period, these futures contracts no
longer qualified as hedges for accounting purposes. Accordingly, the Company
recorded a $996,000 reduction to "investment and other income" during the
fourth quarter of 1995.
Fair Value of Financial Instruments
The following information discloses the fair value of the Company's financial
instruments in accordance with SFAS No. 107, "Disclosures About Fair Value of
Financial Instruments" (amounts in thousands):
<TABLE>
<CAPTION>
CARRYING FAIR
AMOUNT VALUE
-------- -------
<S> <C> <C>
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 27,150
1995:
Long-term debt:
Series B, 7.55% senior notes......................... 28,700 29,300
Futures contracts:
Oil (unrealized loss)................................ (134) (134)
</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.
45
<PAGE>
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
12. 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
$418,000, $393,000, $396,000, $434,000 and $434,000 for the years ended
December 31, 1997, 1998, 1999, 2000 and 2001, respectively. Total rental
expense for office space for the years ended December 31, 1997, 1996 and 1995
was $648,000, $646,000 and $637,000, respectively.
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.
13. 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 1997, the consulting company procured $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 also 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 1997, the Company remitted
$914,000 to Kaiser-Francis as payment of the Company's share of the joint
operation.
46
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
DECEMBER 31, 1997, 1996 AND 1995
(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>
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
======= ======= =======
1995:
Acquisition of properties:
Proved properties..................................... $ 136 $ 136
Unproved properties................................... 2,437 $ 93 2,530
Exploration costs...................................... 5,208 1,128 6,336
Development costs...................................... 4,657 1,735 6,392
------- ------- -------
Total................................................ $12,438 $ 2,956 $15,394
======= ======= =======
</TABLE>
Included in the above amounts for the years ended December 31, 1997, 1996 and
1995 were $1,897,000, $1,690,000 and $1,962,000, respectively, of capitalized
internal costs related to property acquisition, exploration and development.
Under SFAS No. 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, 1997, 1996 AND 1995
(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>
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
======== ======= ========
1995:
Proved properties................................ $128,891 $21,176 $150,067
Unproved properties.............................. 3,433 973 4,406
-------- ------- --------
132,324 22,149 154,473
Accumulated depreciation, depletion and
amortization.................................... (65,938) (4,462) (70,400)
-------- ------- --------
$ 66,386 $17,687 $ 84,073
======== ======= ========
</TABLE>
Of the unproved properties capitalized cost at December 31, 1997,
approximately $5,099,000 and $2,931,000 was incurred in 1997 and 1996,
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, 1997, 1996 AND 1995
(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>
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
======== ======= ========
1995:
Revenues......................................... $ 21,520 $ 2,928 $ 24,448
Production costs................................. (6,261) (1,043) (7,304)
Depreciation, depletion and amortization......... (10,370) (1,140) (11,510)
Oil and gas property valuation adjustment........ (8,500) (8,500)
Income tax expense............................... (1,809) (230) (2,039)
-------- ------- --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................. $ (5,420) $ 515 $ (4,905)
======== ======= ========
</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, 1997, 1996 AND 1995
(UNAUDITED)
The Company's estimates of its proved reserves and proved developed reserves
of oil and gas as of December 31, 1997, 1996 and 1995 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>
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
====== ====== ===== ====== ====== ======
1995:
Proved reserves:
Beginning of year............ 6,845 34,412 16 47,404 6,861 81,816
Production................... (656) (6,084) (2) (3,199) (658) (9,283)
Purchase of minerals-in-
place....................... 27 152 27 152
Extensions and discoveries... 345 1,053 2,089 345 3,142
Sales of minerals-in-place... (413) (413)
Revisions to previous
estimates................... 179 225 10 7,202 189 7,427
------ ------ ----- ------ ------ ------
End of year................... 6,740 29,345 24 53,496 6,764 82,841
====== ====== ===== ====== ====== ======
Proved developed reserves:
Beginning of year............ 2,437 31,782 16 41,381 2,453 73,163
====== ====== ===== ====== ====== ======
End of year.................. 2,617 28,256 21 45,339 2,638 73,595
====== ====== ===== ====== ====== ======
</TABLE>
50
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(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 unproven 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>
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
======== ======== ========
1995:
Future gross revenues.............................. $182,422 $ 63,969 $246,391
Less--future costs:
Production........................................ 50,797 23,379 74,176
Development and dismantlement..................... 7,252 2,215 9,467
-------- -------- --------
Future net cash flows before income taxes.......... 124,373 38,375 162,748
Less--10% annual discount for estimated timing of
cash flows........................................ 46,126 15,829 61,955
-------- -------- --------
Present value of future net cash flows before
income taxes...................................... 78,247 22,546 100,793
Less--present value of future income taxes......... 12,925 3,057 15,982
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 65,322 $ 19,489 $ 84,811
======== ======== ========
</TABLE>
51
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(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>
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
======== ======== ========
1995:
Standardized measure--beginning of period....... $ 56,251 $ 17,077 $ 73,328
Sales of oil and gas produced, net of
production costs.............................. (15,259) (1,885) (17,144)
Purchases of minerals-in-place................. 182 182
Extensions and discoveries..................... 5,086 1,095 6,181
Sales of minerals-in-place..................... (447) (447)
Net changes in prices and production costs..... 10,372 (1,870) 8,502
Development costs incurred and changes in
estimated future development and dismantlement
costs......................................... 2,677 315 2,992
Revisions to previous quantity estimates....... 1,454 3,148 4,602
Accretion of discount.......................... 6,814 2,120 8,934
Changes in timing of production and other...... (770) (1,575) (2,345)
Net changes in income taxes.................... (1,038) 1,064 26
-------- -------- --------
Standardized measure--end of period............. $ 65,322 $ 19,489 $ 84,811
======== ======== ========
</TABLE>
52
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(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>
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
1995:
Oil (per BBL)............................................ $18.20 $17.96 $18.20
Gas (per Mcf)............................................ 2.04 1.19 1.49
</TABLE>
Information relating to sulfur in Canada which has not been included in the
standardized measure is summarized as follows:
<TABLE>
<CAPTION>
1997 1996 1995
---------- -------- ----------
<S> <C> <C> <C>
Revenues for the year ended December 31......... $ 183,000 $ 99,000 $ 457,000
Production (long tons) for the year ended Decem-
ber 31......................................... 15,546 13,337 14,284
Estimated proved reserves (long tons) as of De-
cember 31...................................... 202,000 191,000 228,000
Present value (10%), before income taxes, of fu-
ture net revenues.............................. 1,080,000 132,000 4,367,000
Price per long ton, net of transportation costs,
used to determine future revenues at December
31............................................. $ 9.36 $ 1.16 $ 32.23
</TABLE>
53
<PAGE>
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
(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, 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
Year ended December 31, 1996:
Revenues.............................. $7,530 $7,389 $7,306 $9,321 $31,546
Gross profit(1)....................... 2,759 2,619 2,550 4,322 12,250
Income from operations................ 1,512 1,409 1,537 3,120 7,578
Net income(2)......................... 1,249 520 635 1,840 4,244
Net income per share--basic........... $ 0.14 $ 0.06 $ 0.07 $ 0.21 $ 0.49
</TABLE>
- --------
(1) Revenues less operating expenses other than general and administrative.
(2) In the first quarter of 1996, the Company recorded a $629,000 after-tax
gain related to the sale of its Oklahoma gas gathering system.
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 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: March 27, 1998
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<S> <C>
</TABLE>
SIGNATURE TITLE DATE
/s/ W. Neil McBean President, Chief March 27, 1998
- ----------------------------------- Executive Officer
W. Neil McBean (Principal
Executive Officer)
and Director
/s/ Craig K. Townsend Vice President-- March 24, 1998
- ----------------------------------- Finance, Secretary
Craig K. Townsend and Treasurer
(Principal
Financial Officer
and Principal
Accounting Officer)
/s/ Lealon L. Sargent Chairman of the Board March 24, 1998
- ----------------------------------- of Directors
Lealon L. Sargent
/s/ Thomas N. Amonett Director March 27, 1998
- -----------------------------------
Thomas N. Amonett
/s/ Gary R. Christopher Director March 23, 1998
- -----------------------------------
Gary R. Christopher
/s/ G. Jay Erbe, Jr. Director March 24, 1998
- -----------------------------------
G. Jay Erbe, Jr.
/s/ Stephen M. McGrath Director March 23, 1998
- -----------------------------------
Stephen M. McGrath
/s/ Robert C. Thomas Director March 20, 1998
- -----------------------------------
Robert C. Thomas
55
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
NO. ITEM
--- ----
<C> <S>
21 --List of material subsidiaries
23.1 --Consent of Price Waterhouse LLP
23.2 --Consent of Huddleston & Co., Inc.
27 --Financial Data Schedule
</TABLE>
56
<PAGE>
EXHIBIT 21
MATERIAL SUBSIDIARIES
PCC Energy, Inc. (an Alberta, Canada corporation)
PCC Energy Corp. (an Alberta, Canada corporation)
PCC Energy Limited (an Alberta, Canada corporation)
(subsidiary of PCC Energy Corp.)
<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) and on Form S-8 (No. 333-05645) of
PetroCorp Incorporated of our report dated March 11, 1998, appearing on page 27
of The Annual Report of Petrocorp Incorporated on Form 10-K for the year ended
December 31, 1997.
PRICE WATERHOUSE LLP
Houston, Texas
March 30, 1998
<PAGE>
EXHIBIT 23.2
[LETTERHEAD OF HUDDLESTON & CO., INC.]
LETTER OF CONSENT
We herby consent to the references to us under the headings "Principal
Properties" and "Oil and Gas Reserves" in the Annual Report on Form 10-K of
PetroCorp Incorporated for the year ended December 31, 1997.
Huddleston & Co., Inc.
/s/ B. P. Huddleston
By: _________________________________
B. P. Huddleston, P.E.
Chairman
Houston, Texas
March 24, 1998
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 3-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1997 DEC-31-1997
<PERIOD-START> OCT-01-1997 JAN-01-1997
<PERIOD-END> DEC-31-1997 DEC-31-1997
<CASH> 9,391 9,391
<SECURITIES> 0 0
<RECEIVABLES> 6,658 6,658
<ALLOWANCES> (50) (50)
<INVENTORY> 0 0
<CURRENT-ASSETS> 16,336 16,336
<PP&E> 217,913 217,913
<DEPRECIATION> (103,644) (106,644)
<TOTAL-ASSETS> 130,924 130,924
<CURRENT-LIABILITIES> 13,698 13,698
<BONDS> 0 0
0 0
0 0
<COMMON> 86 86
<OTHER-SE> 66,471 66,471
<TOTAL-LIABILITY-AND-EQUITY> 130,924 130,924
<SALES> 9,024 33,502
<TOTAL-REVENUES> 9,376 35,094
<CGS> 0 0
<TOTAL-COSTS> 8,335 30,071
<OTHER-EXPENSES> 44 47
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 963 3,528
<INCOME-PRETAX> 188 2,006
<INCOME-TAX> (236) 136
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 424 1,870
<EPS-PRIMARY> .05 .22
<EPS-DILUTED> .05 .22
</TABLE>
