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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1996
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
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PETROCORP INCORPORATED
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0380430
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
77060-2391
16800 GREENSPOINT PARK DRIVE (ZIP CODE)
SUITE 300, NORTH ATRIUM
HOUSTON, TEXAS
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
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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) 229.405 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, 1997 was $37,730,718.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of March 17, 1997:
Common Stock, par value $.01 per share 8,584,519
Documents incorporated by reference: Proxy Statement for the registrant's
Annual Meeting of Shareholders to be held May 16, 1997 (to be filed within 120
days of the close of registrant's fiscal year) is incorporated by reference
into Part III.
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TABLE OF CONTENTS
ITEM TITLE PAGE
---- ----- ----
PART I
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.......................................................... 17
6 Selected Financial Data........................................... 18
7 Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................ 19
8 Financial Statements and Supplementary Data....................... 25
9 Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure............................................. 25
PART III
10-13 (Items 10-13 incorporated by reference to Proxy Statement)........ 25
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 25
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.
i
PART I
ITEM 1. BUSINESS.
GENERAL
PetroCorp Incorporated (PetroCorp or the Company) 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 Mississippi,
Oklahoma, Texas, Louisiana, Kansas and Colorado and in the province of
Alberta, Canada.
At December 31, 1996, the Company's proved reserves totaled 5.2 MMbbls of
oil and 80.8 Bcf of natural gas and had an estimated pretax present value of
future net revenues (PV-10) of $177 million. On a BOE basis, approximately 70%
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 $5.3
million, as well as interests in natural gas processing and gathering
facilities with a net book value of $5.9 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 and partnerships 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 re-processing,
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 1996, PetroCorp
had drilled four exploratory prospects in Wayne and Greene Counties, yielding
two new field discoveries and six successful wells out of eight total wells
drilled. In February 1995, PetroCorp announced the new Maynor Creek Field in
Wayne County, Mississippi, which it
1
operates. The initial discovery well, the Scott Paper 1-33, was successfully
tested from two separate intervals in the Cotton Valleyformation at
approximately 14,000 feet. Subsequent to the discovery, the Company conducted
a 16-square mile 3-D seismic survey to optimize the development of the field
and has successfully drilled three consecutive development wells. Restricted
by state allowable limitations, the four wells are now producing at a combined
rate in excess of 1,000 BOPD. PetroCorp originally owned a 50% working
interest in the field. The acquisition of the interest of one of its partners
in October 1996, together with an anticipated prospect payout in the first
quarter of 1997, is expected to bring its working interest ownership to 65%.
To date, the Company has participated in four separate 3-D seismic surveys
covering 65 square miles in the Mississippi Salt Basin. 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.
Hanlan-Robb Area. The Company owns interests in three proved developed
nonproducing fields in the Hanlan-Robb area of western Alberta, Canada. It
intends to connect these fields to the Hanlan-Robb gas gathering system as
declining production from the five currently producing fields makes capacity
available at the gas processing plant in which the Company owns an interest.
Recent activity for the Hanlan Unit includes the successful installation and
start-up of a $10 million field compression facility designed to extend the
life of the field into the next century. In addition, the first of several
potential horizontal laterals has been drilled from an existing well in the
Unit and is awaiting final production testing. The Hanlan 6-23 well has been
deviated laterally almost 1,000 feet in an attempt to increase its
productivity and mitigate natural field decline. If successful, additional
laterals on existing Hanlan Unit wells are planned over the next several years
in an attempt to reduce the natural rate of field production declines. The
Erith 8-13 development well was completed at approximately 15,000 feet in
February 1995 at the Erith prospect, approximately seven miles east of the
plant. After construction of a gas gathering line, production from this well
commenced in December 1995, and it now produces at 6 MMcf/D. Current plans
call for a horizontal lateral (in a fashion similar to the Hanlan 6-23) to be
drilled from the vertical Erith 8-13 wellbore later in 1997.
Approximately ten miles west of the plant are the Shaw/Basing and Coal
Branch/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 Mississippi Turner Valley
formation. The Coalbranch 16-33 and the Coalspur 9-27 are now producing at 10
MMcf/D and 3.5 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 has been tested at 4 MMcf/D and awaits a pipeline connection
which is expected to be completed in the second half of 1997. The Basing 10-25
is currently testing. 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.
Oklahoma. North of Oklahoma City, PetroCorp has successfully completed the
first well on its Edmond Prospect as a Prue Sand gas well at 6,100 feet.
Capable of sustained production of approximately 3 MMcf/D, the Jackson 2B-4
well is currently flowing at a pipeline constrained rate of 1.4 MMcf/D.
PetroCorp owns a 47% working interest in this well and an average 70% working
interest in two additional wells planned for this project. The first of these
development wells is scheduled to be drilled in the second quarter of 1997. In
recent years, the Company has made a number of discoveries in the Northern
Oklahoma Area, and the Company will continue exploration and development of
this area during 1997. 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. A number of exploration
projects have been identified with 1997 drilling scheduled. 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, the Oklahoma Corporation Commission officially approved the
formation of the Southwest Oklahoma City Unit for the purposes of water
flooding and repressurizing the field to improve ultimate oil
2
recovery. Water injection commenced in September 1996. The PetroCorp-operated,
56 well unit has produced 2.4 MMbbls of oil and 18 Bcf of gas to date.
PetroCorp owns an 86.4% working interest in the Southwest Oklahoma City Unit
which is currently producing 280 BOPD and 3.9 MMcf/D. 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 four fields in the Northern Oklahoma Area.
Worsley Field and Other Canadian Properties. The largest of the producing
properties acquired from Millarville Oil & Gas Ltd. in December 1996 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 1997 in the Worsley property as well as in the McLeod,
Trochu and Buick-Sutton areas of Alberta.
Other Projects. PetroCorp recently acquired a 15% interest in an exploration
play in Southeast Texas. The Company is participating 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 down to a depth of 12,000 feet.
Acquisition of the seismic data has been completed and the data is currently
in processing. Assuming positive results from the survey, drilling is expected
to commence during the second half of 1997.
The Company's waterflood project at the Richardson-Mueller Caddo Unit in
North Texas did not show any commercial oil response in 1996 and operations
have been suspended in the first quarter of 1997. As a result, the Company
moved 2.6 MMBOE of proved reserves attributable to this unit into the
probable/possible category. This reserve revision resulted in a 9% decrease in
the Company's total proved reserves at December 31, 1996 compared with the
previous year end; however, the Company more than replaced production with new
reserve additions for the year. See "Supplemental Information to Consolidated
Financial Statements--Oil and Gas Reserves and Related Financial Data--Reserve
Quantities" in the Notes to the Consolidated Financial Statements of the
Company.
ACQUISITIONS AND ASSET RATIONALIZATION ACTIVITIES
In December 1996, the Company acquired all of the capital stock of
Millarville Oil & Gas Ltd., a privately held owner and operator of oil and gas
properties in Alberta, Canada. The Company completed the acquisition, which
added proved reserves of 2.2 MMBOE of oil and 6.8 Bcf of natural gas, in
December 1996 for a purchase price of $11.8 million. The purchase price for
the Millarville properties was funded by available cash and $3.6 million of
long-term borrowings by a Canadian subsidiary of the Company. The Company now
operates 75% of the acquired reserves.
Also in 1996, the Company purchased additional interests in the Maynor Creek
Field in Mississippi from its partners and an average working interest of
approximately 95% in two natural gas properties, one near its existing
interests in the Southwest Oklahoma City Unit and one in south-central Texas.
During the year ended December 31, 1996, the Company completed its three-
year program of rationalizing its asset base by selling both its gas gathering
system in the Southwest Oklahoma City Unit and its interests in 438 wells on
various locations. The wells sold represented 53% of the Company's total well
count but less than 2% of proved reserves. In addition, the Company sold a
portion of its reserves in the Hanlan Swan Hills Unit along with a portion of
its interest in the related gas processing plant in Alberta, Canada. The
proceeds from this sale contributed to the acceleration of payout of the
Company's partners' investment in the Hanlan-Robb area into the first quarter
of 1997, increasing the Company's current working interest ownership by 40%.
The Company expects to continue to pursue acquisition opportunities to
complement its exploration and drilling activities. 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.
3
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, 1996, 1995 and 1994. 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.
YEAR ENDED DECEMBER
31,
--------------------
1996 1995 1994
------ ------ ------
Net oil produced (Mbbls):
United States........................................... 662 656 562
Canada.................................................. 5 2 2
------ ------ ------
Total................................................. 667 658 564
Average oil sales price (per Bbl):
United States........................................... $19.89 $17.80 $15.98
Canada.................................................. 23.12 17.86 15.54
Weighted average........................................ 19.91 17.80 15.98
Net gas produced (MMcf):
United States........................................... 5,155 6,084 6,402
Canada.................................................. 3,182 3,199 3,444
------ ------ ------
Total................................................. 8,337 9,283 9,846
Average gas sales price (per Mcf):
United States........................................... $ 2.36 $ 1.62 $ 1.83
Canada.................................................. 1.34 .90 1.30
Weighted average........................................ 1.97 1.37 1.64
Oil equivalents produced (MBOE):
United States........................................... 1,521 1,670 1,629
Canada.................................................. 535 535 576
------ ------ ------
Total................................................. 2,056 2,205 2,205
Average sales price (per BOE):
United States........................................... $16.65 $12.89 $12.70
Canada.................................................. 8.20 5.48 7.80
Weighted average........................................ 14.45 11.09 11.42
Production costs (per BOE):
United States........................................... $ 3.89 $ 3.75 $ 3.86
Canada.................................................. 1.39 1.95 1.51
Weighted average........................................ 3.24 3.31 3.25
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-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.
4
During the year ended December 31, 1996, Pan-Alberta (the purchaser of most
of the Company's Canadian gas), EOTT Energy Operated Limited Partnership and
Sun Refining and Marketing Company (two of the Company's purchasers of oil)
accounted for 17%, 20% and 14% 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
From time to time, 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) 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-
5
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 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
6
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, 1996, PetroCorp had 55 full-time employees.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to all of the risks normally incident
to the exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, oil spills and fires, each of which
could result in severe damage to or destruction of oil and gas wells,
production facilities or other property or injury to persons. The energy
business is also subject to environmental hazards, such as oil spills, gas
leaks and ruptures and discharges of toxic substances or gases that could
expose the Company to substantial liability due to pollution and other
environmental damage. Although the Company maintains insurance coverage
considered to be customary in the industry, it is not fully insured against
certain of these risks, either because such insurance is not available or
because of high premium costs. The occurrence of a significant event that is
not fully insured against could have a material adverse effect on the
Company's financial position.
7
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, 1996 was attributable to seven 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, 1996, all of which are taken from
reports prepared by Huddleston & Co., Inc. and Paddock Lindstrom & Associates
Ltd. in accordance with the rules and regulations of the Securities and
Exchange Commission (SEC).
DECEMBER 31, 1996
-------------------------------------
ESTIMATED PROVED
RESERVES
----------------------
OIL GAS
PROPERTY/AREA (MBBLS) (MMCF) MBOE PV-10
------------- ------ ------ ------ --------------
(IN THOUSANDS)
Hanlan-Robb................................ 21 47,383 7,918 $ 56,831
Oklahoma City Area......................... 2,069 8,971 3,564 39,353
Mississippi Salt Basin..................... 987 142 1,010 16,415
Northern Oklahoma Area..................... 422 1,151 614 10,435
Worsley Field.............................. 596 1,006 764 8,040
Scott Field................................ 32 1,632 304 5,847
Glick Field................................ 1 2,809 469 4,817
----- ------ ------ --------
Subtotal................................. 4,128 63,094 14,643 141,738
Others..................................... 1,104 17,679 4,051 35,019
----- ------ ------ --------
Total.................................... 5,232 80,773 18,694 $176,757
===== ====== ====== ========
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 accounts for 40% of the Company's net daily gas
production. The Company has ownership interests in all eight 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 #1.
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
has increased by 40%, from 5.4% to 7.5%. 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 Southwest Oklahoma City Unit located within
the metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect
located just north of the city. The Southwest 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, 1996, PetroCorp had an undeveloped leasehold position
of 788 gross (525 net) acres in the Edmond Prospect.
Mississippi Salt Basin. Production from the Mississippi Salt Basin accounts
for 30% of PetroCorp's net domestic oil sales. 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 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 57.7%
before payout and 65% after payout 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
8
seismic database in the area (approximately 13,000 line-miles of data) and
other proprietary information held by Shell. As of December 31, 1996,
PetroCorp had an undeveloped leasehold position of 13,709 gross (6,390 net)
acres in this area.
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 fourteen fields. PetroCorp operates 28 of the
wells in nine fields located in this trend, of which two fields are the
subject of pressure maintenance waterfloods. The Company also has non-operated
working interests in two additional waterfloods. PetroCorp continues to
actively pursue both exploration and development in the Northern Oklahoma
Area, and at December 31, 1996 had an undeveloped leasehold position of
approximately 17,410 gross (11,193 net) acres.
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 owns 100% of the
working interests. It also owns an interest in one non-operated well. With an
undeveloped leasehold position of 1,040 gross (976 net) acres at December 31,
1996, the Company plans to pursue further development of this field.
Scott Field. This prolific five-well field in south central Louisiana
produces primarily natural gas with associated condensate. PetroCorp owns an
interest of approximately 3% in the field.
Glick Field. The Glick field is located in Kiowa County in southern Kansas
and is one of several natural gas producing fields that form an arc around the
southern end of the Central Kansas Uplift. PetroCorp currently has interests
in and operates a total of eight wells in the field.
Other Properties. Other significant properties include the Harris Field
located in Live Oak County in south central Texas, the Paradox Basin area of
southwest Colorado and the Cheyenne West Field in western Oklahoma.
TITLE TO PROPERTIES
United States. Except for the Company-owned mineral fee, royalty and
overriding royalty interests shown in the "Acreage and Wells" table below,
substantially all of the Company's United States property interests are held
pursuant to leases from third parties. The Company believes that it has
satisfactory title to its properties in accordance with standards generally
accepted in the oil and gas industry. In numerous instances the Company has
acquired legal title to producing properties and has carved out of the
properties so acquired net profits royalty interests in favor of institutional
investors who supplied a substantial portion of the funds for the acquisition
of such properties. The producing property reserves of the Company are stated
after giving effect to the reduction in cash flow attributable to such net
profits royalty interests. In addition, the Company's properties are subject
to customary royalty interests, liens for current taxes and other burdens that
the Company believes do not materially interfere with the use of or affect the
value of such properties.
Canada. Canadian property interests are held primarily under leases from the
Crown. A small percentage are from freehold owners. Prior to drilling on a
non-Crown lease or acquiring a non-Crown producing lease, the Company
generally obtains a title opinion covering the "historical" (freehold) title.
The Company generally relies on a title certificate under Canada's Torrens
title registration system to verify "current" (leasehold) ownership. Except
for these differences, title matters in Canada are similar to those in the
United States.
OIL AND GAS RESERVES
All information herein regarding estimates of the Company's proved reserves,
related future net revenues and PV-10 is taken from reports prepared by
Huddleston & Co., Inc. and Paddock Lindstrom & Associates Ltd. (together, 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.
9
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, 1996. 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.
DECEMBER 31, 1996
--------------------------
UNITED
STATES CANADA TOTAL
-------- -------- --------
PROVED RESERVES:
Oil (Mbbls)........................................ 4,108 1,124 5,232
Gas (MMcf)......................................... 26,620 54,153 80,773
Oil equivalents (MBOE)............................. 8,545 10,149 18,694
Future net revenues ($000s).......................... $159,064 $123,353 $282,417
Present value of future net revenues ($000s)......... $103,145 $ 73,612 $176,757
PROVED DEVELOPED RESERVES:
Oil (Mbbls)........................................ 2,414 941 3,355
Gas (MMcf)......................................... 22,517 46,125 68,642
Oil equivalents (MBOE)............................. 6,167 8,628 14,795
Future net revenues ($000s).......................... $105,245 $102,584 $207,829
Present value of future net revenues ($000s)......... $ 77,211 $ 60,637 $137,848
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and future amounts and
timing of development expenditures, including many factors beyond the control
of the Company. Reserve engineering is a subjective process of estimating
underground accumulations of crude oil and natural gas that cannot be measured
in an exact manner, and the accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Estimates of proved undeveloped reserves are inherently less
certain than estimates of proved developed reserves. The quantities of oil and
gas that are ultimately recovered, production and operating costs, the amount
and timing of future development expenditures, geologic success and future oil
and gas sales prices may all differ from those assumed in these estimates. In
addition, the Company's reserves may be subject to downward or upward revision
based upon production history, purchases or sales of properties, results of
future development, prevailing oil and gas prices and other factors.
Therefore, the present value shown above should not be construed as the
current market value of the estimated oil and gas reserves attributable to the
Company's properties.
In accordance with SEC guidelines, the Independent Engineers' estimates of
future net revenues from the Company's proved reserves and the present value
thereof are made using oil, gas and sulfur sales prices in effect as of the
dates of such estimates and are held constant throughout the life of the
properties except where such guidelines permit alternate treatment, including,
in the case of gas contracts, the use of fixed and determinable contractual
price escalations. See "Marketing" under Item 1 of this report, "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
under Item 7 of this report and "Supplemental Information to Consolidated
Financial Statements" in the Notes to the Consolidated Financial Statements of
the Company. Estimates of the Company's proved oil and gas reserves were not
filed with or included in reports to any other federal authority or agency
other than the SEC during the fiscal year ended December 31, 1996.
10
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, 1996.
DEVELOPED ACRES UNDEVELOPED ACRES(1)
---------------------------- -----------------------------
NET NET
PARTICIPATING PARTICIPATING
GROSS NET INTEREST(2) GROSS NET INTEREST(2)
------- ------ ------------- ------- ------- -------------
United States:
Colorado.......... 10,186 7,894 7,894 73,103 56,496 56,496
Kansas............ 4,960 3,420 647 10 6 1
Louisiana......... 1,808 125 125 201 66 66
Mississippi....... 800 356 356 13,709 6,390 6,390
Oklahoma.......... 46,306 16,795 12,713 37,990 24,558 24,483
Texas............. 23,840 8,551 5,167 14,981 4,754 4,723
Other............. 2,367 489 490 3,202 547 547
Canada:
Alberta........... 91,960 23,205 14,040 146,401 40,882 29,231
------- ------ ------ ------- ------- -------
Total........... 182,227 60,835 41,432 289,597 133,699 121,937
======= ====== ====== ======= ======= =======
- --------
(1) Approximately 56% of net (approximately 62% of net participating interest)
undeveloped acres are covered by leases that expire during 1997. The
Company has the option, which it plans to exercise for approximately 60% of
the acreage, to extend the primary lease term under certain conditions for
51,072 net (as well as net participating interest) undeveloped areas in
Colorado. Assuming the Company exercises its option to extend the lease
term for 60% of the acreage, approximately 40% of net (approximately 30% of
net participating interest) undeveloped acres would be covered by leases
that expire in 1997.
(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, 1996, the Company had working interests in 291 gross (120
net) producing oil wells and 197 gross (59 net) producing gas wells. Of these
wells, 67 gross (25 net) oil wells and 83 gross (19 net) gas wells were in
Canada, and the remainder of the oil and gas wells were in the United States.
The Company had two wells with multiple completions in the United States.
11
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, 1996, 1995 and 1994 is set forth below:
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------
1996 1995 1994
---------------------------- ---------------------------- ----------------------------
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)
------------ ----- -------- ------------- ----- -------- ------------- ----- -------- -------------
UNITED STATES
Development:
Oil................... 6 3.6 3.3 8 3.5 2.9 7 3.1 3.1
Gas................... 5 .1 0.0(2) 3 .8 .8 3 .5 .4
Nonproductive......... 5 2.2 2.2 6 3.2 3.0 4 1.7 1.7
--- ---- ---- --- ---- ---- --- ---- ----
Total............... 16 5.9 5.5 17 7.5 6.7 14 5.3 5.2
--- ---- ---- --- ---- ---- --- ---- ----
Exploratory:
Oil................... 1 .3 .3 4 2.2 2.2 6 4.3 4.1
Gas................... 2 .5 .4 3 1.5 1.1 2 .4 .4
Nonproductive......... 6 3.5 3.5 4 2.4 2.4 8 4.5 4.5
--- ---- ---- --- ---- ---- --- ---- ----
Total............... 9 4.3 4.2 11 6.1 5.7 16 9.2 9.0
--- ---- ---- --- ---- ---- --- ---- ----
CANADA
Development:
Oil................... -- -- -- 0 0.0 0.0 -- -- --
Gas................... -- -- -- 1 .3 .1 -- -- --
Nonproductive......... -- -- -- 0 0.0 0.0 -- -- --
--- ---- ---- --- ---- ---- --- ---- ----
Total............... -- -- -- 1 .3 .1 -- -- --
--- ---- ---- --- ---- ---- --- ---- ----
Exploratory:
Oil................... -- -- -- -- -- -- 0 0.0 0.0
Gas................... 1 .3 .1 -- -- -- 0 0.0 0.0
Nonproductive......... 1 .5 .5 -- -- -- 1 .3 .2
--- ---- ---- --- ---- ---- --- ---- ----
Total............... 2 .8 .6 -- -- -- 1 .3 .2
--- ---- ---- --- ---- ---- --- ---- ----
Total................... 27 11.0 10.3 29 13.9 12.5 31 14.8 14.4
=== ==== ==== === ==== ==== === ==== ====
- --------
(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, 1996, the Company was participating in the drilling or
completion of 3 gross (.9 net) wells in Canada.
12
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 of gas per day. For the 12
months ending December 31, 1996, plant throughput averaged 200 MMcf per day
(67% of design capacity). Recent activity for the Hanlan Unit included
installation and start-up of a $10.0 million compression project. In addition,
the first of several potential horizontal laterals from existing Hanlan Unit
wells has been drilled and is awaiting final production testing. The Hanlan 6-
23 well has been deviated laterally almost 1,000 feet in an attempt to
increase its productivity and mitigate natural field decline. 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.
A wholly-owned subsidiary of the Company, Fidelity Gas Systems, Inc.
("FGS"), owns and operates the Anasazi Gas Gathering System, which gathers gas
produced from the Company-operated lease in the Paradox Basin area of
southwest Colorado. The Company as operator, along with the other working
interest owners, has entered into contracts with FGS pursuant to which FGS
purchases all of the gas produced from the area. This gas is then resold by
FGS to a purchaser at a redelivery point on the national transmission pipeline
system. Proceeds payable by FGS are based upon FGS's resale price less a
contractually agreed-upon fee. Amounts received by the Company from FGS 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 is considered nonjurisdictional with
respect to existing FERC rules and regulations.
As previously discussed as part of the asset rationalization program, FGS
sold its Southwest Oklahoma City Field gas gathering system in March 1996.
In addition to the gas gathering systems, for several years FGS owned a 10%
interest in a crude oil pipeline. FGS purchased the remaining 90% of this
pipeline in September 1995 and sold the entire pipeline to a third party in
February 1996.
OTHER FACILITIES
The Company leases approximately 31,600 square feet in Houston, Texas for
its executive and divisional offices. Additionally, the Company leases
approximately 18,500 square feet in Oklahoma City, Oklahoma and approximately
2,900 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.
13
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
predominately on its ability to replace present reserves through acquisitions
and development and exploratory drilling, as well as on its ability to
successfully develop additional reserves. There can be no assurance that the
Company's acquisition and exploration activities or planned development
projects will result in significant additional reserves or that the Company
will have continuing success at drilling economically productive wells.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, 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
14
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 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.
15
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 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.
16
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 1995 and 1996, and for a portion of the Company's current
quarter, as reported by The Nasdaq Stock Market.
1995 1996 1997
------------------------------- ------------------------------- ------------------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH FIRST QUARTER
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER (THROUGH MARCH 17)
------- ------- ------- ------- ------- ------- ------- ------- ------------------
High.................... $10.88 $9.00 $8.25 $8.38 $7.50 $10.00 $9.63 $10.00 $10.13
Low..................... 6.25 8.25 6.38 6.88 5.88 6.75 8.25 8.13 9.00
As of March 17, 1997, the closing price for the Company's Common Stock was
$9.00 per share. As of March 17, 1997, there were approximately 780 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.
17
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. The Company's results of operations for
each year in the five-year period ended December 31, 1996 are not comparable
due to the acquisition of properties from Park Avenue Exploration Company in
October 1992.
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
INCOME STATEMENT DATA:
REVENUES:
Oil and gas................ $ 29,718 $ 24,448 $ 25,176 $ 30,129 $ 16,573
Plant processing........... 1,658 1,880 1,852 2,054 2,284
Other...................... 170 1,037 923 705 604
-------- -------- -------- -------- --------
31,546 27,365 27,951 32,888 19,461
-------- -------- -------- -------- --------
EXPENSES:
Production costs........... 6,660 7,304 7,156 8,011 4,839
Depreciation, depletion and
amortization.............. 12,433 13,300 12,800 13,058 6,947
Oil and gas property
valuation adjustment...... -- 8,500 -- -- 2,400
General and administrative. 4,672 5,544 5,067 5,210 3,350
Other operating expenses... 203 256 98 299 84
-------- -------- -------- -------- --------
23,968 34,904 25,121 26,578 17,620
-------- -------- -------- -------- --------
INCOME (LOSS) FROM
OPERATIONS.................. 7,578 (7,539) 2,830 6,310 1,841
-------- -------- -------- -------- --------
OTHER INCOME (EXPENSES):
Investment and other
income.................... 1,910 1,470 1,411 1,264 422
Interest expense........... (3,391) (3,917) (3,229) (2,333) (1,257)
Preferred dividends of
subsidiary................ -- -- (648) (1,214) (1,403)
Other expenses............. (46) (159) (131) (68) (424)
-------- -------- -------- -------- --------
(1,527) (2,606) (2,597) (2,351) (2,662)
-------- -------- -------- -------- --------
INCOME (LOSS) BEFORE INCOME
TAXES....................... 6,051 (10,145) 233 3,959 (821)
Income tax provision
(benefit)................... 1,807 (608) 114 2,116 831
-------- -------- -------- -------- --------
INCOME (LOSS) BEFORE
CUMULATIVE EFFECT OF
ACCOUNTING CHANGE........... 4,244 (9,537) 119 1,843 (1,652)
Cumulative effect of
accounting change(1)........ -- -- -- 481 --
-------- -------- -------- -------- --------
NET INCOME (LOSS)............ $ 4,244 $ (9,537) $ 119 $ 2,324 $ (1,652)
======== ======== ======== ======== ========
NET INCOME (LOSS) PER SHARE.. $ 0.49 $ (1.10) $ 0.01 $ 0.33
======== ======== ======== ========
UNAUDITED PRO FORMA DATA(2):
Loss before income taxes... $ (821)
Income tax benefit......... (71)
--------
Net loss................... $ (750)
========
Net loss per share......... $ (0.17)
========
Weighted average number of
common shares............. 8,698 8,698 8,698 7,103 4,427
======== ======== ======== ======== ========
BALANCE SHEET DATA:
Working capital............ $ 1,946 $ 6,344 $ 11,767 $ 30,156 $ 9,413
Total assets............... 122,864 114,839 133,403 140,381 113,111
Long-term debt............. 33,462 36,513 41,587 39,200 36,976
Redeemable preferred stock
of subsidiary............. -- -- -- 7,691 8,678
Shareholders' equity....... 65,665 61,521 70,328 71,517 51,704
- --------
(1) Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes."
(2) Prior to October 1, 1992, the Company was exempt from U.S. federal and
certain state income taxes as a result of its partnership status. The pro
forma data reflects the income tax benefit that would have been recorded
had the Company not been exempt from such income taxes.
18
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:
FOR THE YEAR ENDED
DECEMBER 31,
--------------------
1996 1995 1994
------ ------ ------
PRODUCTION:
United States:
Oil (Mbbls)............. 662 656 562
Gas (MMcf).............. 5,155 6,084 6,402
Oil equivalents (MBOE).. 1,521 1,670 1,629
Canada:
Oil (Mbbls)............. 5 2 2
Gas (MMcf).............. 3,182 3,199 3,444
Oil equivalents (MBOE).. 535 535 576
Total:
Oil (Mbbls)............. 667 658 564
Gas (MMcf).............. 8,337 9,283 9,846
Oil equivalents (MBOE).. 2,056 2,205 2,205
AVERAGE SALES PRICES
(includes the effects of
hedging):
United States:
Oil (per Bbl)........... $19.89 $17.80 $15.98
Gas (per Mcf)........... 2.36 1.62 1.83
Canada:
Oil (per Bbl)........... 23.12 17.86 15.54
Gas (per Mcf)........... 1.34 .90 1.30
Weighted average:
Oil (per Bbl)........... 19.91 17.80 15.98
Gas (per Mcf)........... 1.97 1.37 1.64
SELECTED DATA PER BOE:
Average sales price....... $14.45 $11.09 $11.42
Production costs.......... 3.24 3.31 3.25
General and administrative
expenses................. 2.27 2.51 2.30
Oil and gas depreciation,
depletion and
amortization............. 5.24 5.22 5.15
19
RESULTS OF OPERATIONS
1996 Compared to 1995
Overview. The Company recorded $7.6 million in income from operations in
1996 compared to a loss from operations of $7.5 million in 1995. Excluding an
$8.5 million oil and gas property valuation adjustment recorded in 1995, the
improvement between periods is primarily the result of increases of 44% and
12%, respectively, in the Company's weighted average natural gas and oil
prices coupled with a 9% decrease in operating 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 $1.10 per share.
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 2,057 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 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 continued
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.
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
20
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 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).
1995 Compared to 1994
Overview. The Company's oil production and weighted average price increased
17% and 11%, respectively, while the Company's natural gas production and
weighted average price declined 6% and 16%, respectively, resulting in a 3%
decrease in oil and gas revenues for 1995. The Company recorded an $8.5
million oil and gas property valuation adjustment in the second quarter of
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. Absent
the oil and gas property valuation adjustment, income from operations for 1995
was $1.0 million compared to $2.8 million income from operations in 1994.
Total revenues decreased 2% to $27.4 million from $28.0 million, while
operating expenses, excluding the oil and gas property valuation adjustment,
increased 5% to $26.4 million from $25.1 million. The Company's net loss of
$9.5 million, or $1.10 per share, for 1995 compares to net income of $119,000,
or $0.01 per share, for 1994.
Revenues. Total revenues decreased 2% to $27.4 million in 1995 from $28.0
million in 1994. Oil production increased 17% to 658 Mbbls in 1995 from 564
Mbbls in 1994. However, natural gas production decreased 6% to 9,283 MMcf from
9,846 MMcf, resulting in production volumes remaining level at 2,205 MBOE
between years. The increase in oil production primarily reflects the positive
response to waterflooding operations in the Oklahoma Misener Trend and new
production from two wells in the Maynor Creek Field located in the Mississippi
Salt Basin. Natural gas production in the U.S. decreased primarily as a result
of normal production declines, while Canadian production decreased due to
normal production declines and a significant well in the Hanlan-Robb Area of
western Alberta, Canada being shut-in indefinitely due to its high sulfur
content. The Company's average U.S. oil price increased 11% to $17.80 per
barrel for 1995 from $15.98 per barrel for 1994 . As a result of hedging
transactions, the Company's 1995 average oil price was increased by $0.49 per
barrel from the average price that would have otherwise been received. The
Company's average U.S. natural gas price declined 11% to $1.62 per Mcf from
$1.83 per Mcf while the average Canadian natural gas price decreased 31% to
$0.90 per Mcf from $1.30 per Mcf. Though oil prices and volumes were up, the
decrease in natural gas prices and volumes resulted in a 3% decrease in oil
and gas revenues to $24.4 million in 1995 from $25.2 million in 1994. Plant
processing revenues remained level at $1.9 million while other revenues were
up 12% to $1.0 million from $923,000 primarily due to increased sulfur prices
($31.97 per long-ton in 1995 compared to $16.92 per long-ton in 1994).
Production Costs. Production costs increased 1% to $7.3 million in 1995
compared to $7.2 million in 1994, while production costs per BOE increased 2%
to $3.31 per BOE from $3.25 per BOE.
Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 4% to
$13.3 million in 1995 from $12.8 million in 1994, primarily as a result of an
increase in other property, plant and equipment depreciation coupled with a
small increase in the oil and gas DD&A rate. On a BOE basis, the oil and gas
DD&A rate increased 1% to $5.22 per BOE from $5.15 per BOE.
21
Oil and Gas Property Valuation Adjustment. The Company follows the full cost
method of accounting for its oil and gas properties. Under this method, all
productive and non-productive exploration and development costs, incurred for
the purpose of finding oil and gas reserves, are capitalized and may not
exceed a calculated ceiling computed on a country-by-country basis. The
ceiling is calculated on a quarterly basis as the sum of (i) the present value
(discounted at 10%) of future net revenues from estimated production of proved
oil and gas reserves plus (ii) the lower of cost or estimated fair market
value of the unproved properties, less (iii) the related income tax effects.
At 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's net capitalized costs for its U.S. oil and gas
properties exceeded the ceiling by $8.5 million, resulting in the
corresponding valuation adjustment. The ceiling was calculated using $16.00
per barrel of oil and $1.52 per Mcf of natural gas, the prices in effect as of
June 30, 1995.
General and Administrative Expenses. Though general and administrative
expenses increased 8% to $5.5 million in 1995 from $5.1 million in 1994, gross
general and administrative expenses, before deducting capitalized amounts and
cost reimbursements, decreased by 2%. The 8% increase in the reported general
and administrative expenses reflects the impact of a reduction in the amount
being capitalized as oil and gas property costs during 1995 as compared to
1994. Additionally, the Company received lower cost reimbursements during
1995, primarily as a result of the close out of the management of the limited
partnerships in which the Company served as general partner through June 1994,
at which time the limited partnerships were liquidated.
Investment and Other Income. Investment and other income increased 7% to
$1.5 million in 1995 compared to $1.4 million in 1994. 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 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 two events, investment and other income would have
decreased 36% to $900,000 primarily as a result of reduced funds available for
investment during 1995 as compared to 1994.
Interest Expense. Interest expense increased 22% to $3.9 million in 1995
from $3.2 million in 1994, primarily as a result of the nonrecourse notes
payable being outstanding for a full year in 1995. On August 9, 1994, the
Company's Canadian subsidiary issued $7.0 million in nonrecourse long-term
notes payable to replace its redeemable preferred stock which was redeemed on
that date. That portion of interest expense related to the Company's
nonrecourse notes payable was $1.0 million in 1995 compared to $397,000 in
1994.
Preferred Dividends of Subsidiary. As discussed above, on August 9, 1994,
the Company's Canadian subsidiary redeemed its preferred stock and issued
nonrecourse long-term notes payable. Accordingly, no preferred dividends were
declared for 1995 compared to $648,000 charged to expense in 1994.
Income Taxes. The Company recorded a $608,000 income tax benefit on a pre-
tax loss of $1.6 million (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) in 1995 compared to an income tax
provision of $114,000 on pre-tax net income of $233,000 in 1994.
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, 1996,
the Company had working capital of $1.9 million as compared to $6.3 million at
December 31, 1995. The decrease in working capital was primarily due to
capital expenditures and reductions in long-term debt exceeding net cash
provided by operating activities and proceeds from asset sales. Net cash
provided by operating activities
22
was $18.4 million, $10.5 million and $9.3 million for 1996, 1995 and 1994,
respectively, while net cash provided by operating activities before changes
in operating assets and liabilities for the same periods was $17.5 million,
$11.7 million and $12.4 million, respectively.
The Company's total capital expenditures, including capitalized internal
costs, for 1996, 1995 and 1994 were $29.5 million, $16.6 million and $29.5
million, respectively. 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 purchase 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). Capital
expenditures in 1995 included $10.2 million in exploration and development
drilling expenditures, $5.1 million in lease acquisitions, geological and
geophysical costs and $138,000 in producing property acquisitions. Capital
expenditures in 1994 included $14.4 million in exploration and development
drilling expenditures, $7.3 million in lease acquisitions, geological and
geophysical costs and $5.3 million in producing property acquisitions.
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. In addition,
the Company sold a portion of its reserves in the Hanlan Swan Hills Unit along
with a portion of its interest in the related Hanlan-Robb gas processing plant
in Alberta, Canada. Proceeds from oil and gas property sales in 1996, 1995 and
1994 were $6.3 million, $4.4 million (primarily non-performing fee mineral
interests) and $4.1 million, respectively. The Company received $3.8 million
from the 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.
In March 1996, the Company's wholly-owned subsidiary, Fidelity Gas Systems,
Inc., sold its Southwest 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 Southwest Oklahoma City Field. Through December 31, 1996,
$694,000 has been recognized, leaving a balance of $1.4 million in "deferred
revenue" on the consolidated balance sheet as of December 31, 1996.
In July 1993, PetroCorp refinanced its long-term debt through the issuance
of $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, 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 and to
four unaffiliated institutional investors in amounts totaling $20.0 million
and $10.0 million, respectively. Mandatory redemptions commenced on December
31, 1994 for the Series A Notes and commenced on December 31, 1995 for the
Series B Notes. As of December 31, 1996, the remaining principal balances for
the Series A and B Notes were $4.6 million and $26.2 million, respectively,
for a total of $30.9 million of which $5.0 million was classified as current.
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.
On December 30, 1996, the Company, through a wholly-owned Canadian
subsidiary, entered into a long-term borrowing arrangement with the Royal Bank
of Canada (RBC) whereby the Company borrowed $3.6 million to partially fund
the Millarville Acquisition. The arrangement allows the Company forego
principal payments during the first year. Additionally, the Company may elect
to pay interest only (Interest Only Period)
23
in subsequent years if the Company's Canadian subsidiary meets certain
borrowing base tests. Otherwise, the loan becomes payable over a three-year
period as follows: $1,575,000 in the first year, $1,200,000 in the second year
and $873,000 in the third year (the Term Period). 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 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%.
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, 1996, the nonrecourse long-term notes payable balance was $4.7 million, of
which $763,000 was classified as current.
Product prices continue to be volatile. Since December 31, 1996, 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 1 to the
Consolidated Financial Statements -- Property, Plant and Equipment). At
December 31, 1996, the Company had ceiling cushions in excess of $24 million
and $25 million, respectively, related to its U.S. and Canadian oil and gas
properties. However, should product prices continue to decline 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.
From time to time, 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 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. To date, 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, 1996.
In connection with its oil and gas hedging program, the Company may be
exposed to the risk of financial loss in certain circumstances including
instances where production is less than expected, the Company's customers fail
to purchase or take delivery of the contracted sales quantities, or a sudden,
unexpected event materially impacts product prices, as occurred at year-end
1995. The Company has attempted to reduce these risks by limiting, at any
point in time, its U.S. hedged oil and natural gas sales volumes to
approximately 85% of total U.S. sales volumes and limiting its Canadian hedged
natural gas sales volumes to approximately 65% of total Canadian natural gas
sales volumes.
The Company's Board of Directors has approved a capital budget of $26.0
million for 1997. The approved 1997 capital budget includes $16.0 million for
exploration and development projects and $10.0 million 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 1997 exploration and development
expenditures with its cash flow from operations while it plans to finance the
its 1997 producing property acquisitions with new borrowings. 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.
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages 28 through 52 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, 1996 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
PAGE OF
THIS
REPORT
-------
Report of Independent Accountants...................................... 28
Consolidated Balance Sheet as of December 31, 1996 and December 31,
1995.................................................................. 29
Consolidated Statement of Operations for the Years Ended December 31,
1996, 1995 and 1994................................................... 30
Consolidated Statement of Shareholders' Equity for the Years Ended
December 31, 1996, 1995 and 1994...................................... 31
Consolidated Statement of Cash Flows for the Years Ended December 31,
1996, 1995 and 1994................................................... 32
Notes to Consolidated Financial Statements............................. 33
2. Financial Statement Schedules
Not Applicable.
3. Exhibits
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").
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.
25
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 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. 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.
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.
26
23.2 Consent of Huddleston & Co., Inc.
23.3 Consent of Paddock Lindstrom & Associates Ltd.
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.
- --------
* Incorporated by reference.
(b) Reports on Form 8-K
Report, dated October 22, 1996, relating to a press release regarding the
increase by Kaiser-Francis Oil Company of its ownership of the Company's
Common Stock.
Report, dated December 23, 1996, relating to the Company's acquisition of
the capital stock of Millarville Oil & Gas Ltd.
27
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 25 present fairly, in all material
respects, the financial position of PetroCorp Incorporated and its
subsidiaries at December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1996, 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 7, 1997
28
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEET
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
DECEMBER 31
------------------
ASSETS 1996 1995
------ -------- --------
Current assets:
Cash and cash equivalents................................ $ 8,859 $ 11,764
Accounts receivable, net................................. 8,114 7,632
Other current assets..................................... 312 1,433
-------- --------
Total current assets................................... 17,285 20,829
-------- --------
Property, plant and equipment:
Proved oil and gas properties, at cost, full cost method,
net of accumulated depreciation, depletion and
amortization............................................ 93,161 79,667
Unproved oil and gas properties, not subject to
depletion............................................... 5,279 4,406
Plant and related facilities, net........................ 4,585 6,389
Other, net............................................... 2,257 3,128
-------- --------
105,282 93,590
-------- --------
Other assets, net.......................................... 297 420
-------- --------
Total assets........................................... $122,864 $114,839
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable......................................... $ 6,007 $ 5,259
Accrued liabilities...................................... 3,569 3,370
Current portion of long-term debt........................ 5,763 5,856
-------- --------
Total current liabilities.............................. 15,339 14,485
-------- --------
Long-term debt............................................. 33,462 36,513
-------- --------
Deferred revenue........................................... 1,395 --
-------- --------
Deferred income taxes...................................... 7,003 2,320
-------- --------
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 and 8,584,519 shares
outstanding............................................. 86 86
Additional paid-in capital............................... 71,170 71,170
Retained earnings (accumulated deficit).................. (1,799) (6,043)
Foreign currency translation adjustment and other........ (3,475) (3,375)
Treasury stock, at cost (31,697 shares).................. (317) (317)
-------- --------
Total shareholders' equity............................. 65,665 61,521
-------- --------
Total liabilities and shareholders' equity............. $122,864 $114,839
======== ========
The accompanying notes are an integral part of this statement.
29
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF OPERATIONS
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
FOR THE YEAR ENDED
DECEMBER 31,
-------------------------
1996 1995 1994
------- ------- -------
REVENUES:
Oil and gas........................................ $29,718 $24,448 $25,176
Plant processing................................... 1,658 1,880 1,852
Other.............................................. 170 1,037 923
------- ------- -------
31,546 27,365 27,951
------- ------- -------
EXPENSES:
Production costs................................... 6,660 7,304 7,156
Depreciation, depletion and amortization........... 12,433 13,300 12,800
Oil and gas property valuation adjustment.......... -- 8,500 --
General and administrative......................... 4,672 5,544 5,067
Other operating expenses........................... 203 256 98
------- ------- -------
23,968 34,904 25,121
------- ------- -------
INCOME (LOSS) FROM OPERATIONS........................ 7,578 (7,539) 2,830
------- ------- -------
Other income (expenses):
Investment and other income........................ 1,910 1,470 1,411
Interest expense................................... (3,391) (3,917) (3,229)
Other expenses..................................... (46) (159) (131)
Preferred dividends of subsidiary.................. -- -- (648)
------- ------- -------
(1,527) (2,606) (2,597)
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES.................... 6,051 (10,145) 233
Income tax provision (benefit)....................... 1,807 (608) 114
------- ------- -------
NET INCOME (LOSS).................................... $ 4,244 $(9,537) $ 119
======= ======= =======
Net income (loss) per share.......................... $ 0.49 $ (1.10) $ 0.01
======= ======= =======
WEIGHTED AVERAGE NUMBER OF COMMON SHARES............. 8,698 8,698 8,698
======= ======= =======
The accompanying notes are an integral part of this statement.
30
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(AMOUNTS IN THOUSANDS)
FOREIGN
RETAINED CURRENCY
ADDITIONAL EARNINGS TRANSLATION
SHARES PAID-IN (ACCUMULATED ADJUSTMENT TREASURY
ISSUED AMOUNT CAPITAL DEFICIT) AND OTHER STOCK TOTAL
------ ------ ---------- ------------ ----------- -------- -------
BALANCE, DECEMBER 31,
1993................... 8,616 $86 $71,170 $ 3,375 $(2,797) $(317) $71,517
Net income............ 119 119
Foreign currency
translation
adjustment and other. (1,308) (1,308)
----- --- ------- ------- ------- ----- -------
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
===== === ======= ======= ======= ===== =======
The accompanying notes are an integral part of this statement.
31
PETROCORP INCORPORATED
CONSOLIDATED STATEMENT OF CASH FLOWS
(AMOUNTS IN THOUSANDS)
FOR THE YEAR ENDED
DECEMBER 31,
--------------------------
1996 1995 1994
-------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................. $ 4,244 $(9,537) $ 119
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization........ 12,433 13,300 12,800
Deferred income tax provision (benefit)......... 1,807 (608) (503)
Gain on sale of gas gathering system............ (999) -- --
Oil and gas property valuation adjustment....... -- 8,500 --
-------- ------- -------
17,485 11,655 12,416
Changes in operating assets and liabilities:
Accounts receivable........................... (482) (182) 187
Other current assets.......................... 1,121 (289) (186)
Accounts payable.............................. 748 (688) (2,855)
Accrued liabilities........................... 199 (98) (460)
Other........................................... (693) 126 190
-------- ------- -------
NET CASH PROVIDED BY OPERATING ACTIVITIES..... 18,378 10,524 9,292
-------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties...... 6,304 4,421 4,085
Additions to oil and gas properties............... (28,683) (15,394) (26,995)
Additions to plant and related facilities......... (261) (416) (399)
Additions to other property, plant and equipment.. (537) (751) (2,014)
Additions to other assets......................... (31) (9) (98)
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 8,000
Additions to short-term investment................ -- -- (15,000)
-------- ------- -------
NET CASH USED IN INVESTING ACTIVITIES.............. (18,162) (5,467) (32,421)
-------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt...................... 3,908 665 7,116
Repayment of long-term debt....................... (7,028) (4,257) (1,203)
Proceeds from issuance of redeemable preferred
stock by subsidiary.............................. -- -- 20
Redemption of preferred stock by subsidiary....... -- -- (7,437)
-------- ------- -------
NET CASH USED IN FINANCING ACTIVITIES.............. (3,120) (3,592) (1,504)
-------- ------- -------
EFFECT OF EXCHANGE RATE CHANGES ON CASH............ (1) 172 (331)
-------- ------- -------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS....................................... (2,905) 1,637 (24,964)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR..... 11,764 10,127 35,091
-------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR........... $ 8,859 $11,764 $10,127
======== ======= =======
The accompanying notes are an integral part of this statement.
32
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 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 also operates a gas gathering
facility in the U.S. through its wholly-owned subsidiary, Fidelity Gas
Systems, Inc. (FGS).
Principles of consolidation
The accompanying consolidated financial statements include the accounts of
the Company and its wholly-owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated. Certain prior period amounts
have been reclassified to conform to the current year presentation.
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the amounts reported in the consolidated 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 six 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, 1996 and 1995, the cumulative amount of accrued site
restoration and dismantlement costs approximated $140,000 and $251,000,
respectively, and is included as a component of accumulated depreciation,
depletion and amortization.
Revenue recognition
Revenues from the sale of petroleum produced are recognized upon the passage
of title, net of royalties and net profits royalty interests.
33
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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, 1996 and 1995, the Company has included
in accrued liabilities $32,000 and $38,000 with respect to 20,000 Mcf and
21,000 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).
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, 1996 and 1995, 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 follows the asset and liability approach to accounting for
income taxes. Deferred tax assets and liabilities are determined using the tax
rate for the period in which those amounts are expected to be received or
paid, based on a scheduling of temporary differences between the tax bases of
assets and liabilities and their reported amounts. Under this method of
accounting for income taxes, any future changes in income tax rates will
affect deferred income tax balances and financial results.
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, 1996, 1995 and 1994, the Company recognized
foreign currency gains (losses) of $(24,000), ($13,000) and $188,000,
respectively. At December 31, 1996, 1995 and 1994, the exchange rates were ($1
CAN = $U.S.) $0.7297, $0.7329 and $0.7129, respectively, while the average
exchange rates during such years were $0.7334, $0.7312 and $0.7297,
respectively.
Earnings per common share
Earnings per common share is computed using the weighted average number of
common and common equivalent shares outstanding during the periods presented.
Common equivalent shares consist of the Company's common stock issuable upon
exercise of stock options.
34
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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,
1996, 1995 and 1994 were $7,407,000, $13,623,000 and $2,648,000, respectively.
Short-term investment
During 1994, the Company invested $15,000,000 in a mutual fund which
invested in high-quality adjustable rate mortgage securities issued or
guaranteed by the U.S. government or its agencies. This investment was
classified as an "available-for-sale security" as provided by SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities." During
1994, the Company realized $616,000 in dividend income from this investment.
However, partially offsetting the dividend income was a $192,000 loss
resulting from the sale of a portion of this investment for $8,000,000. At
December 31, 1994, the remaining short-term investment had a market value and
carrying value of $6,645,000, net of a $163,000 unrealized holding loss.
During 1995, the Company sold the remaining portion of this investment for
$6,682,000. A $126,000 loss on the sale was more than offset by $137,000 in
dividend income earned on this investment prior to the sale.
NOTE 2--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 Millarville Acquisition as if such transaction had occurred
at the beginning of 1996 and 1995. The historical results of the Company's
operations have been adjusted to reflect (i) Millarville's revenues and
operating expenses, (ii) increases in depletion, depreciation and amortization
directly attributable to the Millarville Acquisition, (iii) minor increases in
administrative costs directly attributable to the Millarville Acquisition,
(iv) the increase in interest expense related to the bank debt incurred as a
result of the Millarville Acquisition, and (v) the increase in income taxes
resulting from future income directly attributable to the Millarville
Acquisition. The pro forma amounts do not purport to be indicative of the
results of operations that would have been reported had the acquisition
occurred as of the date indicated, or that may be reported in the future (in
thousands, except per share amounts).
UNAUDITED PRO
FORMA FINANCIAL
INFORMATION FOR
THE YEAR ENDED
DECEMBER 31,
---------------
1996 1995
------- -------
Revenues....................................................... $35,855 $31,231
Income (loss) from operations.................................. 9,158 (6,642)
Net income (loss).............................................. 5,114 (9,106)
Net income (loss) per share.................................... 0.59 (1.05)
35
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 3--PROPERTY, PLANT AND EQUIPMENT:
Investments in property, plant and equipment were as follows at December 31,
1996 and 1995 (amounts in thousands):
1996 1995
-------- --------
Oil and gas properties:
Proved.................. $174,324 $150,067
Unproved................ 5,279 4,406
-------- --------
179,603 154,473
Plant and related
facilities............... 8,859 9,852
Gas gathering facilities.. 1,658 2,644
Furniture, fixtures and
equipment................ 2,507 2,652
-------- --------
192,627 169,621
Less--accumulated
depreciation, depletion
and amortization......... (87,345) (76,031)
-------- --------
$105,282 $ 93,590
======== ========
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 1996, 1995 and 1994 was
$12,279,000, $13,145,000 and $12,663,000, respectively. Oil and gas property
depreciation, depletion and amortization for the years ended December 31,
1996, 1995 and 1994 was $10,788,000, $11,510,000 and $11,353,000,
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, 1996, 1995 and 1994 was $6.38, $6.21 and $6.23, respectively, for
United States operations and $2.03, $2.13 and $2.10, respectively, for
Canadian operations. The total composite rates were $5.24, $5.22 and $5.15 for
the years ended December 31, 1996, 1995 and 1994, respectively. At June 30,
1995, the Company's net capitalized costs of its United States 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.
NOTE 4--LONG-TERM DEBT:
The Company's total long-term debt is payable as follows (amounts in
thousands):
NONRECOURSE
SERIES SERIES BANK NOTE
A B DEBT PAYABLE TOTAL
------- ------- ------ ----------- -------
1997................................. $ 2,025 $ 2,975 $ -- $ 763 $ 5,763
1998................................. 1,675 3,025 -- 763 5,463
1999................................. 875 2,925 -- 763 4,563
2000................................. -- 3,250 -- 763 4,013
2001................................. -- 2,800 -- 763 3,563
Thereafter........................... -- 11,300 3,648 912 15,860
------- ------- ------ ------ -------
$ 4,575 $26,275 $3,648 $4,727 $39,225
======= ======= ====== ====== =======
36
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Series A and Series B Senior Notes
Series A and Series B Senior Notes at December 31, 1996 and 1995 consisted
of (amounts in thousands):
1996 1995
------- -------
Series A, senior adjustable rate notes payable to a shareholder
affiliate..................................................... $ 4,575 $ 7,100
Series B, 7.55% senior notes payable to shareholder affiliates. -- 19,133
------- -------
4,575 26,233
Series B, 7.55% senior notes payable to nonaffiliates.......... 26,275 9,567
------- -------
$30,850 $35,800
======= =======
Redemption payments to affiliates and nonaffiliates were $4,142,000 and
$808,000 in 1996 and $2,967,000 and $433,000 in 1995, respectively.
Interest paid to affiliates and nonaffiliates for the years ended December
31, 1996, 1995 and 1994 amounted to $1,883,000 and $706,000, $2,150,000 and
$755,000 and $2,010,000 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
shareholder affiliates of the Company. However, 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 6.68% to 7.09%, 6.71% to 7.40% and
4.40% to 6.71% during 1996, 1995 and 1994, respectively. Interest on the
Series B notes is fixed at a rate of 7.55% and is payable semiannually in
arrears.
The Note Purchase Agreement prohibited the declaration or payment of any
cash dividends related to the Company's common stock prior to July 1, 1995. In
addition, other provisions of the Note Purchase Agreement impose upon the
Company certain financial covenants that have the effect of restricting the
amount of dividends on common stock that may be paid by the Company after June
30, 1995. These restrictions include a covenant under which the aggregate
amount of such dividends after June 30, 1995 may not exceed the sum of (i) $5
million plus (ii) 50% of consolidated net income (as defined) for the period
January 1, 1993 through the end of the then most recently completed fiscal
quarter (or less 100% of consolidated net income for such period if such
amount is a loss) plus (iii) the amount of the Company's net cash proceeds
from issuance subsequent to December 31, 1992 of shares of common stock or
options, rights or warrants to purchase common stock. Certain other
restrictive covenants could, depending upon future events and circumstances,
further reduce the amount of any dividends on common stock permitted to be
paid by the Company.
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.
37
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Bank Debt
On December 30, 1996, the Company, through a wholly-owned Canadian
subsidiary, entered into a long-term borrowing arrangement with the Royal Bank
of Canada (RBC) whereby the Company borrowed $3,648,000 to partially fund the
Millarville Acquisition. The arrangement allows the Company to forgo principal
payments in the first year. 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 as follows: $1,575,000 in the first
year, $1,200,000 in the second year and $873,000 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 August 9, 1994, the Company's Canadian subsidiary, 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 (Note 6). Consistent with the redeemable preferred
stock, the Nonrecourse Notes Payable are denominated in Canadian dollars.
During 1996 and 1995, interest payments were $896,000 and $1,010,000,
respectively, while principal payments totaled $1,938,000 and $857,000,
respectively. Additionally, in 1996 and 1995, the Company issued $261,000 and
$665,000 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.
NOTE 5--DEFERRED REVENUE:
In March 1996, FGS sold its Southwest Oklahoma City Field gas gathering
system for $3,835,000. The Company's total gain on the sale was $3,088,000,
with $999,000 being recognized in the first quarter of 1996 in "investment and
other income" on the consolidated statement of operations while the remaining
$2,089,000 of the gain was deferred. The $2,089,000 deferred revenue will be
recognized in future periods as a component of gas revenues by partially
offsetting the gas gathering fees paid by the Company over the productive life
of the Company's Southwest Oklahoma City Field. Through December 31, 1996,
$694,000 has been recognized, leaving a balance of $1,395,000 in "deferred
revenue" on the consolidated balance sheet as of December 31, 1996.
NOTE 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,
38
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
Redeemable preferred stock of subsidiary
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 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.
Prior to August 9, 1994, PCC Inc. had authorized 50,000,000 shares of First
Preferred Shares Series A, par value $1.00 (CAN) per share, which were
mandatorily redeemable and were generally nonvoting (the Redeemable Preferred
Stock). The Company had a call on the Redeemable Preferred Stock held by the
preferred shareholders entitling the Company at any time to convert the
Redeemable Preferred Stock for an amount equal to the redemption price, plus
any dividends and redemptions in arrears, to long-term debt with an interest
rate of 15% per annum. On August 9, 1994, PCC Inc. redeemed the remaining
balance of the preferred stock and issued $7,034,000 in nonrecourse long-term
notes payable to the previous holders of the preferred stock with financial
terms similar to the Redeemable Preferred Stock (Note 4). The number of shares
of Redeemable Preferred Stock redeemed for the year ended December 31, 1994
approximated $10,209,000.
During 1994, preferred dividend cash payments were $928,000 while 10,209,000
preferred shares were redeemed for $7,437,000 and 27,000 new preferred shares
were issued for $20,000.
Dividends were accrued and paid on a quarterly basis at a rate of 15% per
annum. In addition, redemptions were required to be made quarterly, based on a
fixed schedule through December 31, 2002. Dividend and redemption payments
were made only to the extent that there were 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 Redeemable Preferred Stock.
To the extent dividends and redemptions exceeded such cash proceeds, the
excess amount was carried forward to the next quarter.
NOTE 7--INCOME TAXES:
Effective January 1, 1993, the Company adopted the provisions of SFAS 109,
which requires the use of 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.
The components of income (loss) before income taxes for the years ended
December 31, 1996, 1995 and 1994 consisted of the following (amounts in
thousands):
1996 1995 1994
------ -------- -------
United States operations............................. $4,096 $(10,249) $(2,381)
Canadian operations.................................. 1,955 104 2,614
------ -------- -------
$6,051 $(10,145) $ 233
====== ======== =======
39
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The provision (benefit) for income taxes consists of the following (amounts
in thousands):
1996 1995 1994
------ ----- ----
Current:
Canadian preferred dividend tax........................... $ -- $ -- $617
------ ----- ----
Deferred:
U.S.--federal............................................. 1,475 (560) (859)
U.S.--state............................................... 84 (32) (46)
Canada.................................................... 248 (16) 402
------ ----- ----
1,807 (608) (503)
------ ----- ----
$1,807 $(608) $114
====== ===== ====
During the year ended December 31, 1994, the Company paid Canadian preferred
dividend taxes of $617,000. Canadian income tax rules allow the Company to
include 225% of the amount of preferred dividend taxes paid with the Company's
Canadian net operating loss carryforwards. Effectively, this will allow the
Company to reduce (dollar-for-dollar) future income tax payments by the amount
of the preferred dividend taxes previously paid.
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, 1996, 1995 and 1994 is presented in the following table (amounts
in thousands):
YEAR ENDED DECEMBER
31,
----------------------
1996 1995 1994
------ ------- -----
United States federal income taxes (benefit)at
statutory rate of 35%................................. $2,118 $(3,551) $ 82
Increases (reductions) resulting from:
Canadian earnings not subject to United States taxes. (684) (36) (915)
Canadian income taxes................................ 248 (16) 1,019
State income taxes................................... 84 (32) (46)
Change in valuation allowance........................ -- -- (291)
Oil and gas property valuation adjustment............ -- 2,975 --
Prior-period adjustment.............................. -- -- 232
Other................................................ 41 52 33
------ ------- -----
$1,807 $ (608) $ 114
====== ======= =====
40
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Deferred tax assets and liabilities consist of the following at December 31,
1996 and 1995 (amounts in thousands):
1996 1995
-------- --------
Deferred tax assets:
Net operating loss carryforward--U.S..................... $ 8,900 $ 9,291
Net operating loss carryforward--Canada.................. 1,738 1,831
-------- --------
Gross deferred tax asset................................... 10,638 11,122
-------- --------
Deferred tax liabilities:
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--U.S.............. (11,671) (10,503)
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--Canada........... (5,970) (2,939)
-------- --------
Gross deferred tax liability............................... (17,641) (13,442)
-------- --------
$ (7,003) $ (2,320)
======== ========
As of December 31, 1996, the Company has U.S. net operating loss
carryforwards of $24,055,000 and $17,756,000 for regular tax and alternative
minimum tax purposes, respectively, which begin to expire in 2000. 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.
In 1996, under SFAS 109, the Company was required to increase deferred
income taxes and oil and gas properties by $2,890,000 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):
YEAR ENDED DECEMBER
31,
-----------------------
1996 1995 1994
------- ----- -------
Tax computed at statutory rate of 44.34%............... $ 872 $ 46 $ 1,159
Nondeductible preferred share dividends................ -- -- 286
Nondeductible crown royalties.......................... 510 535 1,114
Resource allowance..................................... (1,134) (597) (1,540)
------- ----- -------
$ 248 $ (16) $ 1,019
======= ===== =======
NOTE 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 of which 890,740 option shares were granted and outstanding as
of December 31, 1996.
The Company has issued option shares as follows: (1) 225,000 were granted in
October 1992 in exchange for rights which existed under the 1989 PetroCorp
Equity Interest Plan (the 1989 Plan) which was terminated and replaced by the
Option Plan; these option shares have an exercise price of $5.00, which was
equal to the value of the rights under the 1989 Plan; (2) 407,740 were granted
in October 1992 and 105,000 were granted in
41
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
August 1993 with an exercise price of $10.00 and (3) 220,000 were granted in
February 1996 with an exercise price of $6.38. The exercise price for all
options equaled fair value at the date of grant. Of the option shares
previously granted with a $10.00 exercise price, 67,000 shares have been
forfeited as of December 31, 1996. The weighted-average exercise prices for
options outstanding at January 1, 1996, outstanding at December 31, 1996,
exercisable at December 31, 1996 and forfeited during 1996 were $8.43, $7.84,
$7.84 and $10.00, respectively.
In October 1996, all granted stock options 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 had purchased the common shares owned by
investment funds managed by First Reserve Corporation and the common shares
owned by a subsidiary of CIGNA Corporation. All stock options expire ten years
from the date of grant.
The Company applies Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees," and related interpretations in accounting for
the Option Plan. Accordingly, no compensation expense has been recognized for
this stock-based compensation plan. Had compensation cost for the Option Plan
been determined based upon the fair value at the grant date for awards under
such plan consistent with the methodology prescribed under SFAS No. 123,
Accounting for Stock-Based Compensation, the Company's 1996 net income and
earnings per share would have been reduced by approximately $450,000 or $0.05
per share. 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 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 permanent 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
$208,000, $243,000 and $242,000 in 1996, 1995 and 1994, respectively.
NOTE 9--RELATED PARTY TRANSACTIONS:
In February 1994, the Company completed the sale of approximately 300 U.S.
oil and gas properties. The sale of properties, in addition to the Company's
share, also included interests managed by the Company but owned by others,
principally limited partnerships in which the Company or PetroCorp Management,
Inc. (PMI), a wholly-owned subsidiary at that time, served as general partner.
As a result, the Company made liquidating distributions to the limited partners
in June 1994, allowing the Company to close out its management of the limited
partnerships.
Previously, the Company served as manager of the activities for the limited
partnerships in which the Company or PMI was the general partner. Additionally,
the Company served as operator of various wells in which such partnerships had
an interest. The Company disbursed funds to third parties on behalf of the
partnerships and was reimbursed on a monthly basis. Likewise, revenues were
received by the Company and disbursed to the partnerships and to the other well
participants, including royalty owners. During 1994, the Company received
$97,000 from affiliated partnerships, representing reimbursement of certain
costs of a general and administrative nature.
42
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 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):
UNITED GENERAL
STATES CANADA CORPORATE TOTAL
------- ------ --------- -------
1996:
Revenues................ $25,452 $6,094 $ -- $31,546
Income (loss) from
operations............. 9,446 3,433 (5,301) 7,578
Depreciation, depletion
and amortization....... 9,886 1,918 629 12,433
Capital expenditures.... 15,200 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
1994:
Revenues................ $21,311 $6,640 $ -- $27,951
Income (loss) from
operations............. 4,670 3,753 (5,593) 2,830
Depreciation, depletion
and amortization....... 10,259 2,015 526 12,800
Capital expenditures.... 25,968 3,041 497 29,506
Identifiable assets at
December 31............ 101,068 30,660 1,675 133,403
The following table reflects purchasers which accounted for more than 10% of
the Company's oil and gas revenues:
YEAR ENDED
DECEMBER 31,
----------------
1996 1995 1994
---- ---- ----
EOTT Energy Operating Limited Partnership........................ 20%
Pan-Alberta Gas Ltd.............................................. 17% 14% 19%
Sun Refining and Marketing Company............................... 14% 22% 16%
Conoco Inc....................................................... 11% 12%
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.
43
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 11--HEDGING PROGRAM AND FAIR VALUE OF FINANCIAL INSTRUMENTS:
Hedging Program
From time to time, 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 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. Since initiating the hedging program, 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. The Company had no open hedging positions as of
December 31, 1996. As of December 31, 1995, deferred losses related to hedged
oil and natural gas sales totaled $227,000 and $148,000, respectively.
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.
In connection with its oil and gas hedging program, the Company may be
exposed to the risk of financial loss in certain circumstances including
instances where production is less than expected, the Company's customers fail
to purchase or take delivery of the contracted sales quantities, or a sudden,
unexpected event materially impacts product prices, as occurred at year-end
1995. The Company attempts to reduce these risks by limiting, at any point in
time, its U.S. hedged oil and natural gas sales volumes to approximately 85%
of total U.S. sales volumes and limiting its Canadian hedged natural gas sales
volumes to approximately 65% of total Canadian natural gas sales volumes.
Fair value of financial instruments
The following information discloses the fair value of the Company's
financial instruments in accordance with SFAS 107, "Disclosures about Fair
Value of Financial Instruments" (amounts in thousands):
CARRYING FAIR
AMOUNT VALUE
-------- -------
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)
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.
44
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 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 $605,000, $418,000, $393,000, $396,000 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, 1996, 1995 and 1994
was $646,000, $637,000 and $631,000, 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.
45
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
(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):
U.S. CANADA TOTAL
------- ------- -------
1996:
Acquisition of properties:
Proved properties.................................... $ 5,157 $12,187 $17,344
Unproved properties.................................. 645 141 786
Exploration costs...................................... 3,029 770 3,799
Development costs...................................... 6,214 540 6,754
------- ------- -------
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
======= ======= =======
1994:
Acquisition of properties:
Proved properties.................................... $ 6,139 $ -- $ 6,139
Unproved properties.................................. 3,103 85 3,188
Exploration costs...................................... 10,091 2,250 12,341
Development costs...................................... 5,019 308 5,327
------- ------- -------
Total................................................ $24,352 $ 2,643 $26,995
======= ======= =======
Included in the above amounts for the years ended December 31, 1996, 1995 and
1994 were $1,690,000, $1,962,000 and $2,552,000, respectively, of capitalized
internal costs related to property acquisition, exploration and development. In
1996, under SFAS 109, the Company was required to increase deferred income
taxes and oil and gas properties by $2,890,000 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.
46
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):
U.S. CANADA TOTAL
-------- ------- --------
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
======== ======= ========
Of the unproved properties capitalized cost at December 31, 1996,
approximately $2,931,000 and $1,282,000 was incurred in 1996 and 1995,
respectively. The Company anticipates evaluating these properties during
subsequent years.
47
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):
U.S. CANADA TOTAL
------- ------ -------
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)
======= ====== =======
1994:
Revenues........................................... $20,683 $4,493 $25,176
Production costs................................... (6,284) (872) (7,156)
Depreciation, depletion and amortization........... (10,146) (1,207) (11,353)
Income tax expense................................. (1,574) (748) (2,322)
------- ------ -------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................... $ 2,679 $1,666 $ 4,345
======= ====== =======
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.
48
The Company's estimates of its proved reserves and proved developed reserves
of oil and gas as of December 31, 1996, 1995 and 1994 and the changes in its
proved reserves are as follows:
U.S. CANADA TOTAL
--------------- -------------- --------------
OIL GAS OIL GAS OIL GAS
------- ------ ------ ------ ------ ------
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
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
====== ====== ===== ====== ====== ======
1994:
Proved reserves:
Beginning of year........... 6,220 33,245 20 50,780 6,240 84,025
Production.................. (562) (6,402) (2) (3,444) (564) (9,846)
Purchase of minerals-in-
place...................... 681 2,615 -- -- 681 2,615
Extensions and discoveries.. 666 5,722 -- 2,510 666 8,232
Sales of minerals-in-place.. (188) (3,095) -- -- (188) (3,095)
Revisions to previous
estimates.................. 28 2,327 (2) (2,442) 26 (115)
------ ------ ----- ------ ------ ------
End of year................. 6,845 34,412 16 47,404 6,861 81,816
====== ====== ===== ====== ====== ======
Proved developed reserves:
Beginning of year........... 2,305 31,805 20 47,388 2,325 79,193
====== ====== ===== ====== ====== ======
End of year................. 2,437 31,782 16 41,381 2,453 73,163
====== ====== ===== ====== ====== ======
49
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The standardized measure of discounted future net cash flows was calculated
by applying current prices to estimated future production, less future
expenditures (based on current costs) to be incurred in developing and
producing such proved reserves and the estimated effect of future income taxes
based on the current tax law. The resulting future net cash flows were
discounted using a rate of 10% per annum.
The standardized measure of discounted future net cash flow amounts
contained in the following tabulation do not purport to represent the fair
market value of oil and gas properties. No value has been given to unproved
properties. There are significant uncertainties inherent in estimating
quantities of proved reserves and in projecting rates of production and the
timing and amount of future costs. Future realization of oil and gas prices
over the remaining reserve lives may vary significantly from current prices.
In addition, the method of valuation utilized, based on current prices and
costs and the use of a 10% discount rate, is not necessarily appropriate for
determining fair value.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (amounts in thousands):
U.S. CANADA TOTAL
-------- -------- --------
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
======== ======== ========
1994:
Future gross revenues............................. $169,389 $ 57,314 $226,703
Less--future costs:
Production...................................... 48,450 17,852 66,302
Development and dismantlement................... 9,245 2,465 11,710
-------- -------- --------
Future net cash flows before income taxes......... 111,694 36,997 148,691
Less--10% annual discount for estimated timing of
cash flows....................................... 43,556 15,800 59,356
-------- -------- --------
Present value of future net cash flows before
income taxes..................................... 68,138 21,197 89,335
Less--present value of future income taxes........ 11,887 4,120 16,007
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................ $ 56,251 $ 17,077 $ 73,328
======== ======== ========
50
The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows (amounts in
thousands):
U.S. CANADA TOTAL
------- ------- --------
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
======= ======= ========
1994:
Standardized measure--beginning of period........ $52,186 $20,530 $ 72,716
Sales of oil and gas produced, net of production
costs........................................... (14,399) (3,621) (18,020)
Purchases of minerals-in-place................... 5,933 -- 5,933
Extensions and discoveries....................... 10,197 1,211 11,408
Sales of minerals-in-place....................... (4,071) -- (4,071)
Net changes in prices and production costs....... 3,494 (4,609) (1,115)
Development costs incurred and changes in
estimated future development and dismantlement
costs........................................... 1,103 (259) 844
Revisions to previous quantity estimates......... 2,615 (1,182) 1,433
Accretion of discount............................ 6,475 2,864 9,339
Changes in timing of production and other........ (7,272) (2,048) (9,320)
Net changes in income taxes...................... (10) 4,191 4,181
------- ------- --------
Standardized measure--end of period................ $56,251 $17,077 $ 73,328
======= ======= ========
51
The standardized measure amounts are based on current prices at each year end
and reflect overall weighted average prices of:
U.S. CANADA TOTAL
------ ------ ------
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
1994:
Oil (per BBL)............................................ $16.24 $16.65 $16.24
Gas (per Mcf)............................................ 1.69 1.20 1.41
Information relating to sulfur in Canada which has not been included in the
standardized measure is summarized as follows:
1996 1995 1994
------- --------- ---------
Revenues for the year ended December 31............ $99,000 $ 457,000 $ 295,000
Production (long tons) for the year ended December
31................................................ 13,337 14,284 17,418
Estimated proved reserves (long tons) as of
December 31....................................... 191,000 228,000 233,000
Present value (10%), before income taxes, of future
net revenues...................................... 132,000 4,367,000 2,273,000
Price per long ton, net of transportation costs,
used to determine future revenues at December 31.. $ 1.16 $ 32.23 $ 17.02
SUMMARIZED QUARTERLY FINANCIAL DATA
(UNAUDITED)
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER YEAR
------- ------- ------- ------- -------
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................. $ 0.14 $ 0.06 $ 0.07 $ 0.21 $ 0.49
Year Ended December 31, 1995:
Revenues............................. $6,818 $6,999 $6,416 $7,132 $27,365
Gross profit (1)..................... 1,517 (6,966) 1,399 2,055 (1,955)
Income (loss) from operations........ (56) (8,302) 56 763 (7,539)
Net income (loss) (3)................ (568) (8,927) (457) 415 (9,537)
Net income (loss) per share.......... $(0.07) $(1.03) $(0.05) $ 0.05 $ (1.10)
- --------
(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.
(3) The fourth quarter of 1995 includes a $1.0 million after-tax gain related
to the settlement of a gas contract claim against Columbia Gas System and a
$630,000 after-tax loss related to natural gas hedging activity.
52
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES 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 24, 1997
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.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Lealon L. Sargent Chairman of the Board and March 24, 1997
____________________________________ Director
Lealon L. Sargent
/s/ W. Neil McBean President, Chief Executive March 24, 1997
____________________________________ Officer (Principal Executive
W. Neil McBean Officer) and Director
/s/ Craig K. Townsend Vice President--Finance, March 24, 1997
____________________________________ Secretary and Treasurer
Craig K. Townsend (Principal Financial Officer
and Principal Accounting
Officer)
/s/ Thomas N. Amonett Director March 24, 1997
____________________________________
Thomas N. Amonett
/s/ Gary R. Christopher Director March 24, 1997
____________________________________
Gary R. Christopher
/s/ Dan L. Hale Director March 24, 1997
____________________________________
Dan L. Hale
/s/ Stephen M. McGrath Director March 24, 1997
____________________________________
Stephen M. McGrath
53
EXHIBIT INDEX
NO. ITEM
--- ----
21 --List of material subsidiaries
23.1 --Consent of Price Waterhouse LLP
23.2 --Consent of Huddleston & Co., Inc.
23.3 --Consent of Paddock Lindstrom & Associate Ltd.
27 --Financial Data Schedule