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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, 2001
or
[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 0-22650
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PETROCORP INCORPORATED
(Exact name of registrant as specified in its charter)
Texas 76-0380430
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation organization)
6733 South Yale Avenue 74136
Tulsa, Oklahoma (Zip Code)
(Address of principal executive
offices)
Registrant's telephone number, including area code: (918) 491-4500
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Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.01 per share
Preferred Stock Purchase Rights
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. [X] Yes [_] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K ((S)(S)229.045 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of February 28, 2002 was $42,680,916. Indicate the number of
shares outstanding of each of the registrant's classes of common stock, as of
February 28, 2002:
Common Stock, par value $.01 per share: 12,556,109
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held in 2002 (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...................................................... 6
3 Legal Proceedings............................................... 14
4 Submission of Matters to a Vote of Security Holders............. 14
PART II
5 Market for Registrant's Common Equity and Related Stockholder 15
Matters.........................................................
6 Selected Financial Data......................................... 16
7 Management's Discussion and Analysis of Financial Condition and 17
Results of Operations...........................................
7A Quantitative and Qualitative Disclosure about Market Risk....... 23
8 Financial Statements and Supplementary Data..................... 24
9 Changes in and Disagreements with Accountants on Accounting and 24
Financial Disclosures...........................................
PART III
10-13 (Items 10-13 incorporated by reference to Proxy Statement)...... 24
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8- 25
K...............................................................
As used in this report, "SEC" means the United States Securities and
Exchange Commission, "Bbl" means barrel, "MBbls" means thousand barrels,
"MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "BOPD" means barrel of oil
per day, "Mcf/D" means thousand cubic feet per day, "MMcf/D" means million
cubic feet per day, "Mcfe" means natural gas stated on an MCF basis and crude
oil converted to a thousand cubic feet of natural gas equivalent by using the
ratio of one Bbl of crude oil to six Mcf of natural gas, "MMcfe" means million
cubic feet of natural gas equivalents, "Bcfe" means billion cubic feet of
natural gas equivalents, "Tcf" means trillion cubic feet, "PV-10" means
estimated pretax present value of future net revenues discounted at 10% using
SEC rules, "gross" wells or acres are the wells or acres in which the Company
has a working interest, and "net" wells or acres are determined by multiplying
gross wells or acres by the Company's working interest in such wells or acres.
PART I
Item 1. Business.
General
PetroCorp Incorporated is an independent energy company engaged in the
acquisition, exploration and development of oil and gas properties, and in the
production of oil, natural gas liquids and natural gas in North America. The
Company's activities are conducted principally in the states of Oklahoma,
Texas, Mississippi, Alabama, Louisiana, Colorado and Kansas, and in the
province of Alberta, Canada.
At December 31, 2001, the Company's proved reserves totaled 6.4 MMBbls of
oil and 100.0 Bcf of natural gas and had an estimated pretax present value of
future net revenues (PV-10) of $133.2 million. On a Mcfe basis, approximately
74% 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
$1.2 million, as well as interests in natural gas processing and gathering
facilities with a net book value of $1.5 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. In August 1999, the Company signed
a Management Agreement with its largest shareholder, Kaiser-Francis Oil
Company (Kaiser-Francis), under which Kaiser-Francis agreed to provide
management, technical and administrative support for all of the Company's
operations in the United States and Canada. At that time, Gary R. Christopher
was named President and CEO of the Company. Mr. Christopher, who has served on
PetroCorp's Board of Directors since 1996, was an employee of Kaiser-Francis
Oil Company through January 1, 2002, at which time he became an employee of
PetroCorp Incorporated. This Management Agreement was approved by the
shareholders of the Company in October 1999 and took effect on November 1,
1999. A new slate of corporate officers was approved at that time. PetroCorp's
principal executive offices are located at 6733 South Yale Avenue, Tulsa,
Oklahoma 74136, with a mailing address of P.O. Box 21298, Tulsa, Oklahoma
74121-1298, and its telephone number is (918) 491-4500. Unless the context
otherwise requires, the terms the "Company" and "PetroCorp" refer to and
include PetroCorp Incorporated, its predecessor entities (including the
original Delaware corporation and the subsequent Texas general partnership)
and all subsidiaries in which PetroCorp owns a 50% or greater interest.
Business Strategy
PetroCorp and its wholly-owned Canadian subsidiaries acquire, explore and
develop oil and natural gas properties in North America.
Acquisition Strategy. The Company has grown, in large part, through the
acquisition of producing oil and gas properties. The Company generally focuses
on acquisitions of long-lived natural gas reserves, located onshore in North
America, and prefers acquisitions that provide additional potential through
development or exploitation efforts, as well as exploratory drilling
opportunities.
Exploration and Development Strategy. Exploration and development
activities are an important component of PetroCorp's business strategy.
Through its Management Agreement with Kaiser-Francis, the Company has been
able to allocate a greater portion of cash flows to exploration and
development activities.
Acquisition, Exploration and Development Activities
Merger with Southern Mineral. PetroCorp completed the acquisition of
Southern Mineral on June 6, 2001. Southern Mineral shareholders could elect to
receive .471 shares of PetroCorp common stock or cash of $4.71 or some
combination thereof for each share of Southern Mineral common stock. Based on
elections of Southern Mineral shareholders, PetroCorp issued 4 million shares
(valued at approximately $39 million) and paid cash of approximately $21.4
million. The cash consideration includes cash due to warrant and option
holders, net of cash received from the exercise of Southern Mineral warrants
and options. The totals do not reflect 800,336 shares of
1
Southern Mineral purchased by PetroCorp in open market transactions prior to
the merger for $3.4 million. See Note 4 to the financial statements for
additional data concerning the merger. 2,190 MBbls of oil and 19,722 MMcf of
gas were added through the merger.
United States. During 2001, the Company participated in a new discovery in
the Cement Field area, located in Caddo County, Oklahoma, increasing proved
reserves by 533 MMcfe. In Lavaca County, Texas, PetroCorp participated in the
successful Barnes well in the Hallettsville field area, adding 482 MMcfe of
proved reserves.
At year-end 2001, PetroCorp was not participating in any significant
exploratory projects.
PetroCorp's SW Oklahoma City Unit, which showed positive response to water
injection in 2000, has since flattened in its response. As a result, some
1,297 MBbls have been removed from the proved reserves classification.
PetroCorp recently initiated a tracer program to study the waterflood and is
currently converting additional wells for source water and for water injection
to finish out the waterflood pattern.
Canada. Recent activity in the Hanlan-Robb area has focused on the
development of the Shaw and Basing areas through the drilling of two new
horizontal wells, adding 1,089 MMcfe of reserves.
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, 2001, 2000, and 1999. The average oil sales and average gas sales have
been increased, respectively, by $68,000 ($0.11 per Bbl) and $202,000 ($0.02
per Mcf) for hedging gains during 2001. See Notes 11 and 15 to the
Consolidated Financial Statements of the Company included elsewhere in this
report for additional financial information regarding the Company's foreign
and domestic operations.
Year Ended December 31,
-----------------------
2001 2000 1999
------- ------- -------
Net oil produced (MBbls):
United States..................................... 396 294 324
Canada............................................ 203 110 138
------- ------- -------
Total........................................... 599 404 462
Average oil sales price (per Bbl):
United States..................................... $ 23.61 $ 26.38 $ 17.33
Canada............................................ 20.85 25.49 16.48
Weighted average.................................. 22.67 26.14 17.08
Net gas product (MMcf):
United States..................................... 4,498 3,850 4,421
Canada............................................ 5,376 4,519 4,660
------- ------- -------
Total........................................... 9,874 8,369 9,081
Average gas sales price (per Mcf):
United States..................................... $ 3.47 $ 4.08 $ 2.24
Canada............................................ 3.51 3.54 1.58
Weighted average.................................. 3.49 3.79 1.90
Gas equivalents produced (MMcfe):
United States..................................... 6,874 5,614 6,365
Canada............................................ 6,594 5,179 5,488
------- ------- -------
Total........................................... 13,468 10,793 11,853
Average sales price (per Mcfe):
United States..................................... $ 3.63 $ 4.18 $ 2.44
Canada............................................ 3.51 3.63 1.76
Weighted average.................................. 3.57 3.92 2.13
Production costs (per Mcfe):
United States..................................... $ 1.27 $ 1.04 $ 0.72
Canada............................................ 0.65 0.43 0.40
Weighted average.................................. 0.97 0.74 0.57
2
Marketing
PetroCorp's United States gas production is sold to a variety of pipelines,
marketing companies and utility end users at prices based on the spot market.
This gas is typically sold under short-term contracts ranging in length from
one month to one year. In Canada during 2001, nearly one-half of the Company's
gas was dedicated under long-term contracts to Pan-Alberta Gas Ltd. (Pan-
Alberta), a major Canadian gas aggregator and marketer. Under these contracts,
approximately 75% of the gas was resold into the United States, predominantly
to markets in the upper Midwest region. PetroCorp received a price, per Mcf,
from Pan-Alberta equal to Pan-Alberta's resale price less certain costs. Most
of the Company's remaining Canadian gas was sold to Engage Energy at spot
prices on either a daily or a monthly basis, except for a small portion sold
at fixed prices over a five-month period.
PetroCorp's domestic crude oil and condensate production is sold to a
variety of purchasers typically on a monthly contract basis at posted field
prices or NYMEX prices, as determined by major buyers. In particular areas,
where production volumes are significant or the location is desirable for a
particular purchaser, or both, the Company has successfully negotiated bonuses
over the purchaser's general field postings for its production.
During the year ended December 31, 2001, Engage Energy and Pan-Alberta
accounted for 32% and 22% 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.
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
3
gathering of natural gas (and operational and safety matters related thereto)
may be subject to regulation by state and local governments.
In the past, the federal government regulated the prices at which the
Company's produced oil and gas could be sold. Currently, "first sales" of
natural gas by producers and marketers, and all sales of crude oil, condensate
and natural gas liquids, can be made at uncontrolled market prices, but
Congress could reenact price controls at any time.
Within the past decade, the FERC has issued numerous orders and policy
statements designed to create a more competitive environment in the national
natural gas marketplace, including orders promoting "open-access"
transportation on natural gas pipelines subject to the FERC's NGA and NGPA
jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed
to restructure the interstate natural gas transportation and marketing system
and to promote competition within all phases of the natural gas industry.
Among other things, Order 636 required interstate pipelines to separate the
transportation of gas from the sale of gas, to change the manner in which
pipeline rates were designed and to implement other changes intended to
promote the growth of market centers. Subsequent FERC initiatives have
attempted to standardize interstate pipeline business practices and to allow
pipelines to implement market-based, negotiated and incentive rates. The
restructured services implemented by Order 636 and successor orders have now
been in effect for a number of winter heating seasons and have significantly
affected the manner in which natural gas (both domestic and foreign) is
transported and sold to consumers.
Order 636 has generally been upheld in judicial appeals to date. However,
FERC routinely evaluates whether its 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 change, and it is not possible to predict the effect, if any, of
future restructuring orders or policies on the Company's operations. 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 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
4
as the oil and gas industry in general. Also at the federal level, the U.S. Oil
Pollution Act requires owners and operators of facilities that could be the
source of an oil spill into "waters of the United States" (a term defined to
include rivers, creeks, wetlands and coastal waters) to demonstrate that they
have at least $35 million in financial resources to pay for the costs of
cleaning up an oil spill and compensating any parties damaged by an oil spill.
Such financial assurances may be increased to as much as $150 million if a
formal assessment indicates such an increase is warranted. These financial
responsibility requirements could have a significant adverse impact on small
oil and gas companies like PetroCorp. State initiatives to further regulate the
disposal of oil and gas wastes are also pending in certain states, and these
various initiatives could have a similar impact on the Company. The Company is
unable to predict the ongoing cost to it of complying with these laws and
regulations or the future impact of such regulations on its operation.
Management believes that the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance
with existing requirements will not have a material adverse impact on the
Company. A catastrophic discharge of hydrocarbons into the environment could,
to the extent such event is not insured, subject the Company to substantial
expense.
Canada
In Canada, the petroleum industry operates under federal, provincial and
municipal legislation and regulations governing taxes, land tenure, royalties,
production rates, environmental protection, exports and other matters. Prices
of oil and natural gas in Canada have been deregulated and are determined by
market conditions and negotiations between buyers and sellers, although oil
production volumes are regulated. Various matters relating to the
transportation and distribution of natural gas are the subject of hearings
before various regulatory tribunals. In addition, although the price of natural
gas exported from Canada is subject to negotiation between buyers and sellers,
the National Energy Board, which regulates exports of natural gas, requires
that natural gas export contracts meet certain criteria as a condition of
approving such contracts. These criteria, including price considerations, are
designed to demonstrate that the export is in the Canadian public interest.
Several provincial governments have introduced a number of programs to
encourage and assist the oil and natural gas industry, including incentive
payments, royalty holidays and royalty tax credits. Canadian governmental
regulations may have a material effect on the economic parameters for engaging
in oil and gas activities in Canada and may have a material effect on the
advisability of investments in Canadian oil and gas drilling activities.
Employees
At December 31, 2001, PetroCorp had no full-time employees. On January 1,
2002, Gary R. Christopher, President, and Richard L. Dunham, Executive Vice-
President, became direct employees of PetroCorp. Previously they had been
employees through the management agreement with Kaiser-Francis.
5
Item 2. Properties.
Principal Properties
The Company's proved oil and gas properties are relatively concentrated.
Approximately 82% of the PV-10 from the Company's proved reserves at December
31, 2001 was attributable to four 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, 2001, in accordance with the rules and
regulations of the Securities and Exchange Commission (SEC).
December 31, 2001
-------------------------------------
Estimated Proved
Reserves
----------------------
Oil Gas
Property/Area (MBbls) (MMcf) MMcfe PV-10
------------- ------- ------ ------- --------------
(in thousands)
Hanlan-Robb (Canada)................... 39 34,462 34,696 $ 36,539
Other Alberta (Canada)................. 2,376 24,129 38,385 34,552
Gulf Coast Area........................ 1,306 10,298 18,134 21,712
Mid-Continent Area..................... 1,365 13,186 21,376 16,750
----- ------ ------- --------
Subtotal............................. 5,086 82,075 112,591 109,553
----- ------ ------- --------
Others................................. 1,363 17,900 26,078 23,683
----- ------ ------- --------
Total................................ 6,449 99,975 138,669 $133,236
===== ====== ======= ========
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. The Company owns interests in eleven producing fields in this
area, covering 46,000 developed acres. PetroCorp has additional interests in
80,000 undeveloped acres in this area. The key field is the Hanlan Swan Hills
Gas Unit #1, with current gross production of 130 MMcf/D. PetroCorp's
ownership is part of a joint venture managed by the Company with institutional
investors that collectively own 21.7% of the field. PetroCorp's working
interest in this field is 35% of the joint venture, or 7.6%. Petro-Canada (not
an affiliate of PetroCorp) is the largest interest owner in the area and
operates the Hanlan-Robb area fields and the related gathering system and
processing plant. Other significant PetroCorp fields in this area include
Shaw/Basing, Minehead, Columbia, Red Cap, Lambert, Banshee and Medicine Lodge.
Other Alberta fields. PetroCorp, through existing interests and through the
2001 merger with Southern Mineral, has significant production in other core
areas throughout Alberta. This includes gas reserves in Pine Creek, Kaybob
South, McLeod and a Basal Colorado discovery in Alderson. Oil areas include
recent developments in Gift, along with Worsley and Hayter. In addition,
PetroCorp maintains minority ownership in large units, including Ghost Pine,
Mitsue and Pembina.
Mid-Continent Area. Includes the Southwest Oklahoma City Field located
within the metropolitan Oklahoma City area. PetroCorp operates 63 wells in a
waterflood unit targeting the Prue formation at 6,500 feet. Current unit
production is approximately 340 BOPD. The Company owns an 86.4% working
interest in the unit. The Company also owns a 4% working interest in the
adjacent Will Rogers Unit, operated by Marathon.
Other significant Mid-Continent properties include the Glick gas field in
south-central Kansas, the West Hunter Misener waterflood in Alfalfa County,
Oklahoma, and deep gas from the Cement field of Caddo County, Oklahoma.
Gulf Coast Area. Includes ownership in the East Riceville Field in
Vermillion Parish, Louisiana and the Scott Field in Lafayette Parish,
Louisiana. East Riceville is a two-well gas field producing 16 MMcf/D from a
Miogyp reservoir at approximately 17,000 feet. PetroCorp owns a 13.8% working
interest in this field, which is operated by Murphy Exploration and Production
Company. Through the Southern Mineral merger, PetroCorp
6
now has significant interest in the Exxon operated Big Escambia Creek field in
Alabama. PetroCorp also drilled a successful sidetrack in the Maynor Creek
field of Wayne County, Mississippi.
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 PetroCorp and reviewed by Huddleston & Co., Inc. (the Independent
Engineers). These reports were prepared in accordance with the rules and
regulations of the SEC and estimates of reserves were based upon production
histories and other geologic, economic, ownership and engineering data.
The following table sets forth summary information with respect to the
estimates of the Company's proved oil and gas reserves as of December 31,
2001. 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. The average prices used in determining future cash inflows for
natural gas and oil as of December 31, 2001, were $2.48 per Mcf and $19.79 per
barrel, respectively. These prices were based on the adjusted cash spot price
for natural gas and oil at December 31, 2001.
December 31, 2001
-------------------------
United
States Canada Total
------- -------- --------
Proved reserves:
Oil (MBbls)..................................... 3,931 2,518 6,449
Gas (MMcf)...................................... 41,384 58,591 99,975
Gas equivalents (MMcfe)......................... 64,970 73,699 138,669
Future net revenues ($000s)....................... $99,407 $122,894 $222,301
Present value of future net revenues ($000s)...... $59,571 $ 73,665 $133,236
Proved developed reserves:
Oil (MBbls)..................................... 3,350 2,242 5,592
Gas (MMcf)...................................... 38,806 50,876 89,682
Gas equivalents (MMcfe)......................... 58,906 64,328 123,234
Future net revenues ($000s)....................... $93,664 $110,893 $204,557
Present value of future net revenues ($000s)...... $57,881 $ 65,419 $123,300
7
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, estimates of future net revenues from
the Company's proved reserves and the present value thereof are made using oil
and gas 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 Note 15
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, 2001.
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, 2001.
Developed Undeveloped
Acres Acres(1)
-------------- --------------
Gross Net Gross Net
------- ------ ------- ------
United States:
Alabama...................................... 9,619 2,336 -- --
Colorado..................................... 10,186 7,958 -- --
Kansas....................................... 5,360 667 10 1
Louisiana.................................... 14,339 2,717 883 193
Mississippi.................................. 2,880 487 8,430 6,049
Oklahoma..................................... 39,969 9,950 11,325 4,325
Texas........................................ 49,353 12,031 42,211 11,334
Wyoming...................................... 5,655 774 5,109 480
Other........................................ 800 204 22,679 4,841
Canada:
Alberta...................................... 157,456 14,843 182,222 37,306
Other........................................ 12,425 2,824 16,737 5,990
------- ------ ------- ------
Total...................................... 308,042 54,791 289,606 70,519
======= ====== ======= ======
- --------
(1) Approximately 10% of net undeveloped acres are covered by leases that
expire during 2002, unless drilling or production otherwise extends lease
terms.
As of December 31, 2001, the Company had working interests in 1389 gross
(175 net) producing oil wells and 590 gross (53 net) producing gas wells. Of
these wells, 1126 gross (67 net) oil wells and 404 gross (19 net) gas wells
were in Canada, and the remainder of the oil and gas wells were in the United
States.
8
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 completed during
the years ended December 31, 2001, 2000 and 1999 is set forth below:
Year Ended December 31,
-----------------------------------------------
2001 2000 1999
-------------- -------------- --------------
Net Net Net
Working Working Working
Type of Well Gross Interest Gross Interest Gross Interest
------------ ----- -------- ----- -------- ----- --------
United States
Development:
Oil...................... 3 .1 4 .2 4 .2
Gas...................... 8 1.0 5 .3 1 .0(/1/)
Nonproductive............ 3 .2 1 .2 1 .2
--- --- --- --- --- ---
Total.................. 14 1.3 10 .7 6 .4
--- --- --- --- --- ---
Exploratory:
Oil...................... 1 .1 -- -- -- --
Gas...................... 3 .5 -- -- -- --
Nonproductive............ 2 .2 1 .0(/1/) 1 .2
--- --- --- --- --- ---
Total.................. 6 .8 1 .0 1 .2
--- --- --- --- --- ---
Canada:
Development:
Oil...................... 21 .8 1 1.0 1 1.0
Gas...................... 5 .9 6 1.1 2 .2
Nonproductive............ -- -- -- -- 2 .0(/1/)
--- --- --- --- --- ---
Total.................. 26 1.7 7 2.1 5 1.2
--- --- --- --- --- ---
Exploratory:
Oil...................... 1 .6 -- -- -- --
Gas...................... 2 .4 3 .4 4 .2
Nonproductive............ -- -- -- -- 3 .1
--- --- --- --- --- ---
Total.................. 3 1.0 3 .4 7 .3
--- --- --- --- --- ---
Total...................... 49 4.8 21 3.2 19 2.1
=== === === === === ===
- --------
(/1/The)Company has a net working interest less than 0.05% in these wells.
At December 31, 2001, the Company was not participating in the drilling of
any wells in either Canada or the United States.
Hanlan-Robb Natural Gas Processing Plant and Gas Gathering Systems
PetroCorp owns interests in a centrally located gas processing plant and in
a gas gathering system that connects all of the Company's currently producing
Hanlan-Robb fields to the Hanlan-Robb plant. Commissioned in 1983, the
estimated replacement value is approximately $175 ($C277) million. The
original design capacity of 300 MMcf/D has been expanded to 380 MMcf/D. Third-
party gas, for which processing fees are received, plus gas from additional
drilling in the area, has increased plant throughput to near capacity.
PetroCorp owns a 24.5% working interest in the plant and varying working
interests in the gathering systems, dehydration and compression facilities
that deliver gas to the plant.
9
Other Facilities
The Company leases, and subleases to others, approximately 10,000 square
feet in Houston, Texas where the Southern Mineral offices were located and
approximately 4,000 square feet in Calgary, Alberta where divisional offices
were previously located. The obligation under these leases will end in 2003
for the Houston lease and 2002 for the Calgary lease. Additionally, the
Company owns an 18,400 square-foot building and surface pads covering
approximately 42 acres related to its Southwest Oklahoma City Field operations
and a small gathering system in the Paradox Basin area of southwestern
Colorado.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Current and prospective stockholders should carefully consider the
following risk factors in evaluating an investment in PetroCorp. The
information discussed herein includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of
historical facts included herein regarding planned capital expenditures,
increases in oil and gas production, the number of anticipated wells to be
drilled after the date hereof, the Company's financial position, business
strategy and other plans and objectives for future operations, are forward-
looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, they do involve
certain assumptions, risks and uncertainties, and the Company can give no
assurance that such expectations will prove to have been correct. The
Company's actual results could differ materially from those anticipated in
these forward-looking statements as a result of certain factors, including
those set forth in the following risk factors.
All subsequent written and oral forward-looking statements attributable to
the Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
Volatile Nature of Oil and Gas Markets; Fluctuations in Prices
The Company's future financial condition and results of operations are
highly dependent on the demand and prices received for oil and gas production
and on the costs of acquiring, developing and producing reserves. Oil and gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the Company's control. These factors include political
conditions in the Middle East and elsewhere, domestic and foreign supply of
oil and gas, the level of consumer demand, weather conditions, domestic and
foreign government regulations and taxes, the price and availability of
alternative fuels and overall economic conditions. A decline in oil or gas
prices may adversely affect the Company's cash flow, liquidity and
profitability and may result in "ceiling test" write downs of the oil and gas
properties. Lower oil or gas prices also may reduce the amount of the
Company's oil and gas that can be produced economically.
Dependence on Acquiring and Finding Additional Reserves
The Company's prospects for future growth and profitability will depend
predominantly on its ability to replace present reserves through acquisitions
and exploratory drilling, as well as on its ability to successfully develop
additional reserves. There can be no assurance that the Company's acquisition
and exploration activities or planned development projects will result in
significant additional reserves or that the Company will have continuing
success at drilling economically productive wells.
Substantial Capital Requirements
The Company has made substantial capital expenditures in connection with
the acquisition, exploration and development of oil and gas properties. Future
cash flows and the availability of credit are subject to a number of
10
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,
the PV-10 values are generally based on prices and costs as of the date of the
estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by factors such as
the amount and timing of actual production, supply and demand for oil and gas,
curtailments or increases in consumption by natural gas purchasers and changes
in governmental regulations or taxation. The timing of actual future net cash
flows from proved reserves, and thus their actual present value, will be
affected by the timing of both the production and the incurrence of expenses in
connection with development and production of oil and gas properties. In
addition, the 10% discount factor (which is required by the SEC to be used to
calculate PV-10 for reporting purposes), is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company and its properties or the oil and gas
industry in general.
Exploration Risks
Exploratory drilling activities are subject to many risks, including the
risk that no commercially productive reservoirs will be encountered, and there
can be no assurance that new wells drilled by the 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.
11
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 have been an
important element of the Company's success, and the Company will continue to
seek acquisitions in the future. Even though the Company performs a review
(including a limited review of title and other records) of the major
properties it seeks to acquire that it believes is consistent with industry
practices, such reviews are inherently incomplete and it is generally not
feasible for the Company to review in-depth every property and all records.
Even an in-depth review may not reveal existing or potential problems or
permit the Company to become familiar enough with the properties to assess
fully their deficiencies and capabilities, and the Company often assumes
environmental and other liabilities in connection with acquired businesses and
properties.
Operating Risks
The Company's operations are subject to numerous risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as
oil spills, natural gas leaks, ruptures or discharges of toxic gases, the
occurrence of any of which could result in substantial losses to the Company
due to injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. The Company's operations may be materially
curtailed, delayed or canceled as a result of numerous factors, including the
presence of unanticipated pressure or irregularities in formations, accidents,
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. In accordance with
customary industry practice, the Company maintains insurance against some, but
not all, of the risks described above. There can be no assurance that the
levels of insurance maintained by the Company will be adequate to cover any
losses or liabilities.
Competitive Industry
The oil and gas industry is highly competitive. The Company competes for
corporate and property acquisitions and the exploration, development,
production, transportation and marketing of oil and gas, as well as
contracting for equipment and securing personnel, with major oil and gas
companies, other independent oil and gas concerns and individual producers and
operators. Many of these competitors have financial and other resources which
substantially exceed those available to the Company.
Risks That Might Arise from the Management Agreement
The Company has only two employees, and all of its technical and corporate
services are provided by Kaiser-Francis pursuant to a management agreement. As
a result, the Company does not have full control over its operations. Either
the Company or Kaiser-Francis may terminate the Kaiser-Francis management
agreement at any time upon six month's notice. If the agreement is terminated,
and if the Company is unable to engage third parties to perform these services
and have to replicate facilities, services or employees that the Company is
not using full time, or are not able to engage a third party at costs similar
to those charged by Kaiser-Francis, the Company's costs would increase. The
Company may not be able to find another contractor to provide substantially
similar services at the same rates or replicate such services without
incurring additional costs.
Kaiser Francis, PetroCorp's largest shareholder, and its subsidiaries
explore for and produce oil and gas in some of the same geographic areas in
which the Company operates. Kaiser-Francis is not required to pursue a
12
business strategy that will favor PetroCorp business opportunities over the
business opportunities of Kaiser-Francis, its affiliates, or any other
competitor of Petrocorp acquired by Kaiser-Francis. In fact, Kaiser-Francis may
have financial motives to favor itself.
In addition, because of the Company's management agreement with Kaiser-
Francis, PetroCorp, Kaiser-Francis and its affiliates share, and therefore will
compete for, the time and effort of Kaiser-Francis personnel who provide
services to the Company. Officers of Kaiser-Francis and its affiliates do not
and will not be required to spend any specified percentage or amount of their
time on the Company's business. Since these shared officers function as both
the Company's representatives and those of Kaiser-Francis and its affiliates,
conflicts of interest could arise between Kaiser-Francis and its affiliates, on
the one hand, and the Company and its shareholders, on the other.
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 and in some
circumstances creating retroactive liability. 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.
Hedging Activities
The Company utilizes energy swap arrangements and financial futures to
reduce sensitivity to oil and gas price volatility. If the Company's reserves
are not produced at the rates estimated by the Company due to inaccuracies in
the reserve estimation process, operational difficulties or regulatory
limitations, the Company will be required to satisfy obligations it may have
under fixed price sales or hedging contracts on potentially unfavorable terms
without the ability to hedge that risk through sales of comparable quantities
of its own production. Further, the terms under which the Company enters into
fixed price sales and hedging contracts are based on assumptions and estimates
of numerous factors such as cost of production and pipeline and other
transportation costs to delivery points. Substantial variations between the
assumptions and estimates used and actual results experienced could materially
adversely affect anticipated profit margins and PetroCorp's ability to manage
the risk associated with fluctuations in oil and gas prices.
In addition, fixed price sales and hedging contracts are subject to the risk
that the counter-party may prove unable or unwilling to perform its obligations
under these contracts. Any significant nonperformance could have a material
adverse financial effect on the Company.
Marketability of PetroCorp's Production
The marketability of PetroCorp's production depends in part upon the
availability, proximity and capacity of oil and gas gathering systems,
pipelines and processing facilities. Most of the Company's oil and gas will be
delivered through gathering systems and pipelines that are not owned by the
Company. Federal and state regulation of oil and gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's ability to
produce and market its oil and gas.
13
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.
On February 13, 2002, R.A. Mackie & Co., L.P., Millenco, L.P. and Wein
Securities Corp, as plaintiffs, filed a lawsuit against PetroCorp in New York
Supreme Court (Index No. 02-600589). In this action certain former holders of
warrants of Southern Mineral Corporation allege that the provisions made for
such warrants in connection with the merger of Southern Mineral Corporation
into PetroCorp Acquisition Corporation, a wholly-owned subsidiary of PetroCorp
Incorporated, were inadequate. The plaintiffs seek $5,000,000. Based on
consultation with outside legal counsel, the Company is of the opinion the
action is without merit.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
14
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
The Company's Common Stock is currently listed on the American Stock
Exchange (the "AMEX") and trades under the symbol PEX. The Company's Common
Stock has been listed with the AMEX since September 17, 1998. Prior to that
time, the Company's Common Stock had been listed on The Nasdaq Stock Market
since October 28, 1993. The following table presents the high and low closing
prices for the Company's Common Stock for each quarter during 2000 and 2001,
and for a portion of the Company's current quarter, as reported by the AMEX.
2000 2001 2002
------------------------------- ------------------------------- ------------
First
Quarter
First Second Third Fourth First Second Third Fourth (through
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter February 28)
------- ------- ------- ------- ------- ------- ------- ------- ------------
High.................... $6.75 $7.25 $9.88 $10.19 $10.63 $10.70 $9.88 $9.50 $9.50
Low..................... 5.25 5.50 7.00 8.63 9.62 9.37 8.60 8.70 8.70
As of February 28, 2002, the closing price for the Company's Common Stock
was $9.50 per share. As of February 28, 2002, there were approximately 2,500
holders of record of the Common Stock.
The Company has not declared or paid any cash dividends on its Common Stock
to date. The Board of Directors of the Company does not intend to declare cash
dividends on its Common Stock in the foreseeable future. The Company intends
instead to retain its earnings to support the growth of the Company's
business. Any future cash dividends would depend on future earnings, capital
requirements, the Company's financial condition and other factors deemed
relevant by the Company's Board of Directors. The terms of the Company's
credit facility prohibits the declaration or payment of any dividends.
15
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.
For the Year Ended December 31,
------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
Income Statement Data:
Revenues:
Oil and gas............... $ 48,058 $ 42,264 $ 25,162 $ 23,621 $ 33,502
Plant processing.......... 1,817 1,934 1,785 1,550 1,420
Other (B)................. 1,399 1,278 1,079 936 1,072
-------- -------- -------- -------- --------
51,274 45,476 28,026 26,107 35,994
-------- -------- -------- -------- --------
Expenses:
Production costs.......... 12,997 8,038 6,733 7,344 7,793
Depreciation, depletion
and amortization......... 16,944 9,471 9,906 16,568 17,065
Oil and gas property
valuation adjustment..... 15,400 -- -- 33,600 --
General and
administrative........... 2,259 1,529 4,311 4,482 4,846
Restructuring costs....... -- (445) 3,643 -- --
Other operating expenses
(B)...................... 1,485 1,212 1,181 1,165 1,267
-------- -------- -------- -------- --------
49,085 19,805 25,774 63,159 30,971
-------- -------- -------- -------- --------
Income (loss) from
operations................. 2,189 25,671 2,252 (37,052) 5,023
-------- -------- -------- -------- --------
Other income (expenses):
Investment income......... 143 584 585 1,151 558
Interest expense.......... (1,991) (3,381) (3,865) (3,622) (3,528)
Other income (expenses)... 1,425 295 (132) 14 (47)
-------- -------- -------- -------- --------
(423) (2,502) (3,412) (2,457) (3,017)
-------- -------- -------- -------- --------
Income (loss) before income
taxes...................... 1,766 23,169 (1,160) (39,509) 2,006
Income tax provision
(benefit);
Current................... 5,552 5,497 -- -- --
Deferred.................. (5,832) 4,612 (954) (15,114) 136
-------- -------- -------- -------- --------
(280) 10,109 (954) (15,114) 136
-------- -------- -------- -------- --------
Net income (loss) before
extraordinary item......... 2,046 13,060 (206) (24,395) 1,870
Extraordinary loss -
extinguishment of debt
(less applicable tax
benefit of $143) -- 242 -- -- --
-------- -------- -------- -------- --------
Net income (loss) $ 2,046 $ 12,818 $ (206) $(24,395) $ 1,870
-------- -------- -------- -------- --------
Net income (loss) per
share--basic (A)........... $ 0.19 $ 1.47 $ (0.02) $ (2.82) $ 0.22
======== ======== ======== ======== ========
Net income (loss) per
share--diluted (A)......... $ 0.18 $ 1.46 $ (0.02) $ (2.82) $ 0.22
======== ======== ======== ======== ========
Weighted average number of
common shares--basic....... 10,975 8,692 8,658 8,637 8,586
======== ======== ======== ======== ========
Weighted average number of
common shares--diluted..... 11,119 8,786 8,658 8,637 8,688
======== ======== ======== ======== ========
Balance Sheet Data (at
December 31):
Working Capital........... $ 4,031 $ 9,029 $ 3,642 $ 2,080 $ 2,638
Total assets.............. 165,355 117,319 105,395 103,992 130,924
Long-term debt............ 47,620 29,992 43,410 47,305 42,192
Shareholders' equity...... 91,915 54,277 42,363 40,744 66,557
- --------
(A) Basic and diluted net income per share before extraordinary loss for the
year ended December 31, 2000 were $1.50 and $1.49, respectively.
(B) As a result of the new accounting requirement to report transportation and
gathering costs as revenues and costs, rather than reducing revenues for
these costs, prior year revenues and costs have been increased by $903 in
2000 and $900 in 1999 through 1997.
16
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,
--------------------
2001 2000 1999
------ ------ ------
Production:
United States:
Oil (MBbls).............................................. 396 294 324
Gas (MMcf)............................................... 4,498 3,850 4,421
Gas equivalents (MMcfe).................................. 6,874 5,614 6,365
Canada:
Oil (MBbls).............................................. 203 110 138
Gas (MMcf)............................................... 5,376 4,519 4,660
Gas equivalents (MMcfe).................................. 6,594 5,179 5,488
Total:
Oil (MBbls).............................................. 599 404 462
Gas (MMcf)............................................... 9,874 8,369 9,081
Gas equivalents (MMcfe).................................. 13,468 10,793 11,853
Average sales prices:
United States:
Oil (per Bbl)............................................ $23.61 $26.38 $17.33
Gas (per Mcf)............................................ 3.47 4.08 2.24
Canada:
Oil (per Bbl)............................................ 20.85 25.49 16.48
Gas (per Mcf)............................................ 3.51 3.54 1.58
Weighted average:
Oil (per Bbl)............................................ 22.67 26.14 17.08
Gas (per Mcf)............................................ 3.49 3.79 1.90
Selected data per Mcfe:
Average sales price....................................... $ 3.57 $ 3.92 $ 2.13
Production costs.......................................... 0.97 0.74 0.57
General and administrative expenses....................... 0.17 0.14 0.36
Oil and gas depreciation, depletion and amortization...... 1.15 0.74 0.69
17
Critical Accounting Policies
Oil and Gas Properties--The Company accounts for oil and natural gas
exploration and development activities using the full cost method of
accounting. Under this method, all costs incurred in the acquisition,
exploration and development of oil and natural gas properties are capitalized.
At the end of each quarter, the net unamortized capitalized cost of oil and
natural gas properties is compared to a "ceiling". The ceiling is defined as
the sum of the present value (10 percent discount rate) of estimated future
net revenues from proved reserves, based on period-ending oil and natural gas
prices, plus the lower of cost or estimated fair value of unproved properties
included in the costs being amortized, less related deferred income taxes. If
the net capitalized costs of oil and natural gas properties exceed the
ceiling, the Company is subject to a ceiling test write-down to the extent of
such excess. A ceiling test write-down, also described as a property valuation
adjustment, is a non-cash charge to earnings. If required, it reduces earnings
and impacts stockholders' equity in the period of occurrence and results in
lower depreciation, depletion and amortization expense in future periods. Once
written down, oil and gas properties can not be adjusted upward due to
subsequent increase in reserve values.
The risk that PetroCorp will be required to write-down the carrying value
of oil and natural gas properties increases when oil and natural gas prices
are depressed or if there are substantial downward revisions in estimated
proved reserves. Application of these rules during periods of relatively low
oil or natural gas prices, even if temporary, increases the probability of a
ceiling test write-down. Based on oil and natural gas prices in effect on
December 31, 2001 of $19.84 per barrel and $2.70 per Mcf in the United States
and $19.73 per barrel and $2.32 per Mcf in Canada, the unamortized cost of
domestic oil and natural gas properties exceeded the ceiling of our proved oil
and natural gas reserves and a valuation adjustment of $15,400,000 was
recorded. Natural gas pricing has been fluctuating since year-end and any
significant declines below year-end prices used in the reserve evaluation may
result in an additional ceiling test write-down in subsequent quarters.
The value of the Company's oil and natural gas reserves is used to
determine the loan value under the Company's loan agreement. This value is
affected by both price changes and the measurement of reserve volumes. Oil and
natural gas reserves cannot be measured exactly. PetroCorp's estimate of oil
and natural gas reserves require extensive judgments of our reservoir
engineering data and are generally less precise than other estimates made in
connection with financial disclosures. Assigning monetary values to such
estimates does not reduce the subjectivity and changing nature of such reserve
estimates. The uncertainties inherent in the disclosure are compounded by
applying additional estimates of the rates and timing of production and the
costs that will be incurred in developing and producing the reserves.
PetroCorp utilizes Huddleston & Co, Inc., independent petroleum consultants,
to review the Company's reserves as prepared by PetroCorp's reservoir
engineer.
Income Taxes. As part of the process of preparing the consolidated
financial statements, PetroCorp is required to estimate the income taxes in
each of the jurisdictions in which PetroCorp operates. This process involves
estimating the actual current tax exposure together with assessing temporary
differences resulting from differing treatment of items, such as depreciation,
amortization and certain accrued liabilities, for tax and accounting purposes.
These differences and the net operating loss carryforwards result in deferred
tax assets and liabilities, which are included within PetroCorp's consolidated
balance sheet. PetroCorp must then assess the likelihood that the deferred tax
assets will be recovered from future taxable income and to the extent the
Company believes that recovery is not likely, PetroCorp must establish a
valuation allowance. To the extent PetroCorp establishes a valuation allowance
or increases or decreases this allowance in a period, the Company must include
an expense or reduction of expense within the tax provisions in the
consolidated statement of operations.
Deferred income tax assets and liabilities are recorded whenever underlying
transactions result in temporary differences between financial accounting and
what will be included in the Company's tax returns. Permanent differences are
taken into account in determining the Company's effective tax rate. The intent
of recording deferred taxes is to cause the Company's financial income tax
expense to be consistent with the underlying tax rates. To the extent deferred
tax estimation doesn't correctly predict how transactions are later reflected
in tax returns, adjustments will be required.
18
Examples of temporary differences include the tax expensing of intangible
drilling costs while such costs are capitalized as part of the full cost pool
for financial purposes. Another example is accelerated depreciation and
depletion for tax purposes compared to financial depreciation and depletion.
Both examples cause an excess basis in oil and gas properties for financial
purposes as compared to tax basis, which results in a deferred liability.
PetroCorp's other significant temporary differences are the net operating
loss carryforwards (NOLs), which are tax losses available to offset future
taxable income of the Company. They result in deferred tax assets. NOLs are an
asset for the Company only to the extent it is likely PetroCorp will have
future taxable income to offset against the NOLs. Although PetroCorp can make
some tax elections to its benefit, a period of sustained lower than normal oil
and gas prices could result in the inability of the Company to utilize NOLs
before they expire, resulting in the recording of a valuation allowance or, if
they expire without being utilized, resulting in a write-off of the deferred
tax asset.
The Company's significant accounting policies are described in Note 1 to
the Consolidated Financial Statements.
Restructuring
As part of a restructuring plan, on August 3, 1999, PetroCorp's Board of
Directors entered into a Management Agreement with its largest shareholder,
Kaiser-Francis, under which Kaiser-Francis provides management, technical, and
administrative support services for all PetroCorp operations in the United
States and Canada.
Under the terms of the Management Agreement, as amended, Kaiser-Francis is
compensated through a service fee equal to administrative and overhead fees
charged under applicable operating agreements plus fixed fees of no more than
$50 per well per month for non-operated properties. Fees and cost
reimbursements for 2001, 2000, and 1999 respectively, were $3,064,000,
$2,076,000 and $1,419,000 ($2,176,000, $1,419,000 and $218,000 for
administration fees).
The Company recorded restructuring costs of $3,643,000 during 1999.
Included in the costs were employee termination costs of $2,371,000, $807,000
in nonrefundable office lease discontinuance, $363,000 in investment banking
and legal costs, and $102,000 in other related costs. As of December 31, 2000,
$70,000 of the remaining restructuring costs were included in accrued
liabilities.
As a result of the restructuring, fifty-two employees were terminated in
1999 with one employee terminated in 2000. Several employees elected to defer
receipt of their termination benefits until 2000. The Houston, Oklahoma City
and Calgary offices were closed, but the Company was still liable under the
lease agreements. In the second quarter of 2000, the Company was able to find
a replacement lessee for some of the idle office space earlier than
anticipated. The following table shows the change in accrued restructuring
costs during 2001(in thousands):
Expenditures
Balance at charged Balance at
December 31, against Changes in December 31,
2000 accrual estimates 2001
------------ ------------ ---------- ------------
Office lease discontinuance
and other related costs.... 70 70 -- --
--- --- --- ---
$70 $70 $-- $--
=== === === ===
19
Results of Operations
2001 Compared to 2000
Overview. The Company recorded net income of $2,046,000 or $0.19 per share
in 2001, compared to net income of $12,818,000, or $1.47 per share, for the
corresponding period of 2000. This decrease results from lower oil and gas
prices, increased depreciation, depletion, and amortization expenses and an
oil and gas property valuation adjustment.
Revenues. Total revenues increased 13% to $51.3 million in 2001 compared to
$45.5 million in 2000. Oil production increased 48% to 599 MBbls from 404
MBbls. Natural gas production increased 18% to 9,874 MMcf from 8,369 MMcf,
resulting in overall production increasing 25% to 13,468 MMcfe from 10,793
MMcfe. Production increases are primarily due to the merger with Southern
Mineral in June 2001.
The Company's average U.S. natural gas price decreased 15% to $3.47 per Mcf
in 2001 from $4.08 per Mcf in 2000, while the average Canadian natural gas
price decreased less than 1% to $3.51 from $3.54. The Company's composite
average oil price decreased 13% to $22.67 per barrel in 2001 from $26.14 per
barrel in 2000. Primarily as a result of increased volumes due to the merger
with Southern Mineral, oil and gas revenues increased 14% to $48.1 million in
2001 from $42.3 million in 2000. Plant processing revenues decreased 5% to
$1.8 million from $1.9 million as a result of less third party processing in
the Canadian Hanlan-Robb gas processing plant.
Production Costs. Production costs increased 63% to $13.0 million in 2001
compared to $8.0 million in 2000 as a result of the acquisition of Southern
Mineral and workover operations for repairs and production enhancements.
Production costs per Mcfe were $0.97 for 2001 and $0.74 for 2000.
Approximately $0.21 per Mcfe of increased costs are due to increased workover
operations.
Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 78% to
$16.9 million in 2001 from $9.5 million in 2000. The increase in the oil and
gas DD&A rate per Mcfe to $1.15 in 2001 from $0.74 in 2000 reflects the impact
of Southern Mineral properties added through the merger in June 2001 and the
lower year-end reserves amounts due to lower prices.
Oil and Gas Property Valuation Adjustment. At December 31, 2001, as a
result of low oil and gas prices, the Company's net capitalized costs for its
U.S. oil and gas properties exceeded the ceiling, resulting in a non-cash
valuation adjustment of $15.4 million.
General and Administrative Expenses. General and administrative expenses
increased 53% to $2.3 million in 2001 from $1.5 million in 2000 due to office
close down costs and higher management fees, both due to the impact of the
merger with Southern Mineral.
Investment Income. Investment income decreased 76% to $143,000 in 2001 from
$584,000 in 2000 due to excess cash being used to pay down debt.
Interest Expense. Interest expense decreased 41% to $2.0 million in 2001
from $3.4 million in 2000, primarily due to decreases in interest rates.
Income Taxes. The Company recorded a $0.3 million income tax benefit on
pre-tax income of $1.8 million compared to an income tax expense of $10.1
million on pre-tax income of $23.2 million with an effective tax rate of 44%
in 2000. During 2001, the Company recorded an income tax provision for its
Canadian operations with an effective tax rate of 37% and a tax benefit for
its U.S. operations of $4.6 million due to the U.S. operating loss and a
change in the estimated amount of depletion carryforwards available to reduce
future taxable income. Effective tax rates differing from statutory rates are
primarily due to adjustments upon resolution of audits by Canadian tax
authorities and statutory depletion in the United States.
20
2000 Compared to 1999
Overview. The Company recorded net income of $12,818,000 or $1.47 per share
in 2000, compared to a loss of $206,000, or $0.02 per share, for the
corresponding period of 1999. This improvement results from higher oil and gas
prices and lower general and administrative, restructuring costs and
depreciation, depletion and amortization expenses.
Revenues. Total revenues increased 63% to $45.5 million in 2000 compared to
$28.0 million in 1999. Oil production decreased 13% to 404 MBbls from 462
MBbls. Natural gas production decreased 8% to 8,369 MMcf from 9,081 MMcf,
resulting in overall production decreasing 9% to 10,793 MMcfe from 11,853
MMcfe. Production decreases are due to normal production declines.
The Company's average U.S. natural gas price increased 82% to $4.08 per Mcf
in 2000 from $2.24 per Mcf in 1999, while the average Canadian natural gas
price increased 124% to $3.54 from $1.58. The Company's composite average oil
price increased 53% to $26.14 per barrel in 2000 from $17.08 per barrel in
1999. Primarily as a result of price increases, oil and gas revenues increased
68% to $42.3 million in 2000 from $25.2 million in 1999. Plant processing
revenues increased 8% to $1.9 million from $1.8 million primarily as a result
of new third party processing in the Canadian Hanlan-Robb gas processing
plant.
Production Costs. Production costs increased 19% to $8.0 million in 2000
compared to $6.7 million in 1999 as a result of workover operations for
repairs and production enhancements and production tax increases related to
higher commodity prices. Production costs per Mcfe were $0.74 for 2000 and
$0.57 for 1999. Approximately $0.18 per Mcfe of increased costs are due to
workover operations and increased production taxes.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 4% to
$9.5 million in 2000 from $9.9 million in 1999. The increase in the oil and
gas DD&A rate per Mcfe to $0.74 in 2000 from $0.69 in 1999 reflects the impact
of previously unevaluated properties evaluated in 2000 and moved into the full
cost pool.
General and Administrative Expenses. General and administrative expenses
decreased 65% to $1.5 million in 2000 from $4.3 million in 1999 as a result of
the Company's restructuring efforts and the Management Agreement with Kaiser-
Francis.
Investment Income. Investment income decreased less than 1% to $584,000 in
2000 from $585,000 in 1999.
Interest Expense. Interest expense decreased 13% to $3.4 million in 2000
from $3.9 million in 1999, reflecting the impact of reduced debt levels,
partially offset by an increase in interest rates.
Income Taxes. The Company recorded a $10.1 million income tax expense on
pre-tax income of $23.2 million with an effective tax rate of 44% in 2000
compared to an income tax benefit of $954,000 on a pre-tax loss of $1.2
million with an effective tax rate of 82% in 1999. During 2000, the Company
recorded an income tax provision for its Canadian operations with an effective
tax rate of 47% and a tax provision for its U.S. operations with an effective
tax rate of 39%, resulting in an overall effective tax rate of 44%. Effective
tax rates in excess of statutory rates are primarily due to adjustments of
approximately $1.2 million resulting from audits by Canadian tax authorities.
Liquidity and Capital Resources
As of December 31, 2001, the Company had working capital of $4.0 million as
compared to $9.0 million at December 31, 2000. Cash provided by operating
activities was $13.1 million, $33.2 million and $10.6 million in 2001, 2000
and 1999, respectively.
The Company's total capital expenditures were $93.8 million ($38.5 million
cash), $7.2 million and $3.3 million for 2001, 2000 and 1999, respectively. In
2001, the Company spent $17.2 million related to the exploration and
development and $76.3 million ($21.0 million of cash expenditures) related to
the acquisition of
21
Southern Mineral. During 2000, the Company spent $6.9 million related to
exploration and development. In 1999, the Company spent $3.1 million related
to exploration and development.
In June 1997, the Company entered into a $50 million five-year revolving
credit agreement with the Toronto-Dominion Bank, the agent, and the Bank of
Nova Scotia. The facility was amended in June 1998 to extend the initial five-
year term an additional year to July 1, 2003 with quarterly borrowing base
amortization beginning September 30, 2001.
In July 2000, the Company entered into a new $75 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The term of the facility is through April 30, 2003 and the
initial borrowing base was set at $58 million. Borrowings can be funded by
either Eurodollar loans or Base Rate loans. The interest rate on the
borrowings is equal to an interest rate spread plus either the Eurodollar rate
or the Base Rate. The interest spread is determined from a sliding scale based
on the Company's borrowing base percentage utilization in effect from time to
time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25
on Base Rate loans. At December 31, 2001, the Company had a total of
$47,300,000 outstanding under the revolver and $10,700,000 available based on
the current borrowing base, as defined, subject to certain limitations. In
2001, the weighted average interest rate under this facility was approximately
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 (Nonrecourse Notes Payable) with similar
financial terms. At December 31, 2001, the nonrecourse long-term notes payable
balance was $1,659,000 million, of which $1,327,000 was classified as
"current."
The Company has historically funded its capital expenditures, which are
discretionary, and working capital requirements with its cash flow from
operations, debt and equity capital and participation by institutional
investors. If the Company increases its capital expenditure level in the
future or operating cash flow is not as expected, capital expenditures may
require additional funding, obtained through borrowings from commercial banks
and other institutional sources or by public or private offerings of equity or
debt securities.
Merger with Southern Mineral
As indicated in Note 4 to the financial statements and part I, Item 1,
"Acquisition, Exploration and Development Activity", PetroCorp completed a
merger with Southern Mineral Corporation in June 2001. Funds needed to
complete this transaction were provided by cash on hand and borrowings under
existing lines of credit.
Common Stock Repurchases
On September 14, 2001, the Company announced that the Board of Directors
authorized the purchase of up to 1,000,000 shares of the Company's common
stock. Through December 31, 2001, 264,607 shares have been purchased at a cost
of $2,350,000.
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued FAS
No. 141 and 142. FAS No. 141, Business Combinations, requires the purchase
method of accounting be used for all business combinations initiated after
June 30, 2001. FAS No. 142, Goodwill and Other Intangible Assets, changes the
accounting for goodwill from an amortization method to an impairment-only
approach and is effective January, 2002. The Company believes that adoption of
these new standards will not have an effect on its results of operations or
its financial position. In June 2001, the FASB issued FAS No. 143, Accounting
for Asset Retirement Obligations, and in August 2001, FAS No. 144, Accounting
for Impairment or Disposal of Long-Lived Assets. Management is currently
evaluating the impact of FAS 143 and 144 on financial position and results of
operations.
22
Item 7A. Quantitative and Qualitative Disclosure about Market Risk.
The Company's primary sources of market risk are from fluctuations in
commodity prices, interest rates and exchange rates.
Commodity Price Risk
The Company produces and sells natural gas, crude oil, condensate, natural
gas liquids and sulfur. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response
to changing market forces. The Company utilizes hedging transactions to manage
its exposure to price fluctuations on its sales of oil and natural gas. In
2001, as part of the Southern Mineral merger, the Company assumed crude oil
and natural gas costless collars. The impact of these hedging transactions on
2001 financial results was an increase in revenues of $270,000. The estimated
fair value at December 31, 2001 of the crude oil and natural gas collars was
an asset of $644,000. Oil and gas hedges outstanding at December 31, 2001
were:
Oil Hedges
U.S. $
NYMEX WTI
Period Total Bbl Monthly Bbl Floor Cap
United States and Canada
Jan-02-Sep-02 158,500 17,611 $22.00 $25.60 to $27.00
Gas Hedges
U.S. $
Houston Ship channel
Period Total MMbtu Monthly MMBtu Floor Cap
United States and Canada
Jan-02-Mar-02 222,000 74,000 $2.75 $4.85
Apr-02-Oct-02 466,000 66,571 $2.75 $3.80
CND $ Alberta
Spot - AECO
Period Total Gigajoules Monthly Gigajoules Floor Cap
Canada
Jan-02-Sep-02 450,000 50,000 $4.05 $6.15
23
Interest Rate Risk
Total debt at December 31, 2001, included no fixed-rate debt. The Company
has elected to use only variable rate financing, therefore the Company has
limited control over interest rate changes, which may adversely affect the
Company's results of operations and cash flows. See Note 6 to the Consolidated
Financial Statements for information regarding future maturities of the
Company's debt.
As described in Note 7 of the Consolidated Financial Statements of the
Company, an interest rate swap position was assumed as part of the merger with
Southern Mineral. Under the swap, the Company receives a floating rate of the
Canadian prime rate and pays a fixed rate of 5.96% on a notational amount of
Canadian $15 million. The estimated fair value of the swap at December 31,
2001 is a liability of $338,000.
Foreign Currency Exchange Rate Risk
The Company conducts a significant portion of its business in the Canadian
dollar and is therefore subject to foreign currency exchange rate risk on cash
flows related to sales, expenses, financing and investing transactions.
Item 8. Financial Statements and Supplementary Data.
The information required by this item appears on pages 32 through 60 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, 2001 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).
24
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...................................... 31
Consolidated Balance Sheets as of December 31, 2001 and December 31,
2000.................................................................. 32
Consolidated Statements of Operations for the Years Ended December 31,
2001, 2000 and 1999................................................... 33
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 2001, 2000 and 1999...................................... 34
Consolidated Statements of Cash Flows for the Years Ended December 31,
2001, 2000 and 1999................................................... 35
Notes to Consolidated Financial Statements............................. 37
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 (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 (Simplification Agreement).
Incorporated by reference to Exhibit 2.2 to the Registration Statement.
3.1* Amended and Restated Articles of Incorporation of PetroCorp Incorporated.
Incorporated by reference to Exhibit 3.2 to the Registration Statement.
3.2* Amended and Restated Bylaws of PetroCorp Incorporated. Incorporated by
reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 1996.
3.3* Statement of Designations, Preferences, Limitations and Relative Rights
of Its Series A Junior Participating Preferred Stock. Incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K, dated November 20,
1998.
4.1* Rights Agreement dated as of November 12, 1998, between PetroCorp
Incorporated and First Union National Bank, as Rights Agent. Incorporated
by reference to Exhibit 4.1 to the Company's Form 8-K, dated November 20,
1998.
4.2* Form of Right Certificate. Incorporated by reference to Exhibit 4.2 to
the Company's Form 8-K, dated November 20, 1998.
4.3* Specimen certificate for shares of Common Stock. Incorporated by
reference to Exhibit 4.1 to the Registration Statement.
25
4.4* Note Purchase Agreement, dated July 29, 1993, among PetroCorp
Incorporated, United States Fidelity and Guaranty Company, Connecticut
General Life Insurance Company, Indiana Insurance Company, Security
Life of Denver Insurance Company, Southland Life Insurance Company,
Life Insurance Company of Georgia and Life Insurance Company of North
America. Incorporated by reference to Exhibit 4.2 to the Registration
Statement.
9.1* Voting Agreement, dated January 18, 1994, by and among USF&G
Corporation, Park Avenue Exploration Corporation, United States
Fidelity and Guaranty Company, CIGNA Corporation, L.S. Holding Company,
American Oil & Gas Investors, AmGO II, First Reserve Fund V, Limited
Partnership, First Reserve Fund V-2, Limited Partnership, First Reserve
Fund VI, Limited Partnership and First Reserve Corporation.
Incorporated by reference to Exhibit 9.2 to the Form 8-K.
10.1* Amended and Restated 1992 PetroCorp Stock Option Plan. Incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-
Q for the quarterly period ended September 30, 1996.
10.2* Hanlan-Robb Area Agreement of Purchase and Sale, effective August 1,
1991, between Gulf Canada Resources Limited and Petro-Canada and PCC
Energy Inc. Incorporated by reference to Exhibit 10.3 to the
Registration Statement.
10.3* Registration Rights Agreement, dated August 24, 1993, between L.S.
Holding Company (assigned to Kaiser-Francis Oil Company) and PetroCorp
Incorporated. Incorporated by reference to Exhibit 10.5 to the
Registration Statement.
10.4* Registration Rights Agreement, dated August 24, 1993, between Park
Avenue Exploration Corporation and PetroCorp Incorporated. Incorporated
by reference to Exhibit 10.6 to the Registration Statement.
10.5* Registration Rights Agreement, dated January 18, 1994, between
PetroCorp Incorporated and American Oil & Gas Investors, AmGO II, First
Reserve Fund V, Limited Partnership, First Reserve Fund V-2, Limited
Partnership, First Reserve Fund VI, Limited Partnership and First
Reserve Corporation (assigned to Kaiser-Francis Oil Company).
Incorporated by reference to Exhibit 10.1 to the Form 8-K.
10.6* Piggyback Registration Rights Agreement, dated October 27, 1993,
between Lealon L. Sargent and PetroCorp Incorporated. Incorporated by
reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993. This is a management
contract or compensatory plan or arrangement required to be filed as an
exhibit.
10.7* Separation Benefits Agreement, dated September 27, 1993, between Lealon
L. Sargent and PetroCorp Incorporated. Incorporated by reference to
Exhibit 10.8 to the Registration Statement. This is a management
contract or compensatory plan or arrangement required to be filed as an
exhibit.
10.8* Executive Management Annual Incentive Compensation Plan, effective
January 1, 1994. Incorporated by reference to Exhibit 10.8 to the
Company's Annual Report on Form 10-K for the fiscal year ended December
31, 1994 (1994 Form 10-K). This is a management contract or
compensatory plan or arrangement required to be filed as an exhibit.
10.9* Share Purchase Agreement, dated December 13, 1996, between 702056
Alberta Ltd. and shareholders of Millarville Oil & Gas Ltd.
Incorporated by reference to Exhibit 2 to the Company's Current Report
on Form 8-K, dated December 23, 1996.
10.10* Agreement for Purchase and Sale, dated June 5, 1997, between PetroCorp
Incorporated and Great River Oil and Gas Corporation. Incorporated by
reference to Exhibit 2.1 to the Company's Current Report on Form 8-K
dated July 1, 1997.
10.11* First Amendment to Agreement for Purchase and Sale, dated June 30,
1997, between PetroCorp Incorporated and Great River Oil and Gas
Corporation. Incorporated by reference to Exhibit 2.2 to the Company's
Current Report on Form 8-K dated July 1, 1997.
26
10.12* Credit Agreement, dated June 26, 1997, among PetroCorp Incorporated,
PCC Energy Limited, PCC Energy Corp, and Toronto-Dominion (Texas), Inc.
and Toronto-Dominion Bank. Incorporated by reference to Exhibit 10 to
the Company's current report on Form 8-K dated July 1, 1997.
10.13* 1997 Non-Employee Director Stock Option Plan. Incorporated by reference
to Appendix A to the Company's Proxy Statement for the Annual Meeting
of Shareholders held on May 16, 1997.
10.14* Management Agreement, dated August 3, 1999, between PetroCorp
Incorporated and Kaiser-Francis Oil Company. Incorporated by reference
to Annex A of the Company's Proxy Statement dated September 30, 1999.
10.15* Credit Agreement dated July 21, 2000 among PetroCorp Incorporated, PC
Energy Limited, PCC Corp., Toronto Dominion (Texas), Inc., The Toronto-
Dominion Bank, TD Securities (USA), Inc. and various lenders signature
thereto. Incorporated by reference to Exhibit 10.2 of the Company's
Quarterly report on Form 10-Q dated August 11, 2000.
10.16* PetroCorp Incorporated 2000 Stock Option Plan. Incorporated by
reference to exhibit 4.0 of the company's registration of such plan on
form S-8 filed on December 12, 2000.
10.17* Southern Mineral Corporation 1995 Non-employee Director Compensation
Plan (incorporated by reference to exhibit (k) to the Southern
Mineral's annual report on Form 10-k dated December 31, 1994
(Commission File No. No 0-8043)).
10.18* Southern Mineral 1996 Stock Option Plan (incorporated by reference to
Exhibit 10.10 to Southern Mineral's Form 10-KSB dated December 31, 1995
(Commission File No. 0-8043)).
10.19* Southern Mineral 1997 Stock Option Plan (incorporated by reference to
Southern Mineral's Form S-8, filed April 28, 1998, Registration No.
333-512 (Commission file No. 333-420450)).
10.20* Southern Mineral 1997 Non-employee Director Compensation Plan
(incorporated by reference to Southern Mineral's Form S-8, filed April
28, registration No. 333-512 (Commission file No. 333-26001)).
10.21* Southern Mineral Stock Option Agreement made as of December 31, 1994
between Southern Mineral Corporation and Steven H. Mikel (incorporated
by reference to Exhibit (h) to the Company's annual report on form 10-K
for year ended December 31, 1994 (commission File NO. 0-8043)).
10.22 Employment Agreement, dated December 28, 2001, between PetroCorp
Incorporated and Gary R. Christopher.
10.23 Employment Agreement, dated December 28, 2001, between PetroCorp
Incorporated and Richard L. Dunham.
21 List of material subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Huddleston & Co., Inc.
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
None.
27
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
PetroCorp Incorporated
(Registrant)
/s/ Gary R. Christopher
By: _________________________________
Gary R. Christopher
President and Chief Executive
Officer
(Principal Executive Officer)
Date: March 26, 2002
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/ Gary R. Christopher President, Chief Executive March 26, 2002
______________________________________ Officer (Principal
Gary R. Christopher Executive Officer) and
Director
/s/ Steven R. Berlin Vice President--Finance, March 26, 2002
______________________________________ Secretary & Treasurer
Steven R. Berlin (Principal Financial
Officer and Principal
Accounting Officer) and
Director
/s/ Steven E. Amos Controller March 26, 2002
______________________________________
Steven E. Amos
/s/ Lealon L. Sargent Chairman of the Board of March 26, 2002
______________________________________ Directors
Lealon L. Sargent
/s/ Thomas N. Amonett Director March 26, 2002
______________________________________
Thomas N. Amonett
/s/ Paul J. Coughlin Director March 26, 2002
______________________________________
Paul J. Coughlin
/s/ Mark W. Files Director March 26, 2002
______________________________________
Mark W. Files
28
Signature Title Date
--------- ----- ----
/s/ Thomas R. Fuller Director March 26, 2002
______________________________________
Thomas R. Fuller
/s/ W. Neil McBean Director March 26, 2002
______________________________________
W. Neil McBean
/s/ Robert C. Thomas Director March 26, 2002
______________________________________
Robert C. Thomas
29
EXHIBIT INDEX
No. Item
21 -- List of material subsidiaries
23.1 -- Consent of PricewaterhouseCoopers LLP
23.2 -- Consent of Huddleston & Co., Inc.
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
PetroCorp Incorporated
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
PetroCorp Incorporated and its subsidiaries (the "Company") at December 31,
2001 and 2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States of America.
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 financial statements in
accordance with auditing standards generally accepted in the United States of
America, 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 our opinion.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 15, 2002
31
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEETS
December 31, 2001 and 2000
(in thousands, except share amounts)
2001 2000
--------- --------
ASSETS
Current assets:
Cash and cash equivalents............................... $ 1,265 $ 21,946
Accounts receivable, net................................ 13,267 13,332
Other current assets.................................... 1,411 609
--------- --------
Total current assets.................................. 15,943 35,887
--------- --------
Property, plant and equipment:
Oil and gas properties, at cost, full cost method, net
of accumulated depreciation, depletion, amortization
and impairment......................................... 126,925 68,432
Other, net.............................................. 1,527 2,504
--------- --------
128,452 70,936
--------- --------
Deferred income taxes..................................... 18,261 10,254
Other assets, net......................................... 2,699 242
--------- --------
Total assets.......................................... $ 165,355 $117,319
========= ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable........................................ $ 6,708 $ 17,732
Accrued liabilities..................................... 3,877 2,488
Income tax payable...................................... -- 5,444
Current portion of long-term debt....................... 1,327 1,194
--------- --------
Total current liabilities............................. 11,912 26,858
--------- --------
Long-term debt............................................ 47,620 29,992
--------- --------
Deferred income taxes..................................... 13,908 6,192
--------- --------
Commitments and contingencies (Note 13)
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,
(12,556,109 shares and 8,703,719 shares outstanding
at December 31, 2001 and 2000, respectively)........... 128 87
Additional paid-in capital.............................. 111,114 71,614
Accumulated deficit..................................... (9,666) (11,712)
Accumulated other comprehensive loss.................... (7,311) (5,712)
Treasury stock, at cost (264,607 shares)................ (2,350) --
--------- --------
Total shareholders' equity............................. 91,915 54,277
--------- --------
Total liabilities and shareholders' equity............ $ 165,355 $117,319
========= ========
The accompanying notes are an integral part of these financial statements.
32
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2001, 2000 and 1999
(in thousands, except share amounts)
2001 2000 1999
------- ------- -------
Revenues:
Oil and gas....................................... $48,058 $42,264 $25,162
Plant processing.................................. 1,817 1,934 1,785
Other............................................. 1,399 1,278 1,079
------- ------- -------
51,274 45,476 28,026
------- ------- -------
Expenses:
Production costs.................................. 12,997 8,038 6,733
Depreciation, depletion and amortization.......... 16,944 9,471 9,906
Oil and gas property valuation adjustment......... 15,400 -- --
General and administrative........................ 2,259 1,529 4,311
Restructuring costs............................... -- (445) 3,643
Other operating expenses.......................... 1,485 1,212 1,181
------- ------- -------
49,085 19,805 25,774
------- ------- -------
Income from operations.............................. 2,189 25,671 2,252
------- ------- -------
Other income (expenses):
Investment income................................. 143 584 585
Interest expense.................................. (1,991) (3,381) (3,865)
Other income (expenses)........................... 1,425 295 (132)
------- ------- -------
(423) (2,502) (3,412)
------- ------- -------
Income (loss) before income taxes................... 1,766 23,169 (1,160)
------- ------- -------
Income tax provision (benefit):
Current........................................... 5,552 5,497 --
Deferred.......................................... (5,832) 4,612 (954)
------- ------- -------
(280) 10,109 (954)
------- ------- -------
Net income (loss) before extraordinary item......... 2,046 13,060 (206)
Extraordinary loss--extinguishment of debt (less
applicable tax benefit of $143).................... -- 242 --
------- ------- -------
Net income (loss)................................... $ 2,046 $12,818 $ (206)
======= ======= =======
Net income (loss) per common share--basic:
Income (loss) before extraordinary item........... $ 0.19 $ 1.50 $ (0.02)
Extraordinary item................................ -- (0.03) --
------- ------- -------
Net income (loss)................................. $ 0.19 $ 1.47 $ (0.02)
======= ======= =======
Net income (loss) per common share--diluted:
Income (loss) before extraordinary item........... $ 0.18 $ 1.49 $ (0.02)
Extraordinary item................................ -- (0.03) --
------- ------- -------
Net income (loss)................................. $ 0.18 $ 1.46 $ (0.02)
======= ======= =======
Weighted average number of common shares--basic..... 10,975 8,692 8,658
======= ======= =======
Weighted average number of common shares--diluted... 11,119 8,786 8,658
======= ======= =======
The accompanying notes are an integral part of these financial statements.
33
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
Accumulated
Common Stock Additional other
-------------- paid-in Accumulated comprehensive Treasury
Shares Amount capital deficit loss stock Total
------ ------ ---------- ----------- ------------- -------- -------
Balance, December 31,
1998................... 8,656 87 71,245 (24,324) (6,264) -- $40,744
Net loss............... -- -- -- (206) -- -- (206)
Exercise of stock
options............... 27 -- 135 -- -- -- 135
Other comprehensive
income................ -- -- -- -- 1,690 -- 1,690
------ ---- -------- ------- ------- ------- -------
Balance, December 31,
1999................... 8,683 87 71,380 (24,530) (4,574) -- 42,363
Net income............. -- -- -- 12,818 -- -- 12,818
Exercise of stock
options............... 21 -- 234 -- -- -- 234
Other comprehensive
loss.................. -- -- -- -- (1,138) -- (1,138)
------ ---- -------- ------- ------- ------- -------
Balance, December 31,
2000................... 8,704 87 71,614 (11,712) (5,712) -- 54,277
Net income............. -- -- -- 2,046 -- -- 2,046
Shares issued--merger.. 4,000 40 38,578 -- -- -- 38,618
Exercise of stock
options............... 117 1 922 -- -- -- 923
Other comprehensive
loss.................. -- -- -- -- (1,599) -- (1,599)
Treasury stock......... (265) -- -- -- -- (2,350) (2,350)
------ ---- -------- ------- ------- ------- -------
Balance, December 31,
2001................... 12,556 $128 $111,114 $(9,666) $(7,311) $(2,350) $91,915
====== ==== ======== ======= ======= ======= =======
The accompanying notes are an integral part of these financial statements.
34
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS(A)
Years Ended December 31, 2001, 2000 and 1999
(in thousands)
2001 2000 1999
--------- -------- -------
Cash flows from operating activities:
Net income (loss)............................... $ 2,046 $ 12,818 $ (206)
Ajustments to reconcile net income (loss) to net
cash provided by operating activities:
Extraordinary loss............................. -- 242 --
Depreciation, depletion and amortization....... 16,944 9,471 9,906
Deferred income tax expense (benefit).......... (5,832) 4,612 (954)
Oil and gas property valuation adjustment...... 15,400 -- --
Other.......................................... 142 107 (112)
Changes in operating assets and liabilities (net
of assets acquired and liabilities assumed in
the acquisition of Southern Mineral):
Accounts receivable............................ 5,343 (8,727) (36)
Other current assets........................... 707 (447) 164
Accounts payable............................... (13,761) 11,594 1,714
Accrued liabilities............................ (2,569) (1,923) 142
Income taxes payable........................... (5,317) 5,444 --
--------- -------- -------
Net cash provided by operating activities.... 13,103 33,191 10,618
--------- -------- -------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties.... -- 210 --
Additions to oil and gas properties............. (17,171) (6,862) (3,089)
Additions to plant and related facilities....... (366) (525) (166)
Purchase of Southern Mineral Corporation, net of
cash acquired (See Supplemental disclosure).... (20,989) -- --
Additions to other assets....................... -- (16) --
--------- -------- -------
Net cash used in investing activities........ (38,526) (7,193) (3,255)
--------- -------- -------
Cash flows from financing activities:
Proceeds from long-term debt.................... 134,763 30,030 2,238
Repayment of long-term debt..................... (129,273) (46,714) (4,566)
Purchase of treasury shares..................... (2,350) -- --
Other........................................... 401 (142) 135
--------- -------- -------
Net cash provided by (used in) financing
activities.................................. 3,541 (16,826) (2,193)
--------- -------- -------
Effect of exchange rate changes on cash.......... 1,201 (125) (57)
--------- -------- -------
Net increase (decrease) in cash and cash
equivalents..................................... (20,681) 9,047 5,113
Cash and cash equivalents at beginning of year... 21,946 12,899 7,786
--------- -------- -------
Cash and cash equivalents at end of year......... $ 1,265 $ 21,946 $12,899
========= ======== =======
- --------
(A) The first supplemental disclosure to this statement provides necessary
information to fully understand the economics of the Southern Mineral
transaction. Attempting to understand the economics of the Company,
without understanding the impact of the disclosure could lead to erroneous
conclusions. Current GAAP, however, requires that the information be
supplementarily disclosed and not in the body of this statement.
The accompanying notes are an integral part of these financial statements.
35
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2001, 2000 and 1999
(in thousands)
Supplemental disclosures:
1. Significant differences between balance sheet changes and amounts shown
in the Statement of Cash Flows for December 31, 2001 resulted from the purchase
of Southern Mineral net assets. Additional differences include the impact of
hedging activities and foreign currency translations. The following summarizes
the details of the fair value of assets acquired and liabilities assumed in the
acquisition of Southern Mineral:
Accounts receivable............................................ $ 5,278
Other current assets........................................... 582
Oil and gas properties......................................... 76,324
Other assets................................................... 6,508
---------
Total assets acquired........................................ 88,692
---------
Accounts payable............................................... (2,737)
Accrued liabilities............................................ (4,100)
Debt assumed................................................... (12,583)
Other liabilities.............................................. (9,241)
---------
Total liabilities assumed.................................... (28,661)
---------
Legal, professional and other costs............................ (424)
Financed through issue of common stock
(net of $380 registration costs) (38,618)
---------
Shown as purchase of Southern Mineral
Corporation on Statement of Cash Flows........................ $ 20,989
=========
2001 2000 1999
------- ------ ------
2. Interest paid $ 1,861 $3,423 $3,150
3. Income taxes paid $13,346 $ -- $ --
4. In 2001, 2000 and 1999, the Company issued $311,000, $525,000 and
$238,000 of additional notes, respectively, as provided under the provisions of
the agreements to finance the company's portion of plant capital additions (See
Note 6).
The accompanying notes are an integral part of these financial statements.
36
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
1. Summary of Accounting Policies
General
PetroCorp Incorporated, a Texas corporation, is engaged in the acquisition,
exploration, development, and the production and sale of crude oil and natural
gas in North America. The terms "PetroCorp" and "Company" refer to PetroCorp
Incorporated and its subsidiaries. PetroCorp operates in Canada through its
wholly-owned Canadian subsidiaries PCC Energy Inc. (PCC Inc.) and PCC Energy
Corp. In the United States, PetroCorp conducts business in its own name and
that of its U.S. subsidiaries, BEC Energy Inc. and PetroCorp Acquisition
Company.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
Petrocorp Incorporated and its wholly-owned subsidiaries. All significant
intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the amounts reported in the financial statements and
the accompanying notes. Actual results may differ from such estimates. In
addition, the oil and gas reserve data and the deferred tax asset include
significant estimates which, in the near term, could materially differ from
the amounts ultimately realized.
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 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. In the year ended December 31, 2001,
there was a valuation adjustment of $15,400,000. There was no valuation
adjustment for the years ended December 31, 2000 and 1999.
Plant and related facilities, consisting principally of a gas processing
plant in Alberta, Canada, are being depreciated on a straight-line basis over
the remaining estimated useful life. 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.
37
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Revenue Recognition
Revenues from the sale of petroleum produced are recognized upon the
passage of title, net of royalties and net profits royalty interests. In 2001,
the company changed its accounting for transportation and gathering costs to
include those charges in other revenues and other operating expenses. Revenues
and operating expenses for 2000 and 1999 have been increased by $903,000 and
$900,000 to conform to the new presentation. This reclassification had no
effect on income from operations.
Revenues from natural gas production are recorded using the sales method,
net of royalties and net profits interests, which may result in more or less
than the Company's share of pro-rata production from certain wells. The
Company estimates its balancing position to be approximately $390,000 (244,000
mcf) on underproduced properties and approximately $331,000 (207,000 mcf) on
overproduced properties. When sales volumes exceed the Company's entitled
share and the overproduced balance 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, 2001 and 2000, the Company
included $171,000 (120,000 mcf) and $53,000 (33,000 mcf) respectively, in
accrued liabilities with respect to overproduced imbalances. The Company's
policy is to expense the pro-rata share of lease operating costs from all
wells as incurred. Such expenses relating to the balancing position on wells
in which the Company has imbalances are not significant.
Revenues from plant processing are recognized at the time associated
natural gas is processed. Other revenues include fees associated with the
Company's U.S. gathering system and 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, 2001 and 2000, the Company's allowance for
doubtful accounts receivable was not significant.
Income Taxes
The Company utilizes the asset and liability method under which deferred
tax assets and liabilities are recognized for the estimated future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases.
Foreign Currency Translation
The "functional currency" for translating the Company's Canadian accounts
is the Canadian dollar. Assets and liabilities are translated into the
reporting currency at the rate of exchange in effect at the balance sheet date
while revenues, expenses, gains and losses are translated at the average
exchange rate for the period. The resulting translation adjustments are
accumulated in the other comprehensive loss component of shareholders' equity.
Foreign currency transaction gains and losses are recognized currently. For
the year ended December 31, 2001, the Company recognized a foreign currency
transaction gain of $916,000. For the years ended December 31, 2000 and 1999,
the Company recognized foreign currency transaction losses of $98,000 and
$22,000, respectively.
38
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
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 at the date of purchase to be cash equivalents. Cash and
cash equivalents are not insured above FDIC limits, which subjects the Company
to credit risk.
Hedging Activities
To reduce the impact of fluctuations in the market prices of oil and
natural gas, the Company periodically utilizes hedging strategies such as
futures transactions or swaps to hedge the price of a portion of its future
oil and natural gas production. Results of these hedging transactions are
reflected in oil and natural gas sales in the month of hedged production. In
2001, the impact of hedging transactions was a net increase in revenues of
$270,000. In 2000, the impact of hedging transactions was a net reduction of
revenues by $1,097,000. No hedging transactions occurred in 1999.
On June 15, 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133, as amended, was effective
January 1, 2001 for the Company. SFAS 133 requires that all derivative
instruments be recorded on the balance sheet at their fair value. Changes in
the fair value of derivatives are recorded each period in current earnings or
other comprehensive income (only certain types of hedge transactions are
reported as a component of other comprehensive income). Additionally, for all
hedge transactions the nature and type of hedge is disclosed.
Reclassification
Certain prior year balances have been reclassified to conform with the
current year financial statement presentation.
Other
In June 2001, the Financial Accounting Standards Board ("FASB") issued FAS
No. 141 and 142. FAS No. 141, Business Combinations, requires the purchase
method of accounting be used for all business combinations initiated after
June 30, 2001. FAS No. 142, Goodwill and Other Intangible Assets, changes the
accounting for goodwill from an amortization method to an impairment-only
approach and is effective January, 2002. The Company believes that adoption of
these new standards will not have an effect on its results of operations or
its financial position. In June 2001, the FASB issued FAS No. 143, Accounting
for Asset Retirement Obligations, and in August 2001, FAS No. 144, Accounting
for Impairment or Disposal of Long-Lived Assets. Management is currently
evaluating the impact of FAS 143 and 144 on financial position and results of
operations.
2. Restructuring
As part of a restructuring plan, on August 3, 1999, PetroCorp's Board of
Directors entered into a Management Agreement with its largest shareholder,
Kaiser-Francis Oil Company ("Kaiser-Francis"), under which Kaiser-Francis
provides management, technical, and administrative support services for all
PetroCorp operations in the United States and Canada.
As a result of the restructuring, fifty-two employees were terminated in
1999 with one employee terminated in 2000. Several employees elected to defer
receipt of their termination benefits until 2000. The Houston,
39
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Oklahoma City and Calgary offices were closed but the Company was still liable
under the lease agreements. In the second quarter of 2000, the Company was
able to find a replacement lessee for some of the idle office space earlier
than anticipated.
The company recorded restructuring costs of $3,643,000 during 1999.
Included in the costs are employee termination costs of $2,371,000, $807,000
in nonrefundable office lease discontinuance, $363,000 in investment banking
and legal costs, and $102,000 in other related costs.
The following table shows the change in accrued restructuring costs during
2001 (in thousands):
Expenditures
Balance at charged Balance at
December 31, against Changes in December 31,
2000 accrual estimate 2001
------------ ------------ ---------- ------------
Office lease discontinuance
and other
related costs.............. 70 70 -- --
--- --- --- ---
$70 $70 $-- $--
=== === === ===
3. Comprehensive Income
The Company follows SFAS No. 130, "Reporting Comprehensive Income." This
Statement establishes requirements for reporting comprehensive income and its
components which includes the Company's foreign currency translation
adjustments. The Company's comprehensive income (loss) for the years ended
December 31, 2001, 2000 and 1999 are as follows (amounts in thousands):
Years ended December
31,
------------------------
2001 2000 1999
------- ------- ------
Net income (loss)............................. $ 2,046 $12,818 $ (206)
------- ------- ------
Derivative hedging gain (net of taxes of
$679)........................................ 1,057 -- --
Reclassification of hedging gain to income
(net of taxes of $105) (165) -- --
Foreign currency translation.................. (2,491) (1,138) 1,690
------- ------- ------
(1,599) (1,138) 1,690
------- ------- ------
Comprehensive income (loss)................... $ 447 $11,680 $1,484
======= ======= ======
Accumulated other comprehensive loss was comprised solely of foreign
currency translation loss through December 31, 2000. As of December 31, 2001,
accumulated other comprehensive loss included $892 of derivative hedging gain,
net of taxes and $8,203 of foreign currency translation losses.
4. Merger with Southern Mineral Corporation
PetroCorp completed the acquisition of Southern Mineral on June 6, 2001.
Southern Mineral shareholders could elect to receive .471 shares of PetroCorp
common stock or cash of $4.71 or some combination thereof for each share of
Southern Mineral common stock they owned. Based on elections of Southern
Mineral shareholders, PetroCorp issued 4 million shares (valued at
approximately $39 million) and paid cash of approximately $21.4 million. The
cash consideration includes cash due to warrant and option holders, net of
cash received from the
40
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
exercise of Southern Mineral warrants and options. The totals include $3.4
million for 800,336 shares of Southern Mineral purchased by PetroCorp in open
market transactions prior to the merger.
The acquisition of Southern Mineral was accounted for using the purchase
method of accounting as of June 1, 2001 because as of that date, the Company
had effective control, and the results of operations have been included since
that date. The aggregate purchase price was as follows (amounts in thousands):
Issuance of common stock (net of $380 registration costs)........ $38,618
Net cash to Southern Mineral stockholders and warrant holders.... 20,989
Legal, professional and other costs.............................. 424
Assumed liabilities and debt and liabilities incurred............ 28,661
-------
Total purchase consideration..................................... $88,692
=======
The following unaudited pro forma information has been prepared assuming
Southern Mineral had been acquired as of the beginning of the period
presented. The pro forma information is presented for information purposes
only and is not necessarily indicative of what would have occurred if the
acquisition had been made as of that date. In addition, the pro forma
information is not intended to be a projection of future results and does not
reflect any efficiencies that may result from the integration of Southern
Mineral.
Pro Forma Information (Unaudited)
(In thousands, except per share data)
Year Ended Year Ended
December 31, December 31,
2001 2000
------------ ------------
Revenues........................................ $65,487 $78,153
Income before income taxes...................... $ 2,711 $28,690
Net income...................................... $ 2,622 $16,385
Earnings per common share--basic................ $ 0.21 $ 1.29
Earnings per common share--diluted ............. $ 0.20 $ 1.28
The above pro forma data reflects $3,665 and $5,544, respectively, of
bankruptcy expenses and restructuring costs (primarily investment banker and
employee severance related costs) for Southern Mineral for the year ended
December 31, 2001 and 2000.
41
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
5. Property, Plant and Equipment
Investments in property, plant and equipment were as follows at December
31, 2001 and 2000 (amounts in thousands):
2001 2000
--------- ---------
Oil and gas properties:
Proved.......................................... $ 315,935 $ 226,813
Unproved........................................ 1,223 2,032
--------- ---------
317,158 228,845
Plant and related facilities...................... 9,743 9,969
Gas gathering facilities.......................... 1,698 1,698
Furniture, fixtures and equipment................. 95 --
--------- ---------
328,694 240,512
Less--accumulated depreciation, depletion,
amortization and impairment...................... (200,242) (169,576)
--------- ---------
$ 128,452 $ 70,936
========= =========
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 2001, 2000 and 1999 was
$16,846,000, $9,471,000 and $9,906,000, respectively. Oil and gas property
depreciation, depletion and amortization for the years ended December 31,
2001, 2000 and 1999 was $15,529,000, $7,947,000 and $8,138,000 , respectively.
Depreciation, depletion and amortization per equivalent Mcf (using a Mcf-to-
barrel conversion factor of 6 to 1) for the years ended December 31, 2001,
2000 and 1999 was $1.38, $0.85 and $0.85, respectively, for U.S. operations
and $0.92, $0.61 and $0.50, respectively, for Canadian operations. The total
composite rates were $1.15, $0.74 and $0.69 for the years ended December 31,
2001, 2000 and 1999, respectively. During 2001 the Company also recorded a
ceiling test write-down of $15,400,000.
6. Long-Term Debt
The Company's total long-term debt is as follows (amounts in thousands):
2001 2000
------- -------
TD Bank Credit Agreement................................ $47,288 $28,500
Nonrecourse Note Payable................................ 1,659 2,686
Less: Current portion................................... (1,327) (1,194)
------- -------
Total long-term debt.................................... $47,620 $29,992
======= =======
Debt maturing subsequent to December 31, 2001 is as follows: $1,327,000 in
2002, and $47,620,000 in 2003.
Bank Debt
On June 26, 1997, the Company entered into a $50 million, five-year
revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the
agent, and the Bank of Nova Scotia. The facility was amended in June 1998 and
July 1999 to extend the initial five-year term an additional year to July 1,
2003 with quarterly borrowing base amortization beginning September 30, 2001.
42
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
In July 2000, the Company entered into a new $75 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The term of the facility is through April 30, 2003 and the
initial borrowing base was set at $58 million. Borrowings can be funded by
either Eurodollar loans or Base Rate loans. The interest rate on the
borrowings is equal to an interest rate spread plus either the Eurodollar rate
or the Base Rate. The interest spread is determined from a sliding scale based
on the Company's borrowing base percentage utilization in effect from time to
time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25
on Base Rate loans. At December 31, 2001, the weighted average interest rate
under this facility was approximately 4.1%.
The $75 million revolving credit agreement prohibits the declaration and
payment of dividends on the common stock of the Company. Also, the debt
agreement requires the Company to maintain a minimum current ratio, a minimum
tangible net worth, and a minimum interest coverage ratio.
Nonrecourse Notes Payable
On December 12, 1991, the Company (through its Canadian subsidiary, PCC
Inc.) acquired an interest in certain oil and gas properties and related gas
processing facilities located in the Hanlan-Robb area in western Alberta,
Canada. The Company used the proceeds from the issuance of redeemable
preferred stock of PCC Inc. to partially fund the acquisition. The holders of
the preferred stock also separately and concurrently acquired an interest in
the same oil and gas properties as the Company.
On August 9, 1994, PCC Inc. entered into agreements whereby PCC Inc.
redeemed the remaining shares of its redeemable preferred stock for
$7,034,000. Simultaneously, PCC Inc. issued $7,034,000 in nonrecourse long-
term notes payable (the Nonrecourse Notes Payable) to the previous holders of
the preferred stock with financial terms similar to the redeemable preferred
stock. Consistent with the redeemable preferred stock, the Nonrecourse Notes
Payable are denominated in Canadian dollars.
In 2001, 2000 and 1999, the Company issued $311,000, $525,000 and $238,000
of additional notes, respectively, as provided under the provisions of the
agreements to finance the company's portion of plant capital additions.
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. At December 31, 2001 and 2000, unpaid
interest and redemptions totaled $394,000 and $334,000, respectively.
7. Hedging Activities
To reduce the impact of fluctuations in the market prices of oil and
natural gas, the Company periodically utilizes hedging strategies such as
futures transactions or swaps to hedge the price of a portion of its future
oil and natural gas production. Results of these hedging transactions are
reflected in oil and natural gas sales in the month of the hedged production.
43
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
In the first quarter of 2000, the Company entered into swap transactions in
an effort to lock in a portion of higher oil prices. These transactions
applied to approximately 50 percent of the Company's projected oil production
from April 2000 through December 2000, at prices ranging from $23.57 to $29.00
per barrel. In the second quarter of 2000, the Company entered into a no-cost
collar arrangement for a portion of its natural gas production by which
180,000 MMbtu for each of the months July through October 2000 were subject to
a $4.96 ceiling and a $3.50 floor per Mmbtu. Oil and gas revenue includes
$69,000 received and $1,166,000 paid in settlement of swap and collar
transactions through December 31, 2000. There were no hedges outstanding at
December 31, 2000.
As part of PetroCorp's acquisition of Southern Mineral Corporation
("Southern Mineral"), the Company assumed crude oil and natural gas costless
collars with a fair value (liability) at date of acquisition of $821,000. The
estimated fair value of the derivative instruments, which fair values were
obtained from the counter-parties, held by the Company at December 31, 2001
were an asset of $644,000 (included in other current assets) related to the
oil and gas hedges and a liability of $314,000 (included in other liabilities)
related to the interest rate swap agreement. The ineffective portion of these
hedges was not material as of December 31, 2001. Hedging transactions for the
year ended December 31, 2001 increased oil and gas revenues by $270,000
(reclassified from comprehensive income).
The Company offsets any gain or loss on the swap and collars contract with
the realized prices for its production. While the swaps and collars reduce the
Company's exposure to declines in the market price of natural gas and oil,
this also limits the Company's gains from increases in the market price.
As a result of the merger with Southern Mineral, the Company also assumed
an interest rate swap position that was originally intended to hedge the
variability of interest expense associated with Southern Mineral's variable
rate Canadian debt. Under the swap agreement, the Company receives a floating
rate of the Canadian prime rate and pays a fixed rate of 5.96% on a notional
amount of Canadian $15 million. The interest rate swap did not qualify for
hedge accounting. The Company has recorded the swap's fair value of $192,000
as a liability at the date of the merger.
44
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
8. Income Taxes
The components of income (loss) before income taxes for the years ended
December 31, 2001, 2000 and 1999 consisted of the following (amounts in
thousands):
2001 2000 1999
------- ------- -------
United States operations.................... $(9,941) $ 9,834 $(4,191)
Canadian operations......................... 11,707 13,335 3,031
------- ------- -------
$ 1,766 $23,169(A) $(1,160)
======= ======= =======
The provision (benefit) for income taxes consists of the following (amounts
in thousands):
2001 2000 1999
------- ------- -------
Deferred:
Federal.................................... $(4,448) $ 3,488 $(1,090)
State...................................... (321) 317 (65)
Canadian................................... (1,063) 807 201
------- ------- -------
(5,832) 4,612 (954)
======= ======= =======
Current:
Federal.................................... 110 -- --
State...................................... 47 -- --
Canadian................................... 5,395 5,497 --
------- ------- -------
5,552 5,497 --
------- ------- -------
$ (280) $10,109(A) $ (954)
======= ======= =======
- --------
(A) Excludes extraordinary loss of $385 and related taxes of $143.
45
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
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 and extraordinary loss
for the years ended December 31, 2001, 2000, and 1999 is presented in the
following table (amounts in thousands):
2001 2000 1999
------- ------- -------
United States federal income taxes (benefit)
at statutory rate of 35%.................... $ 618 $ 8,109 $ (406)
Increases (reductions) resulting from:
Canadian earnings not subject to United
States taxes.............................. (4,097) (4,667) (1,061)
Canadian income taxes...................... 4,332 6,304 201
Statutory depletion........................ (1,079) -- --
State income taxes......................... (178) 206 (65)
Other...................................... 124 157 377
------- ------- -------
$ (280) $10,109 $ (954)
======= ======= =======
Deferred tax assets and liabilities consist of the following at December
31, 2001 and 2000 (amounts in thousands):
2001 2000
-------- --------
Deferred tax assets:
Depletion and net operating loss carryforward--
U.S............................................... $ 23,542 $ 15,404
Net operating loss carryforward--Canada............ 824 633
Derivative liability............................... 134 --
-------- --------
Gross deferred tax asset............................. 24,500 16,037
-------- --------
Deferred tax liabilities:
Excess of basis in property, plant and equipment
for financial reporting purposes over the tax
basis--U.S........................................ (5,238) (5,150)
Excess of basis in property, plant and equipment
for financial reporting purposes over the tax
basis--Canada..................................... (14,662) (6,825)
Derivative asset................................... (247) --
-------- --------
Gross deferred tax liability......................... (20,147) (11,975)
-------- --------
$ 4,353 $ 4,062
======== ========
As of December 31, 2001, the Company has U.S. net operating loss (NOL)
carryforwards of $57,265,000 and $59,201,000 for regular tax and alternative
minimum tax purposes, respectively. Regular tax NOL carryforwards and
alternative minimum tax NOL carryforwards begin to expire in 2009.
Additionally, statutory depletion carryforwards of $7,322,000 are available at
December 31, 2001.
Realization of the deferred tax asset is dependent on generating sufficient
taxable income prior to expiration of loss carryforwards. Although realization
is not assured, management believes it is more likely than not that the
deferred tax asset will be realized. The amount of the deferred tax asset
considered realizable, however, could be reduced in the near term if estimates
of future taxable income during the carryforward period are reduced.
Additionally, certain future changes in the Company's shareholders may impose
restrictions under Section 382 of the Internal Revenue Code on the annual
utilization of its net operating loss carryforwards.
46
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
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):
Years ended December
31,
-------------------------
2001 2000 1999
------- ------- -------
Tax computed at statutory rate of 44.62%
(42.62% for 2001)........................... $ 4,990 $ 5,950 $ 1,352
Nondeductible crown royalties, net of royalty
credits..................................... 5,822 4,411 1,515
Resource allowance........................... (5,405) (5,299) (2,666)
Revenue Canada audit adjustments............. (1,075) 1,242 --
------- ------- -------
$ 4,332 $ 6,304 $ 201
======= ======= =======
9. 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. The following table summarizes these options:
Weighted Average
Options Exercise Price
-------- ----------------
Outstanding at December 31, 1998............... 719,500 $ 7.87
Granted...................................... -- --
Forfeited.................................... (20,000) $ 6.38
Exercised.................................... (27,000) $ 5.00
--------
Outstanding at December 31, 1999............... 672,500 $ 8.04
Granted...................................... -- --
Forfeited.................................... -- --
Exercised.................................... (20,700) $ 6.38
--------
Outstanding at December 31, 2000............... 651,800 $ 8.09
Granted...................................... -- --
Forfeited.................................... (162,000) $10.00
Exercised.................................... (101,300) $ 6.55
--------
Outstanding at December 31, 2001............... 388,500 $ 7.69
========
Of the 388,500 outstanding options under the Option Plan at December 31,
2001, 121,500 options with an exercise price of $5.00, 80,000 options with an
exercise price of $6.38 and 187,000 options with an exercise price of $10 had
weighted average contractual lives of 0.75 years, 4.1 years and 0.75 years,
respectively. All of these options are exercisable as of December 31, 2001.
47
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
In 1997, the Company established the 1997 PetroCorp Non-Employee Director
Stock Option Plan (the Director Option Plan) for the benefit of the Company's
Board of Directors. This plan allows up to 75,000 option shares to be granted.
The Director Options were fully vested and exercisable at the date of grant.
The following table summarizes these options:
Weighted Average
Options Exercise Price
------- ----------------
Outstanding at December 31, 1998................ 31,000 $8.55
Granted....................................... 6,000 $6.75
Forfeited..................................... -- --
Exercised..................................... -- --
-------
Outstanding at December 31, 1999................ 37,000 $8.26
Granted....................................... -- --
Forfeited..................................... -- --
Exercised..................................... -- --
-------
Outstanding at December 31, 2000................ 37,000 $8.26
Granted....................................... -- --
Forfeited..................................... (14,000) $8.30
Exercised..................................... -- --
-------
Outstanding at December 31, 2001................ 23,000 $8.23
=======
As of December 31, 2001, the weighted average remaining contractual life of
the outstanding options under the Director Option Plan was 6.0 years and the
exercise prices ranged from $6.75 to $8.63.
In 2000, the Company established the 2000 Stock Option Plan for the benefit
of employees and the Company's Board of Directors. Employee options vest one
year from date of grant and director options vest six months from the date of
grant. This plan allows up to 600,000 option shares to be granted. The
following table summarizes these options:
Weighted Average
Options Exercise Price
------- ----------------
Outstanding at December 31, 1999................ -- --
Granted....................................... 106,650 $6.34
Forfeited..................................... -- --
Exercised..................................... -- --
-------
Outstanding at December 31, 2000................ 106,650 $6.34
Granted....................................... 163,000 $9.67
Forfeited..................................... (6,500) $9.15
Exercised..................................... (6,500) $6.13
-------
Outstanding at December 31, 2001................ 256,650 $8.39
=======
As of December 31, 2001, the weighted average remaining contractual life of
the outstanding options under the 2000 Stock Option Plan was 8.8 years. Of the
outstanding options, 154,150 were exercisable at year end with an average
remaining contractual life of 8.6 years. At December 31, 2001, exercise prices
ranged from $6.13 to $9.75.
48
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
As part of the merger with Southern Mineral, PetroCorp assumed all stock
options under the various plans of Southern Mineral. Under the terms of these
plans, options equivalent to 330,393 shares of PetroCorp stock have been
authorized. No additional grants are anticipated. All outstanding options were
vested at the date of the merger. The following table summarizes these
options:
Weighted
Average
Exercise
Options Price
------- --------
Outstanding at December 31, 2000........................ -- --
Granted............................................... 179,268 $18.70
Forfeited............................................. (44,887) $14.47
Exercised............................................. (9,420) $ 5.31
-------
Outstanding at December 31, 2001........................ 124,961 $21.01
=======
As of December 31, 2001, all outstanding options were exercisable and all
will expire in 2002. At December 31, 2001, exercise prices ranged from $10.62
to $71.87.
Stock options under all three plans expire ten years from the date of grant
and the exercise price equals market value on the grant date.
The Company adopted SFAS No. 123, "Accounting for Stock Based
Compensation," effective July 1, 1996. While SFAS No. 123 encourages entities
to adopt the fair value based method of accounting for their stock-based
compensation plans, the Company has elected to continue to utilize the
intrinsic value method under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees." Compensation expense has been
recognized for these stock-based compensation plans for any grants to
individuals who do not meet the definition of employee. Had compensation cost
for the 2000 Stock Option Plan and the Director Option Plan been determined
based upon the fair value at the grant date for awards under the plans,
consistent with the methodology prescribed under SFAS No. 123, the Company's
2001 and 2000 net income and 1999 net loss and earnings/loss per share would
have been reduced/increased by approximately $383,000, $330,000 and $17,000,
or $0.03, $0.04 and nil per share, respectively. The fair value of the options
granted during 2001, 2000 and 1999 were $751,000, $432,000 and $27,000,
respectively, on the dates of grants using the Black-Scholes option-pricing
model with the following assumptions:
2001 2000 1999
--------- --------- ----
Weighted average life, in years................. 10 10 10
Risk-Free interest rate......................... 5.1%-5.2% 6.0%-6.5% 6.1%
Expected Volatility............................. 40% 41% 46%
Expected Dividend Rate.......................... None None None
Effective January 1, 1993, the Company established a savings plan, which is
available to eligible employees and qualifies as a deferred compensation plan
under Section 401(k) of the Internal Revenue Code. The Company matches
employee contributions for an amount up to 6% of each employee's salary. The
Company's contributions to the plan, which are charged to expense, totaled
nil, $100,000 and $198,000 in 2001, 2000 and 1999, respectively.
49
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
10. Earnings Per Share
The following is a reconciliation of the numerators and denominators of the
basic and diluted per share computations for the periods presented (in
thousands, except per share amounts).
Per Share Amounts
----------------------------------
Net Income
(Loss) Before Net
Extraordinary Extraordianry Income
Income Shares Item Item (Loss)
------- ------ ------------- ------------- ------
Year ended December 31,
2001
Basic EPS:
Net income............. $ 2,046 10,975 $ 0.19 $ -- $ 0.19
Effect of dilutive
securities:
Options................ -- 144 (0.01) -- (0.01)
------- ------ ------ ------ ------
Diluted EPS:
Net income............. $ 2,046 11,119 $ 0.18 $ -- $ 0.18
======= ====== ====== ====== ======
Year ended December 31,
2000
Basic EPS:
Net income(A).......... $12,818 8,692 $ 1.50 $(0.03) $ 1.47
Effect of dilutive
securities:
Options................ -- 94 (0.01) -- (0.01)
------- ------ ------ ------ ------
Diluted EPS:
Net income(A).......... $12,818 8,786 $ 1.49 $(0.03) $ 1.46
======= ====== ====== ====== ======
Year ended December 31,
1999
Basic EPS:
Net loss............... $ (206) 8,658 $(0.02) $ -- $(0.02)
Effect of dilutive
securities:
Options................ -- -- -- -- --
------- ------ ------ ------ ------
Diluted EPS:
Net loss............... $ (206) 8,658 $(0.02) $ -- $(0.02)
======= ====== ====== ====== ======
- --------
(A) Net of extraordinary loss of $242.
The 2001 and 2000 net income per share and the 1999 net loss per share
amounts do not include the effect of potentially dilutive securities of
469,000, 395,000 and 709,500, respectively, as the impact of these outstanding
options was antidilutive.
50
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
11. 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
------- ------- --------- --------
2001:
Revenues.............................. $25,169 $26,105 $ -- $ 51,274
Income (loss) from operations......... (8,722) 13,170 (2,259) 2,189
Depreciation, depletion, amorization
and impairment....................... 25,016 7,328 -- 32,344
Capital expenditures.................. 55,432 38,284 -- 93,716
Long-lived assets at December 31...... 67,068 63,952 131 131,151
2000:
Revenues.............................. $23,588 $20,985 $ -- $ 44,573
Income (loss) from operations......... 12,353 14,402 (1,084)(A) 25,671
Depreciation, depletion and
amortization......................... 5,178 4,293 -- 9,471
Capital expenditures.................. 1,730 6,459 -- 8,189
Long-lived assets at December 31...... 34,005 36,931 242 71,178
1999:
Revenues.............................. $15,565 $11,561 $ -- $ 27,126
Income (loss) from operations......... 5,045 5,607 (8,400)(B) 2,252
Depreciation, depletion and
amortization......................... 5,746 3,714 446 9,906
Capital expenditures.................. 1,043 2,212 -- 3,255
Long-lived assets at December 31...... 37,600 36,106 107 73,813
- --------
(A) Net of $445 restructuring cost credits.
(B) Includes $3,643 of restructuring costs.
The following table reflects purchasers which accounted for more than 10%
of the Company's oil and gas revenues:
2001 2000 1999
---- ---- ----
Pan-Alberta Gas Ltd........................................ 22% 19% 18%
EOTT Energy Operating Limited Partnership.................. -- -- 11%
Engage Energy LP........................................... 32% 27% 17%
During 1999 and prior, the majority of the Company's Canadian gas was
dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian
aggregator. However, as part of a legal settlement effective December 31,
1998, approximately 50% of PetroCorp's dedicated gas volumes have been
released from the Pan-Alberta contracts. These released volumes are now sold
on the spot market at prevailing prices. The Company does not believe the loss
of any purchaser would have a material adverse effect on its financial
position since the Company believes alternative sales arrangements could be
made on relatively comparable terms.
51
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
12. Common Stock Repurchases
On September 14, 2001, the Company announced that the Board of Directors
authorized the purchase of up to 1,000,000 shares of the Company's common
stock. Through December 31, 2001, 264,607 shares have been purchased at a cost
of $2,350,000, which shares are held in treasury.
13. Commitments and Contingencies
The Company has entered into operating lease agreements with noncancellable
terms in excess of one year for office space. Future minimum lease payments
are $376,000 and $54,000 for the years ending December 31, 2002 and 2003,
respectively with no payments after that time. Future minimum sublease income
with noncancellable terms in excess of one year for office space are $159,000
and $34,000 for the years ending December 31, 2002 and 2003. Total rental
expense for office space for the years ended December 31, 2001, 2000 and 1999
was $140,000, $111,000 and $583,000, respectively.
On February 13, 2002, R.A. Mackie & Co., L.P., Millenco, L.P. and Wein
Securities Corp, as plaintiffs, filed a lawsuit against PetroCorp in New York
Supreme Court (Index No. 02-600589). In this action certain former holders of
warrants of Southern Mineral Corporation allege that the provisions made for
such warrants in connection with the merger of Southern Mineral Corporation
into PetroCorp Acquisition Corporation, a wholly-owned subsidiary of PetroCorp
Incorporated, were inadequate. The plaintiffs seek $5,000,000. Based on
consultation with legal counsel, the Company is of the opinion the action is
without merit.
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.
14. Related Party Transactions
The Company has engaged an engineering consulting company to procure
certain services and equipment pertaining to its Canadian operations. The
consulting company solicits bids from various vendors in order to obtain
competitive pricing. During 2001, 2000 and 1999, the consulting company
procured $3,000, nil and $45,000 from an equipment supplier partly owned by a
director of the Company's Canadian subsidiaries who is a relative of the
Company's previous Chief Executive Officer.
The Company is a joint-interest owner in a project operated by Kaiser-
Francis Oil Company, a shareholder. During 2001, 2000 and 1999, the Company
remitted $63,000, $154,000 and $95,000, respectively, to Kaiser-Francis as
payment of the Company's share of the joint operation. During 2001, the
Company remitted $2,176,000 and $888,000 to Kaiser-Francis for management fees
and cost reimbursements, respectively, under the Management Agreement (see
Note 2). Amounts payable to Kaiser-Francis at December 31, 2001 and 2000 were
$272,000 and $22,000, respectively.
52
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
15. Oil and Gas Reserves and Related Financial Data
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
--------- -------- ---------
2001:
Proved properties........................ $ 233,204 $ 82,731 $ 315,935
Unproved properties...................... 263 960 1,223
--------- -------- ---------
233,467 83,691 317,158
Accumulated depreciation, depletion and
amortization............................ (168,989) (21,244) (190,233)
========= ======== =========
$ 64,478 $ 62,447 $ 126,925
========= ======== =========
2000:
Proved properties........................ $ 176,834 $ 49,979 $ 226,813
Unproved properties...................... 1,223 809 2,032
--------- -------- ---------
178,057 50,788 228,845
Accumulated depreciation, depletion and
amortization............................ (144,105) (16,308) (160,413)
--------- -------- ---------
$ 33,952 $ 34,480 $ 68,432
========= ======== =========
1999:
Proved properties........................ $ 171,931 $ 45,060 $ 216,991
Unproved properties...................... 4,599 1,555 6,154
--------- -------- ---------
176,530 46,615 223,145
Accumulated depreciation, depletion and
amortization............................ (139,323) (13,670) (152,993)
--------- -------- ---------
$ 37,207 $ 32,945 $ 70,152
========= ======== =========
Of the unproved properties capitalized cost at December 31, 2001,
approximately $96,000 and $349,000 were incurred in 2001 and 2000,
respectively. The Company anticipates evaluating these properties during
subsequent years.
53
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Costs Incurred in Oil and Gas Producing Activities
Presented below are costs incurred in oil and gas property acquisition,
exploration and development activities (amounts in thousands):
U.S. Canada Total
------- ------- -------
2001:
Acquisition of properties:
Proved properties............................... $42,608 $33,476 $76,084
Unproved properties............................. 678 -- 678
Exploration costs................................. 2,003 1,166 3,169
Development costs(A).............................. 10,121 3,203 13,324
------- ------- -------
Total........................................... $55,410 $37,845 $93,255
======= ======= =======
2000:
Acquisition of properties:
Proved properties............................... $ 104 $ 126 $ 230
Unproved properties............................. 80 269 349
Exploration costs................................. -- 166 166
Development costs(A).............................. 1,553 5,365 6,918
------- ------- -------
Total........................................... $ 1,737 $ 5,926 $ 7,663
======= ======= =======
1999:
Acquisition of properties:
Proved properties............................... $ 150 $ 230 $ 380
Unproved properties............................. 90 9 99
Exploration costs................................. 27 204 231
Development costs................................. 776 1,603 2,379
------- ------- -------
Total........................................... $ 1,043 $ 2,046 $ 3,089
======= ======= =======
- --------
(A) Includes approximately $42 and $600 of costs incurred in 2001 and 2000,
respectively, for development of properties previously classified as
proved undeveloped properties for the years 2000 and 1999 respectively.
Included in the above amounts for the years ended December 31, 2001, 2000
and 1999 were nil, nil, and $1,188, respectively, of capitalized internal
costs related to property acquisition, exploration and development.
54
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Results of Operations From Oil and Gas Producing Activities (unaudited)
The results of operations from oil and gas 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
-------- ------- --------
2001:
Revenues..................................... $ 24,944 $23,114 $ 48,058
Production costs............................. (8,705) (4,292) (12,997)
Depreciation, depletion, amortization and
impairment.................................. (24,884) (6,045) (30,929)
Income tax benefit (expense)................. (2,500) (5,863) (8,363)
-------- ------- --------
Results of operations from petroleum
producing activities (excluding corporate
overhead and interest costs)................ $(11,145) $ 6,914 $ (4,231)
======== ======= ========
2000:
Revenues..................................... $ 23,481 $18,783 $ 42,264
Production costs............................. (5,813) (2,225) (8,038)
Depreciation, depletion and amortization..... (4,782) (3,165) (7,947)
Income tax benefit (expense)................. (4,728) (5,078) (9,806)
-------- ------- --------
Results of operations from petroleum
producing activities (excluding corporate
overhead and interest costs)................ $ 8,158 $ 8,315 $ 16,473
======== ======= ========
1999:
Revenues..................................... $ 15,506 $ 9,656 $ 25,162
Production costs............................. (4,555) (2,178) (6,733)
Depreciation, depletion and amortization..... (5,410) (2,728) (8,138)
Income tax benefit (expense)................. (2,050) (973) (3,023)
-------- ------- --------
Results of operations from petroleum
producing activities (excluding corporate
overhead and interest costs)................ $ 3,491 $ 3,777 $ 7,268
======== ======= ========
55
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Reserve Quantities (unauditied)
Estimates of proved reserves and the related standardized measure of
discounted future net cash flow information are based on the reports of
independent petroleum engineers for 2000 and 1999 and reserve evaluations
performed by the Company's engineer in 2001 and reviewed by independent
petroleum engineers.
The Company's estimates of its proved reserves and proved developed
reserves of oil and gas as of December 31, 2001, 2000 and 1999 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)
------- ------ ------- ------ ------- ------
2001:
Proved reserves:
Beginning of year........... 3,109 22,709 1,101 52,550 4,210 75,259
Production.................. (396) (4,498) (203) (5,376) (599) (9,874)
Purchase of minerals-in-
place...................... 2,190 19,722 1,585 12,086 3,775 31,808
Extensions and discoveries.. 25 867 -- 1,089 25 1,956
Improved recoveries......... -- -- -- -- -- --
Sales of minerals-in-place.. -- -- -- -- -- --
Revision to previous
estimates.................. (997) 2,584 35 (1,758) (962) 826
----- ------ ----- ------ ----- ------
End of year................. 3,931 41,384 2,518 58,591 6,449 99,975
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year........... 2,888 20,551 1,068 46,624 3,956 67,175
===== ====== ===== ====== ===== ======
End of year................. 3,350 38,806 2,242 50,876 5,592 89,682
===== ====== ===== ====== ===== ======
2000:
Proved reserves:
Beginning of year........... 3,261 20,950 1,320 55,409 4,581 76,359
Production.................. (294) (3,850) (110) (4,519) (404) (8,369)
Purchase of minerals-in-
place...................... 8 1 -- 213 8 214
Extensions and discoveries.. 155 1,314 100 4,049 255 5,363
Improved recoveries......... -- -- -- -- -- --
Sales of minerals-in-place.. -- (213) -- -- -- (213)
Revision to previous
estimates.................. (21) 4,507 (209) (2,602) (230) 1,905
----- ------ ----- ------ ----- ------
End of year................. 3,109 22,709 1,101 52,550 4,210 75,259
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year........... 3,180 18,906 1,187 47,026 4,367 65,932
===== ====== ===== ====== ===== ======
End of year................. 2,888 20,551 1,068 46,624 3,956 67,175
===== ====== ===== ====== ===== ======
1999:
Proved reserves:
Beginning of year........... 2,578 21,970 1,412 57,422 3,990 79,392
Production.................. (324) (4,421) (138) (4,660) (462) (9,081)
Purchase of minerals-in-
place...................... -- 148 -- 1,098 -- 1,246
Extensions and discoveries.. -- -- 6 1,066 6 1,066
Improved recoveries......... 605 91 -- -- 605 91
Sales of minerals-in-place.. -- -- -- -- -- --
Revision to previous
estimates.................. 402 3,162 40 483 442 3,645
----- ------ ----- ------ ----- ------
End of year................. 3,261 20,950 1,320 55,409 4,581 76,359
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year........... 2,499 19,454 1,081 47,460 3,580 66,914
===== ====== ===== ====== ===== ======
End of year................. 3,180 18,906 1,187 47,026 4,367 65,932
===== ====== ===== ====== ===== ======
56
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
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 average prices used were based on the adjusted cash
spot price for natural gas and oil at December 31. At December 31, 2001, there
were crude oil and natural gas collar hedges outstanding with a fair value of
$644,000.
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
-------- -------- --------
2001:
Future gross revenues............................ $169,025 $175,058 $344,083
Less--future costs:
Production..................................... 58,768 47,806 106,574
Development(A)................................. 10,850 4,358 15,208
-------- -------- --------
Future net cash flows before income taxes........ 99,407 122,894 222,301
Less--10% annual discount for estimated timing of
cash flows...................................... 39,836 49,229 89,065
-------- -------- --------
Present value of future net cash flows before
income tax...................................... 59,571 73,665 133,236
Less--present value of future income taxes....... 752 28,130 28,882
-------- -------- --------
Standardized measure of discounted future net
cash flows...................................... $ 58,819 $ 45,535 $104,354
======== ======== ========
(A) $ 11,511 of development costs are for proved
undeveloped properties
2000:
Future gross revenues............................ $313,677 $501,760 $815,437
Less--future costs:
Production..................................... 55,534 31,530 87,064
Development (A)................................ 2,457 2,979 5,436
-------- -------- --------
Future net cash flows before income taxes........ 255,686 467,251 722,937
Less--10% annual discount for estimated timing of
cash flows...................................... 103,563 209,119 312,682
-------- -------- --------
Present value of future net cash flows before
income tax...................................... 152,123 258,132 410,255
Less--present value of future income taxes....... 42,860 110,860 153,720
-------- -------- --------
Standardized measure of discounted future net
cash flows...................................... $109,263 $147,272 $256,535
======== ======== ========
(A) $3,232 of development costs are for proved
undeveloped properties
57
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
U.S. Canada Total
-------- -------- --------
1999:
Future gross revenues............................. $128,792 $129,892 $258,684
Less--future costs:
Production...................................... 35,640 23,544 59,184
Development..................................... 1,799 3,530 5,329
-------- -------- --------
Future net cash flows before income taxes......... 91,353 102,818 194,171
Less--10% annual discount for estimated timing of
cash flows....................................... 30,671 44,753 75,424
-------- -------- --------
Present value of future net cash flows before
income tax....................................... 60,682 58,065 118,747
Less--present value of future income taxes........ 4,276 20,711 24,987
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................ $ 56,406 $ 37,354 $ 93,760
======== ======== ========
58
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
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
-------- -------- --------
2001:
Standardized measure--beginning of period...... $109,263 $147,272 $256,535
Sales of oil and gas produced, net of
production costs.............................. (16,239) (18,822) (35,061)
Purchases of minerals-in-place................. 27,385 23,450 50,835
Extensions, discoveries and improved recovery.. 1,197 1,612 2,809
Sales of minerals-in-place..................... -- -- --
Net changes in prices and productions costs.... (114,680) (240,848) (355,528)
Changes in estimated future development costs.. (11,036) (2,994) (14,030)
Development costs incurred..................... 10,121 3,203 13,324
Revisions to previous quantity estimates....... (3,103) (1,686) (4,789)
Accretion of discount.......................... 15,213 25,813 41,026
Changes in timing of production and other...... (1,410) 25,805 24,395
Net changes in income taxes.................... 42,108 82,730 124,838
-------- -------- --------
Standardized measure--end of period............ $ 58,819 $ 45,535 $104,354
======== ======== ========
2000:
Standardized measure--beginning of period...... $ 56,406 $ 37,354 $ 93,760
Sales of oil and gas produced, net of
production costs.............................. (17,668) (16,558) (34,226)
Purchases of minerals-in-place................. 23 75 98
Extensions, discoveries and improved recovery.. 8,502 18,626 27,128
Sales of minerals-in-place..................... (108) -- (108)
Net changes in prices and productions costs.... 94,155 219,553 313,708
Development costs incurred..................... 238 2,705 2,943
Revisions to previous quantity estimates....... 16,130 (18,563) (2,433)
Accretion of discount.......................... 6,068 5,807 11,875
Changes in timing of production and other...... (15,899) (11,579) (27,478)
Net changes in income taxes.................... (38,584) (90,148) (128,732)
-------- -------- --------
Standardized measure--end of period............ $109,263 $147,272 $256,535
======== ======== ========
1999:
Standardized measure--beginning of period...... $ 30,964 $ 30,578 $ 61,542
Sales of oil and gas produced, net of
production costs.............................. (10,950) (7,479) (18,429)
Purchases of minerals-in-place................. 187 1,491 1,678
Extensions and discoveries..................... 3,198 1,100 4,298
Sales of minerals-in-place..................... -- -- --
Net changes in prices and productions costs.... 27,195 11,517 38,712
Development costs incurred..................... 456 805 1,261
Revisions to previous quantity estimates....... 14,144 1,672 15,816
Accretion of discount.......................... 3,096 4,706 7,802
Changes in timing of production and other...... (7,608) (2,795) (10,403)
Net changes in income taxes.................... (4,276) (4,241) (8,517)
-------- -------- --------
Standardized measure--end of period............ $ 56,406 $ 37,354 $ 93,760
======== ======== ========
59
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
The standardized measure amounts are based on current prices at each year
end and reflect overall weighted average prices of:
U.S. Canada Total
------ ------ ------
2001:
Oil (per BBL)............................................ $19.84 $19.73 $19.79
Gas (per Mcf)............................................ 2.70 2.32 2.48
2000:
Oil (per BBL)............................................ $26.25 $29.73 $27.16
Gas (per Mcf)............................................ 9.98 8.85 9.19
1999:
Oil (per BBL)............................................ $24.40 $22.84 $23.95
Gas (per Mcf)............................................ 2.35 1.80 1.95
16. Supplementary Information
At December 31, 2001, accrued liabilities included $1.3 million of accrued
lease operating expense, $1.4 million of accrued capital costs and $1.2
million of other miscellaneous expense. At December 31, 2000, accrued
liabilities included $.8 million of accrued lease operating expense, $1.0
million of accrued capital costs and $.7 million of other miscellaneous
expenses.
17. Summarized Quarterly Financial Data (unaudited)
(amounts in thousands, except per share amounts)
First Second Third Fourth
quarter quarter quarter quarter Year
------- ------- ------- ------- -------
Year ended December 31, 2001:
Revenues............................ $13,769 $12,756 $13,807 $10,942 $51,274
Gross profit(/1/)................... 9,925 6,249 5,468 (17,194) 4,448
Income from operations.............. 9,446 5,738 4,729 (17,724) 2,189
Net income (loss)(/2/).............. 6,206 2,599 3,049 (9,808) 2,046
Net income (loss) per share--
basic(/2/)......................... $ 0.71 $ 0.27 $ 0.24 $ (0.77) $ 0.19
Year ended December 31, 2000:
Revenues............................ $ 7,742 $ 9,203 $11,787 $15,841 $44,573
Gross profit(/1/)................... 3,778 4,917 6,850 11,210 26,755
Income from operations.............. 3,394 4,840 6,422 11,015 25,671
Net income (loss)(/3/).............. 1,510 2,330 3,264 5,714 12,818
Net income (loss) per share--
basic(/3/)......................... $ 0.17 $ 0.27 $ 0.38 $ 0.66 $ 1.47
- --------
(/1/Revenues)less operating expenses other than general and administrative and
restructuring costs.
(/2/Included)in the fourth quarter was a $1,092 ($0.10 per share) increase in
the deferred income tax benefit due to a change in the estimated amount of
depletion carryforward.
(/3/Net)income for the second quarter and year are net of a $242 extraordinary
loss ($0.03 per share).
60