================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2002
or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
-----------------
Commission file number 0-22650
-----------------
PETROCORP INCORPORATED
(Exact name of registrant as specified in its charter)
Texas 76-0380430
(State or other
jurisdiction of
incorporation (I.R.S. Employer
organization) Identification No.)
6733 South Yale Avenue 74136
Tulsa, Oklahoma (Zip Code)
(Address of principal
executive offices)
Registrant's telephone number, including area code: (918) 491-4500
-----------------
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]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). [_] Yes [X] No
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of June 30, 2002 was $47,152,755. Indicate the number of shares
outstanding of each of the registrant's classes of common stock, as of February
28, 2003:
Common Stock, par value $.01 per share: 12,648,309
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held in 2003 (to be filed within 120 days of the close of registrant's fiscal
year) is incorporated by reference into Part III.
================================================================================
TABLE OF CONTENTS
Item Title Page
---- ----- ----
PART I
1. Business............................................................................. 1
2. Properties........................................................................... 6
3. Legal Proceedings.................................................................... 15
4. Submission of Matters to a Vote of Security Holders.................................. 15
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters................ 16
6. Selected Financial Data.............................................................. 17
7. Management's Discussion and Analysis of Financial Condition and Results of Operations 18
7A Quantitative and Qualitative Disclosure about Market Risk............................ 24
8. Financial Statements and Supplementary Data.......................................... 24
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 25
PART III
10-13. (Incorporated by reference to Proxy Statement)....................................... 25
14. Controls and Procedures.............................................................. 25
PART IV
15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................... 26
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.
The Company makes available its periodic and current reports, free of
charge, on its web site, www.PetroCorp.com, as soon as reasonably practicable
after such material is electronically filed with, or furnished to, the SEC.
FORWARD LOOKING STATEMENTS
All statements other than statements of historical fact contained in this
report and other periodic reports filed by PetroCorp under the Securities
Exchange Act of 1934 and other written or oral statements made by the Company
or on the Company's behalf, are forward-looking statements. When used herein,
the words "anticipates", "expects", "believes", "goals", "intends", "plans", or
"projects" and similar expressions are intended to identify forward-looking
statements. All statements 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 statement. It
is important to note that forward looking statement are based on a number of
assumptions about future events and are subject to various risks, uncertainties
and other factors that may cause the Company's actual results to differ
materially from the views, beliefs and estimates expressed or implied in such
forward-looking statement. Although the Company believes that the assumptions
on which any forward-looking statements in this report and other periodic
reports filed by us are reasonable, no assurance can be given that such
assumptions will prove correct. All forward-looking statements in this Report
are expressly qualified in their entirety by the cautionary statements in this
paragraph and elsewhere in this report.
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. The information
included in Item 1 and Item 2 relates solely to the Company's continuing
operations.
At December 31, 2002, the Company's proved reserves related to the
continuing operations totaled 2.7 MMBbls of oil and 38.8 Bcf of natural gas and
had an estimated pretax present value of future net revenues (PV-10) of $108
million. On a Mcfe basis, approximately 70% of the Company's proved reserves
were natural gas at such date. In addition, the Company has unproved interest
holdings with a net book value of $233 thousand.
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. In June 2001, the Company acquired Southern
Mineral Corporation through a stock and cash purchase and merged it into
PetroCorp. 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.
Sale of Canadian Subsidiaries
On December 24, 2002, PetroCorp signed an agreement to sell its two Canadian
subsidiaries, PCC Energy Inc. and PCC Energy Corp. for C$167.6 million
(approximately US$112 million), with an economically effective
1
date of October 1, 2002. The sale, which closed on March 5, 2003, is subject to
post closing adjustments for certain working capital items. As of December 31,
2002, the combined reserves of the Canadian subsidiaries were 2,458 MBbls and
50,799 MMcf. The financial statements reflect the results of the Canadian
operations as discontinued operations and segregate the Canadian assets and
liabilities at December 31, 2002. Prior year statements of operations have been
restated to conform to the current year presentation. Discontinued operations
for 2002 include $24.0 million of revenue ($6.7 million revenue and 1,861 MMcf
equivalent production in the fourth quarter) and $8.0 million of pre-tax income
($3.0 million earned in the fourth quarter). The corresponding discontinued
operations revenue and pre-tax income for 2001 and 2000 were $26.0 million and
$21.0 million revenue and $11.7 million and $13.3 million pre-tax income,
respectively.
Business Strategy
PetroCorp acquires, explores and develops 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 significant portion of cash flows to exploration and development
activities.
Acquisition, Exploration and Development Activities
Among the 11 wells in which the Company participated during 2002, the
Company drilled a 100% working interest, 7800 foot Miocene gas well in State of
Texas waters off Matagorda Island and completed and put on production a 3 MMcfe
per day well in Alta Loma field in Galveston, Texas. Additionally, the Company
participated in a multi-pay well in Louisiana. These are described more fully
in the Principal Properties section of Item 2.
At year-end 2002, PetroCorp was not participating in any significant
exploratory projects.
PetroCorp sold substantially all of its Alabama producing properties and
interest in a related gas processing plant for $11.5 million in the fourth
quarter of 2002. As described previously in Item 1, on December 24, 2002 the
Company entered into an agreement to sell its Canadian subsidiaries and closed
that sale March 5, 2003.
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,
2002, 2001, and 2000. Hedging activity caused oil sales to decrease by $83,000
($0.17 per Bbl) in 2002, increase by $51,000 ($0.13 per Bbl) in 2001 and
decrease by $1,035,000 ($3.52 per Bbl) in 2000. Hedging activity caused gas
sales to increase by $506,000 ($0.10 per Mcf) and $136,000 ($0.03 per Mcf) in
2002 and 2001, respectively, and decrease by $62,000 ($0.02 per Mcf) in 2000.
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 operations.
Year Ended December 31,
-----------------------
2002 2001 2000
------ ------ ------
Net oil produced (MBbls)......... 479 396 294
Net gas produced (MMcf).......... 5,089 4,498 3,850
Gas equivalents produced (MMcfe). 7,963 6,874 5,614
Average oil sales price (per Bbl) $23.95 $23.61 $26.38
Average gas sales price (per Mcf) $ 3.13 $ 3.47 $ 4.08
Average sales price (per Mcfe)... $ 3.44 $ 3.63 $ 4.18
Production costs (per Mcfe)...... $ 1.31 $ 1.27 $ 1.04
2
Marketing
PetroCorp's 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.
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, 2002, EOTT Energy Trading Partnership
Ltd. and Sunoco, Inc. accounted for 16% and 12% 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 as well.
Regulation
General. The Company's business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation and tax laws.
For example, state and federal agencies have issued rules and regulations that
require permits for the drilling of wells, regulate the spacing of wells,
prevent the waste of reserves through proration, and regulate oilfield and
pipeline environmental and safety matters. Changes in any of these laws could
have a material adverse effect on the Company's business, and the Company
cannot predict the overall effects of such laws and regulations on its future
operations. Although these regulations have an impact on the Company and others
in the oil and gas industry, the Company does not believe that it is affected
in a significantly different manner by these regulations than are its
competitors in the oil and gas industry.
The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.
Regulation of Transportation and Sale of Natural Gas and Oil. Various
aspects of the Company's oil and gas operations are regulated by agencies of
the federal government. The transportation of natural gas in interstate
commerce is generally regulated by the Federal Energy Regulatory Commission
(FERC) pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas
Policy Act of 1978 (NGPA). The intrastate transportation and gathering of
natural gas (and operational and safety matters related thereto) may be subject
to regulation by state and local governments.
In the past, the federal government regulated the prices at which the
Company's produced oil and gas could be sold. Currently, "first sales" of
natural gas by producers and marketers, and all sales of crude oil, condensate
and natural gas liquids, can be made at uncontrolled market prices, but
Congress could reenact price controls at any time.
Since 1985, 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 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
3
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.
Production Regulation. The production of oil and natural gas is subject to
regulation under a wide range of local, state and federal statutes, rules,
orders and regulations. Federal, state and local statutes and regulations
require permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which the Company owns and operates properties have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum allowable rates of production from oil and natural gas wells, the
regulation of well spacing, and plugging and abandonment of wells. Many states
also restrict production to the market demand for oil and natural gas, and
several states have indicated interest in revising applicable regulations. The
effect of these regulations is to limit the amount of oil and natural gas that
the Company can produce from its wells and to limit the number of wells or the
locations at which the Company can drill. Moreover, each state generally
imposes a production or severance tax with respect to the production and sale
of oil, natural gas and natural gas liquids within its jurisdiction.
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
4
legislation were to be enacted, it could have a significant impact on the
operating costs of the Company, as well as the oil and gas industry in general.
Also 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.
Employees
At December 31, 2002, PetroCorp had two full-time employees, Gary R.
Christopher, President, and Richard L. Dunham, Executive Vice-President.
Operations and activities not conducted by Messrs. Christopher and Dunham are
conducted through the Management Agreement with Kaiser-Francis Oil Company.
5
Item 2. Properties.
Principal Properties
The Company's proved oil and gas properties are relatively concentrated.
Approximately 90% of the PV-10 from the Company's proved reserves at December
31, 2002 was attributable to five principal areas.
The following table presents data regarding the estimated quantities of
proved oil and gas reserves and the PV-10 attributable to the Company's
principal properties as of December 31, 2002, in accordance with the rules and
regulations of the Securities and Exchange Commission (SEC).
December 31, 2002
----------------------------------------
Estimated Proved Reserves
-------------------------
Oil Gas
Property/Area (MBbls) (MMcf) MMcfe PV-10
------------- ------- ------ ------ --------------
(in thousands)
Gulf Coast Area.......... 280 5,680 7,360 $ 21,004
Gulf Coast, TX Area...... 154 10,663 11,587 19,650
Mid-Continent Waterfloods 1,147 1,466 8,348 13,460
Mid-Continent Area....... 171 14,100 15,126 25,962
Gulf Coast Offshore...... 268 4,687 6,295 17,819
----- ------ ------ --------
Subtotal.............. 2,020 36,596 48,716 97,895
----- ------ ------ --------
Others................... 689 2,164 6,298 10,519
----- ------ ------ --------
Total................. 2,709 38,760 55,014 $108,414
===== ====== ====== ========
Gulf Coast Area. PetroCorp owns various interests in onshore Gulf Coast
properties in Louisiana and Mississippi. With the sale of the Big Excambia
Creek properties in 2002, there are only minor properties remaining in Alabama.
The primary Gulf Coast fields include East Riceville, Scott, Lake Raccourci and
Leeville. East Riceville in Vermillion Parish, Louisiana 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. The Scott Field in Lafayette Parish,
Louisiana has recently increased to 6 MMcf/d from the Bol Mex 3 in the Martin
Heirs #1, of which PetroCorp owns approximately 10%.
Gulf Coast, TX Area. Includes a new well in the Alta Loma Field in
Galveston County, Texas. The Sunny Ernst #1 (25% PetroCorp working interest) is
producing 3 MMcf/d and 75 barrels of condensate per day from a Tacquard zone at
14,900 feet. Other significant fields include Hallettsville, Harris and Yoakum.
The Yoakum Field in Lavaca County, Texas contains Wilcox pays, including behind
pipe recompletions, plus current and future Edwards horizontal production.
Mid-Continent Waterfloods. The Mid-Continent waterfloods group includes the
SW Oklahoma City waterflood located within the metropolitan Oklahoma City area.
PetroCorp operates 63 wells targeting the Prue formation at 6,500 feet. Current
unit production has increased to over 450 bo/d and PetroCorp owns an 86.4%
working interest. Other fields include West Hunter, a Misner waterflood and the
Will Rogers Unit.
Mid-Continent Area. The Mid-Continent area consists primarily of gas fields
scattered throughout Western Oklahoma. Of note is the deep Cement Field in
Caddo County, Oklahoma, where PetroCorp has participated with up to a 10% WI in
wells drilled below 15,000 feet to the Boatwright. Other fields include
Cheyenne and Eakly Weatherford, which are mature, deep gas wells. PetroCorp
also has a significant interest in the Glick Field in south-central Kansas.
6
Gulf Coast Offshore. The Offshore area is comprised of three fields, all in
state waters. North Cove is in State of Texas waters off Matagorda Island where
PetroCorp drilled a successful 100% working interest Miocene gas well to 7,800
feet. Production should commence in May 2003. PetroCorp holds additional
acreage on the play. Breton Sound is in State of Louisiana waters near the
mouth of the Mississippi River. PetroCorp participated with 26% interest in a
multi-pay well drilled below 10,000 feet. Production should commence in the
spring of 2003. The third field, South Timbalier Block 198, is located in the
state waters of Louisiana.
Title to Properties
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 certain 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.
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 Ryder Scott Company, L.P. ("Ryder Scott") (the
Independent Engineers). Ryder Scott reviewed approximately 85% of the present
value of future net revenues. 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, 2002.
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
prices used in determining future cash inflows for natural gas and oil as of
December 31, 2002, were $4.59 per Mcf and $31.20 per barrel, respectively.
These prices were based on the cash spot price for natural gas and oil at
December 31, 2002.
December 31,
2002
------------
Proved reserves:
Oil (MBbls).............................. 2,709
Gas (MMcf)............................... 38,760
Gas equivalents (MMcfe).................. 55,014
Future net revenues ($000s)................. $174,041
Present value of future net revenues ($000s) $108,414
Proved developed reserves:
Oil (MBbls).............................. 2,147
Gas (MMcf)............................... 34,317
Gas equivalents (MMcfe).................. 47,199
Future net revenues ($000s)................. $152,894
Present value of future net revenues ($000s) $ 96,421
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
7
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, 2002.
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, 2002.
Undeveloped
Developed Acres Acres(1)
-------------- -------------
Gross Net Gross Net
------- ------ ------ ------
Alabama.... 960 40 -- --
Colorado... 10,186 7,958 -- --
Kansas..... 5,360 667 10 1
Louisiana.. 13,795 2,610 9,421 1,632
Mississippi 2,880 487 6,096 5,054
Oklahoma... 40,434 10,230 11,445 4,385
Texas...... 50,109 12,577 28,675 8,370
Wyoming.... 5,655 774 5,109 480
Other...... 800 204 14,259 5,031
------- ------ ------ ------
Total... 130,179 35,547 75,015 24,953
======= ====== ====== ======
--------
(1) Approximately 9% of net undeveloped acres are covered by leases that expire
during 2003, unless drilling or production otherwise extends lease terms.
As of December 31, 2002, the Company had working interests in 271 gross (101
net) producing oil wells and 218 gross (55 net) producing gas wells 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, 2002, 2001 and 2000 is set forth below:
Year Ended December 31,
-----------------------------------------
2002 2001 2000
-------------- -------------- -----------
Net Net Net
Working Working Working
Type of Well Gross Interest Gross Interest Gross Interest
------------ ----- -------- ----- -------- ----- --------
Development:
Oil........... 2 .6 3 .1 4 .2
Gas........... 5 2.3 8 1.0 5 .3
Nonproductive. -- -- 3 .2 1 .2
-- --- -- --- -- --
Total..... 7 2.9 14 1.3 10 .7
-- --- -- --- -- --
Exploratory:
Oil........... 3 1.3 1 .1 -- --
Gas........... -- -- 3 .5 -- --
Nonproductive. 1 .2 2 .2 1 .0/(1)/
-- --- -- --- -- --
Total......... 4 1.5 6 .8 1 .0
-- --- -- --- -- --
Total............ 11 4.4 20 2.1 11 .7
== === == === == ==
--------
/(1)/ The Company has a net working interest of less than 0.05% in this well.
At December 31, 2002, the Company was not participating in the drilling of
any wells.
Other Facilities
The Company leases, and subleases to others, approximately 10,000 square
feet in Houston, Texas where the Southern Mineral offices were located. The
obligation under these leases will end in 2003. 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.
9
RISK FACTORS
Oil price declines and volatility could adversely affect the Company's
revenues, cash flows and profitability.
The Company's revenues, profitability and future rate of growth depend
substantially upon the prevailing prices of oil and gas. Because approximately
70% of the Company's estimated proved reserves as of December 31, 2002 were
natural gas reserves, the Company's financial results are more sensitive to
movements in natural gas prices.
Natural gas and oil and are commodities and, therefore, their prices are
subject to wide fluctuations in response to relatively minor changes in supply
and demand; these changes may arise from:
. weather conditions,
. the ability of the members of OPEC to agree to and maintain oil price and
production controls,
. political instability or armed conflict in oil-producing regions,
. the price and availability of alternative fuels,
. the availability of pipeline capacity, and
. domestic and foreign governmental regulations and taxes.
Historically, the markets for natural gas and oil have been volatile, and
they are likely to continue to be volatile in the future. For example, natural
gas and oil prices declined significantly in late 1997, 1998, and early 1999,
and, for an extended period of time, remained substantially below prices
obtained in previous years. Also, prices at December 31, 2002 were
substantially higher than prices at the end of 2001. Lower oil and gas prices
may reduce the amount of oil and gas the Company produces. Significant
reductions in oil and gas prices may require the Company to reduce its capital
expenditures. Reducing drilling will make it more difficult for the Company to
replace the reserves it produces.
If the Company is not able to replace reserves, it may not be able to sustain
current production rates.
The Company's future success depends largely upon its ability to find,
develop or acquire additional oil and gas reserves that are economically
recoverable. Unless the Company replaces the reserves it produces through
successful development, exploration or acquisition, its proved reserves will
decline over time. In addition, approximately 14% by volume of its total
estimated proved reserves at December 31, 2002 were undeveloped. By their
nature, undeveloped reserves are less certain. Recovery of such reserves will
require significant capital expenditures and successful drilling operations.
The Company may fail to successfully find and produce reserves economically in
the future. Drilling levels required to replace reserves will likely increase
the Company's exposure to drilling risk.
If the Company does not make significant capital expenditures, it may not be
able to exploit reserves.
The Company must make substantial capital expenditures in connection with
the exploration, development and production of its oil and gas properties. The
Company intends to finance its capital expenditures primarily with existing
cash and cash equivalents, funds provided by operations and borrowings under
its credit agreement. If the Company's cash flow from operations and
availability under existing credit facilities are not sufficient to satisfy
capital expenditure requirements, additional debt or equity financing may not
be available to allow it to fund its continued growth. The Company has a $75
million revolving credit facility with a borrowing base at December 31, 2002 of
$70 million (reduced to $25 million in March 2003.) The company estimates
capital expenditures for 2003 to be approximately $10 million.
10
Reserve estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and net present value of our
reserves.
The calculations of proved reserves of oil and gas included in this document
have been prepared by the Company and reviewed by independent petroleum
engineers retained by the Company. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretations and judgment and the assumptions used regarding quantities of
recoverable oil and natural gas reserves and prices for crude oil and natural
gas. Any significant variance between the assumptions used in our estimates and
the actual data could result in the actual quantity of our reserves and future
net cash flow being materially different from the estimates in the Company's
reserve reports. In addition, results of drilling, testing and production and
changes in crude oil and natural gas prices after the date of the estimate may
result in substantial upward or downward revisions.
Also, the Company may adjust estimates of proved reserves to reflect
production history, results of exploration and development, prevailing natural
gas and oil prices and other factors, many of which are beyond our control. At
December 31, 2002, 40% of the Company's proved reserves were proved undeveloped
or proved non-producing. Further, because most of the Company's reserve
estimates are not based on a lengthy production history and are calculated
using volumetric analysis, these estimates are less reliable than estimates
based on a lengthy production history.
Shareholders should not assume that the present value of future net cash
flows from the Company's proved reserves included or incorporated by reference
in this report is the current market value of the Company's estimated natural
gas and oil reserves. In accordance with SEC requirements, the Company bases
the estimated discounted future net cash flows from the Company's proved
reserves on prices and costs on the date of the estimate, which may vary
materially from actual future prices and costs.
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.
The Company's industry experiences numerous operating and exploration risks.
Insurance may not be adequate to protect the Company against all these risks.
Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil and gas reserves
will be found. The cost of drilling and completing wells is often uncertain.
Oil and gas drilling and production activities may be shortened, delayed or
canceled as a result of a variety of factors, many of which are beyond our
control, including:
. pressure or irregularities in formations;
. equipment and materials failures or accidents;
. blowouts and surface cratering;
11
. fires and explosions;
. uncontrollable flows of oil and formation water; and
. environmental hazards such as oil spills, pipeline ruptures and
discharges of toxic gases.
If any of these events occur, we could incur substantial losses as a result
of:
. injury or loss of life;
. severe damage to and destruction of property, natural resources and
equipment;
. pollution and other environmental damage;
. regulatory investigation and penalties;
. suspension of our operations; and
. repairs to resume operations.
The Company's insurance does not protect us against all operational risks.
The Company does not carry business interruption insurance at levels that would
provide enough funds for the Company to continue operating without access to
other funds. For some risks, the Company may not obtain insurance if it
believes the cost of available insurance is excessive relative to the risks
presented. Because third party drilling contractors are used to drill the
Company's wells, the Company not may not realize the full benefit of workmen's
compensation laws in dealing with their employees. In addition, pollution and
environmental risks generally are not fully insurable.
Marketability of the Company's production may be affected by factors beyond its
control.
The marketability of the Company'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, state and local 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.
The Company may be unable to identify liabilities associated with the
properties that it acquires or obtain protection from sellers against them.
The successful acquisition of producing properties involves an assessment of
recoverable reserves, future oil and gas prices, operating costs, potential
environmental and other liabilities and other factors beyond the Company's
control. This assessment is inexact and uncertain. In connection with this
assessment the Company will perform a review of the subject properties, but
this review will not reveal all existing or potential problems. Inspections may
not be performed on every well, and structural and environmental problems are
not necessarily observable even when an inspection is undertaken. The Company
may in many cases assume pre-closing liabilities, including environmental
liabilities, and will likely acquire interests in properties on an "as is"
basis. The Company's acquisitions may be unsuccessful. The failure of the
Company to successfully complete acquisitions could have a material adverse
effect on the Company.
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.
12
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 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.
Hedging Activities
The Company periodically utilizes energy swap arrangements and futures
transactions 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. The company had no hedging contracts
at December 31, 2002.
The Company's articles of incorporation, bylaws and rights plan discourage
corporate takeovers and could prevent shareholders from realizing a premium on
their investment.
The Company's articles of incorporation and bylaws and provisions of the
Texas Business Corporation Act may have the effect of delaying or preventing a
change in control. The Company's directors are elected to staggered terms.
Also, the Company's articles of incorporation authorize the Company's board of
directors to issue preferred stock without shareholder approval and to set the
rights, preferences and other designations, including voting rights of those
shares as the board may determine, and the Company has available authorized
13
but unissued common stock. In addition, the Company has adopted a rights plan,
as further which could, alone or in combination with the articles of
incorporation and the bylaws, discourage transactions involving actual or
potential changes of control, including transactions that otherwise could
involve payment of a premium over prevailing market prices to shareholders for
their common stock.
Costs to comply with environmental laws and governmental regulations are
significant.
Environmental and other governmental laws, some of which are applied
retroactively, have increased the costs to plan, design, drill, install,
operate and abandon oil and natural gas wells and related facilities. The
Company may be required to make large expenditures to comply with environmental
laws.
Under these laws and regulations, the Company could be liable for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. The Company
does not believe that full insurance coverage for all potential environmental
damages is available at a reasonable cost. Failure to comply with these laws
and regulations also may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties.
Moreover, these laws and regulations could change in ways that substantially
increase our costs. For example, Congress or the Minerals Management Service
could decide to limit exploratory drilling or natural gas production in some
areas of the Gulf of Mexico. Accordingly, any of these liabilities, penalties,
suspensions, terminations or regulatory changes could materially and adversely
affect the Company's financial condition and results of operations.
A small number of shareholders control the Company, making it difficult for the
Company's other shareholders to affect the Company's management.
Directors, executive officers and principal shareholders of the Company, and
their affiliates, beneficially own approximately 55% of the Company, including
approximately 38% owned by Kaiser-Francis. Accordingly, these shareholders, as
a group, will be able to control the outcome of shareholder votes, including
votes concerning the election of directors, the adoption or amendment of
provisions in the Company's articles of incorporation or bylaws, and the
approval of mergers and other significant corporate transactions. The existence
of these levels of ownership concentrated in a few persons makes it unlikely
that any other holder of the Company's common stock will be able to affect the
management or direction of the Company. These factors may also have the effect
of delaying or preventing a change in the management or voting control of the
Company, including transactions that otherwise could involve payment of a
premium over prevailing market prices to holders of the Company's common stock.
The Company may not pay dividends on its 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 has not determined if it will
declare cash dividends on its Common Stock in the foreseeable future. Any
future cash dividends would depend on the availability of investment
opportunities, 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 and would need to be modified before any dividends
could be declared.
14
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.
15
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 2001 and 2002,
and for a portion of the Company's current quarter, as reported by the AMEX.
2001 2002 2003
------------------------------- ------------------------------- ------------
First
Quarter
First Second Third Fourth First Second Third Fourth (through
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter February 28)
------- ------- ------- ------- ------- ------- ------- ------- ------------
High $10.63 $10.70 $9.88 $9.50 $10.11 $9.95 $9.60 $10.25 $10.70
Low. 9.62 9.37 8.60 8.70 8.70 9.11 8.06 8.20 10.18
As of February 28, 2003, there were approximately 1,500 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 has not determined if it will
declare cash dividends on its Common Stock in the foreseeable future. Any
future cash dividends would depend on the availability of investment
opportunities, 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 and would need to be modified before any dividends
could be declared.
The equity compensation plan information required by Item 201 of Regulation
S-X will be included in the Company's proxy, and is herewith incorporated by
reference.
16
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,
------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
Income Statement Data:
Revenues:
Oil and gas............................... $ 27,363 $ 24,970 $ 23,481 $ 15,505 $ 15,911
Other..................................... 312 199 107 60 --
-------- -------- -------- -------- --------
27,675 25,169 23,588 15,565 15,911
-------- -------- -------- -------- --------
Expenses:
Production costs.......................... 10,451 8,704 5,813 4,555 5,171
Depreciation, depletion and amortization.. 8,002 9,616 5,178 6,134 12,821
Oil and gas property valuation adjustment. -- 15,400 -- -- 33,600
General and administrative................ 1,838 933 428 2,507 2,462
Restructuring costs....................... -- -- (425) 3,251 --
Other operating expenses.................. 98 169 243 220 219
-------- -------- -------- -------- --------
20,389 34,822 11,237 16,667 54,273
-------- -------- -------- -------- --------
Income (loss) from operations................ 7,286 (9,653) 12,351 (1,102) (38,362)
-------- -------- -------- -------- --------
Other income (expenses):
Investment income......................... 70 65 251 413 694
Interest expense.......................... (1,566) (1,237) (2,895) (3,318) (2,946)
Other income (expenses)................... 565 921 (257) (175) 12
-------- -------- -------- -------- --------
(931) (251) (2,901) (3,080) (2,240)
-------- -------- -------- -------- --------
Income (loss) before income taxes............ 6,355 (9,904) 9,450 (4,182) (40,602)
-------- -------- -------- -------- --------
Income tax provision (benefit):
Current................................... (13) 157 -- -- --
Deferred.................................. 2,133 (4,769) 3,662 (1,155) (15,168)
-------- -------- -------- -------- --------
2,120 (4,612) 3,662 (1,155) (15,168)
-------- -------- -------- -------- --------
Income (loss) from continuing operations..... 4,235 (5,292) 5,788 (3,027) (25,434)
Income from discontinued operations.......... 4,449 7,338 7,030 2,821 1,039
-------- -------- -------- -------- --------
Net income (loss)............................ $ 8,684 $ 2,046 $ 12,818 $ (206) $(24,395)
======== ======== ======== ======== ========
Income (loss) per share--basic:
Continuing operations..................... $ 0.34 $ (0.48) $ 0.66 $ (0.35) $ (2.94)
Discontinued operations................... $ 0.35 $ 0.67 $ 0.81 $ 0.33 $ 0.12
-------- -------- -------- -------- --------
Net income................................ $ 0.69 $ 0.19 $ 1.47 $ (0.02) $ (2.82)
======== ======== ======== ======== ========
Income (loss) per share--diluted:
Continuing operations..................... $ 0.34 $ (0.48) $ 0.66 $ (0.35) $ 2.94
Discontinued operations................... $ 0.35 $ 0.66 $ 0.80 $ 0.33 $ 0.12
-------- -------- -------- -------- --------
Net income................................ $ 0.69 $ 0.18 $ 1.46 $ (0.02) $ (2.82)
======== ======== ======== ======== ========
Weighted average number of common
shares--basic.............................. 12,584 10,975 8,692 8,658 8,637
======== ======== ======== ======== ========
Weighted average number of common shares--
diluted.................................... 12,676 11,119 8,786 8,658 8,637
======== ======== ======== ======== ========
Balance Sheet Data (at December 31):
Working capital........................... $ 55,795 $ 4,031 $ 9,029 $ 3,642 $ 2,080
Total assets.............................. 161,581 165,355 117,319 105,395 103,992
Long-term debt............................ 28,750 47,620 29,992 43,410 47,305
Shareholders' equity...................... 100,595 91,915 54,277 42,363 40,744
17
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.
On December 24, 2002, PetroCorp signed an agreement to sell its two Canadian
subsidiaries, PCC Energy Inc. and PCC Energy Corp. for C$167.6 million
(approximately US$112 million), with an economically effective date of October
1, 2002. The sale, which closed on March 5, 2003, is subject to post closing
adjustments for certain working capital items. As of December 31, 2002, the
combined reserves of the Canadian subsidiaries were 2,458 MBbls and 50,799
MMcf. The financial statements reflect the results of the Canadian operations
as discontinued operations and segregate the Canadian assets and liabilities at
December 31, 2002. Prior year statements of operations have been restated to
conform to the current year presentation. Discontinued operations for 2002
include $24.0 million of revenue ($6.7 million revenue and 1,861 MMcf
equivalent production in the fourth quarter) and $8.0 million of pre-tax income
($3.0 million earned in the fourth quarter). The corresponding discontinued
operations revenue and pre-tax income for 2001 and 2000 were $26.0 million and
$21.0 million revenue and $11.7 million and $13.3 million pre-tax income,
respectively.
The following table reflects certain operating data for the continuing
operations of the Company for the periods presented:
For the Year Ended
December 31,
--------------------
2002 2001 2000
------ ------ ------
Production:
Oil (MBbls).......................................... 479 396 294
Gas (MMcf)........................................... 5,089 4,498 3,850
Gas equivalents (MMcfe).............................. 7,963 6,874 5,614
Average sales prices:
Oil (per Bbl)........................................ $23.95 $23.61 $26.38
Gas (per Mcf)........................................ 3.13 3.47 4.08
Selected data per Mcfe:
Average sales price.................................. $ 3.44 $ 3.63 $ 4.18
Production costs..................................... 1.31 1.27 1.04
General and administrative expenses.................. 0.23 0.14 0.08
Oil and gas depreciation, depletion and amortization. 0.99 1.38 0.85
18
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.
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 Ryder
Scott Company, independent petroleum consultants, to annually 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,
depletion and amortization, for tax and accounting purposes. These differences
and the net operating loss and statutory depletion 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.
Examples of temporary differences include the expensing of intangible
drilling costs for tax purposes while such costs are capitalized as part of the
full cost pool for financial purposes. Another example is accelerated
19
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.
A summary of the Company's accounting policies is included 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. Administration fees and
cost reimbursements for 2002, 2001, and 2000 respectively, were $3,146,000,
$3,064,000 and $2,076,000 ($1,965,000, $2,176,000, and $1,419,000 for
administration fees). Of the administrative fees, $1,498,000, $1,693,000, and
$1,234,000, respectively, relate to continuing operations covered under the
Management Agreement.
Results of Operations
2002 Compared to 2001
Revenues. Total revenues increased 10% to $27.7 million in 2002 compared to
$25.2 million in 2001. Oil production increased 21% to 479 MBbls from 396
MBbls. Natural gas production increased 13% to 5,089 MMcf from 4,498 MMcf,
resulting in overall production increasing 16% to 7,963 MMcfe from 6,874 MMcfe.
Production increases are primarily due to having a full year of production from
properties in the merger with Southern Mineral in June 2001.
The Company's average U.S. natural gas price decreased 10% to $3.13 per Mcf
in 2002 from $3.47 per Mcf in 2001. The Company's average oil price increased
1% to $23.95 per barrel in 2002 from $23.61 per barrel in 2001. Of the
$2,393,000 increase in oil and gas sales in 2002, approximately $4 million was
attributable to increased production of oil and gas, $160,000 was attributable
to the increase in the average price of oil, and these were partially offset by
$1,767,000 of lower average gas prices.
Production Costs. Production costs increased 20% to $10.5 million in 2002
compared to $8.7 million in 2001 as a result of the acquisition of Southern
Mineral in June 2001. Production costs per Mcfe were $1.31 for 2002 and $1.27
for 2001.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 17% to
$8.0 million in 2002 from $9.6 million in 2001. The decrease in the oil and gas
DD&A rate per Mcfe to $0.99 in 2002 from $1.38 in 2001 reflects the impact of
the higher year-end reserve quantities associated with higher prices.
20
General and Administrative Expenses. General and administrative expenses
increased 97% to $1.8 million in 2002 from $0.9 million in 2001 due to office
close down costs and higher management fees, both related to the merger with
Southern Mineral.
Investment Income. Investment income increased 8% to $70,000 in 2002 from
$65,000 in 2001 due to more cash being retained as temporary investments prior
to debt payment.
Interest Expense. Interest expense increased 27% to $1.6 million in 2002
from $1.2 million in 2001, primarily due to the additional debt from the
purchase of Southern Mineral, partially offset by lower interest rates.
Income Taxes. The Company recorded a $2.1 million income tax expense on
pre-tax income of $6.4 million in 2002 compared to an income tax benefit of
$4.6 million on pre-tax loss of $9.9 million in 2001. Effective tax rates were
33% and 47%, respectively, in 2002 and 2001. Effective tax rates differed from
statutory rates primarily due to statutory depletion.
2001 Compared to 2000
Revenues. Total revenues increased 7% to $25.2 million in 2001 compared to
$23.6 million in 2000. Oil production increased 35% to 396 MBbls from 294
MBbls. Natural gas production increased 17% to 4,498 MMcf from 3,850 MMcf,
resulting in overall production increasing 22% to 6,874 MMcfe from 5,614 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. The Company's average oil price decreased
11% to $23.61 per barrel in 2001 from $26.38 per barrel in 2000. Of the
$1,489,000 increase in oil and gas sales in 2001, approximately $5.3 million
was due to increased production of oil and gas, partially offset by $2.7
million and $1.1 million of lower gas and oil prices, respectively.
Production Costs. Production costs increased 50% to $8.7 million in 2001
compared to $5.8 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 $1.27 for 2001 and $1.04 for 2000. Approximately
$0.12 per Mcfe of increased costs are due to increased workover operations.
Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 86% to
$9.6 million in 2001 from $5.2 million in 2000. The increase in the oil and gas
DD&A rate per Mcfe to $1.38 in 2001 from $0.85 in 2000 reflects the impact of
Southern Mineral properties added through the merger in June 2001 and lower
year-end reserve quantities 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 118% to $0.9 million in 2001 from $0.4 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 74% to $65,000 in 2001 from
$251,000 in 2000 due to excess cash being used to pay down debt.
Interest Expense. Interest expense decreased 57% to $1.2 million in 2001
from $2.9 million in 2000, primarily due to decreases in interest rates.
21
Income Taxes. The Company recorded a $4.6 million income tax benefit on a
pre-tax loss of $9.9 million in 2001 compared to an income tax expense of $3.7
million on pre-tax income of $9.5 million with an effective tax rate of 39% in
2000. During 2001, the Company recorded a $4.6 million tax benefit 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 statutory depletion in the
United States.
Liquidity and Capital Resources
As of December 31, 2002, the Company had working capital of $55.8 million as
compared to $4.0 million at December 31, 2001. Cash provided by operating
activities was $24.0 million, $13.1 million and $33.2 million in 2002, 2001 and
2000, respectively.
The Company's total capital expenditures were $8.3 million, $93.8 million
($38.5 million cash), and $7.2 million for 2002, 2001 and 2000, respectively.
In 2002, the Company spent $8.9 million related to exploration and development.
During 2001, the Company spent $12.1 million related to exploration and
development and $76.3 million ($21.0 million of cash expenditures) related to
the acquisition of Southern Mineral. In 2000, the Company spent $1.5 million
related to exploration and development.
In July 2000, the Company entered into a $75 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The agreement was amended in August 2002 to extend its term,
increase the borrowing base, and partially change the lenders. The amended term
of the facility is through May 1, 2004 and the amended borrowing base was set
at $70 million. The current lenders are TD Bank, as agent, and Fortis Capital
Corp. and Bank of Oklahoma, N.A. (Bank of Oklahoma, N.A.'s largest beneficial
owner is also the primary beneficial owner of Kaiser-Francis Oil Company.
Approximately 38% of the Company is owned by Kaiser-Francis Oil Company.)
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 rate 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, 2002, the
Company had a total of $28.8 million outstanding under the revolver and $41.2
million available based on the current borrowing base, as defined, subject to
certain limitations. During 2002 and 2001, the average interest rate under this
facility was approximately 4.1% and 5.8%. At December 31, 2002, the weighted
average interest rate under this facility was approximately 4.25%.
The above described borrowing arrangement is the Company's only long-term
(over one year) contractual obligation.
Effective in March 2003, and in conjunction with the sale of Canadian
subsidiaries described in Note 2, the Company amended its revolving credit
agreement to adjust the borrowing base to $25 million, allocated entirely to
United States borrowing. Canadian lenders were released from the agreement. All
outstanding debt was paid off with a portion of the proceeds from the sale.
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.
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, 2002, 305,907 shares have been purchased at a cost
of $2,712,000. On March 17, 2003, the Company announced a stock repurchase plan
under which up to 25% of the Company's common stock could be acquired.
22
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued FAS
No. 142, Goodwill and Other Intangible Assets, and in August 2001, FAS No. 144,
Accounting for Impairment or Disposal of Long-Lived Assets. Effective January
1, 2002, the Company adopted FAS No. 142 and 144. The adoption had no effect on
the Company's financial position or results of operations.
In June 2001, the FASB issued FAS No. 143, Accounting for Asset Retirement
Obligations. FAS 143 is effective for fiscal years beginning after June 15,
2002 (January 1, 2003 for the Company) and establishes an accounting standard
requiring the recording of the fair value of liabilities associated with the
retirement of long-lived assets (mainly plugging and abandonment costs for
depleted wells) in the period in which the liability is incurred (at the time
the wells are drilled). The effect of this standard on the Company's results of
operations and financial condition at adoption is expected to include an
increase in liabilities of approximately $4.6 million; a net increase in
property, plant and equipment of approximately $700,000; and a charge to
income, net of deferred income tax, for the cumulative effect of adopting the
new standard of $2.5 million and a deferred tax asset of $1.4 million.
During 2002, the company adopted FAS No. 145, Recission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. Under the provisions of this standard, gains and losses from
extinguishment of debt generally will no longer be classified as extraordinary
items in the statement of operations. Accordingly, the Company's loss on early
retirement of debt of $385 thousand in the year ended December 31, 2000, which
was previously presented as a net of tax extraordinary item, has been
reclassified in the accompanying financial statements and presented as a
component of other income. This reclassification had no impact on the Company's
financial position, net income or cash flows.
In July 2002, the FASB issued FAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which is effective for exit or disposal
activities initiated after December 31, 2002. Management anticipates the
adoption of FAS No. 146 will not affect the Company's current financial
position or results of operations.
In November 2002, the FASB issued FASB Interpretation ("FIN") 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, including
Indirect Guarantee of Indebtedness of Others. FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions
for initial recognition and measurement should be applied on a prospective
basis to guarantees issued or modified after December 31, 2002. The guarantor's
previous application may not be revised or restated to reflect the effect of
the recognition and measurement provisions of the interpretation. The
disclosure requirements are effective for financial statements of both interim
and annual periods that end after December 15, 2002. The Company is not a
guarantor under any significant guarantees and thus this interpretation is not
expected to have a significant effect on the Company's financial position or
results of operations.
On December 31, 2002, the FASB issued FAS No. 148, Accounting for
Stock-Based Compensation-- Transition and Disclosure--an amendment of FAS 123,
Accounting For Stock-Based Compensation. FAS 148 does not change the provisions
of FAS 123 that permit entities to continue to apply the intrinsic value method
of APB 25, Accounting for Stock Issued to Employees. FAS 148 does require
certain new disclosures in both annual and interim financial statements. The
required annual disclosures were effective immediately for the Company and have
been included in Note 1 of the Company's financial statements. The new interim
disclosure provisions will be effective for the Company in the first calendar
quarter of 2003.
On January 17, 2003, the FASB issued FIN 46, Consolidation of Variable
Interest Entities, An Interpretation of Accounting Research Bulletin No. 51.
The primary objectives of FIN 46 are to provide guidance on how to identify
entities for which control is achieved thought means other than through voting
rights (variable interest entities "VIE" and how to determine when and which
business enterprise should consolidate the VIE. This new
23
model for consolidation applies to an entity in which either (1) the equity
investors do not have a controlling financial interest on (2) the equity
investment at risk is insufficient to finance that entity's activities without
receiving additional subordinated financial support from other parties. The
Company does not expect the adoption of this standard to have any impact on the
financial position and results of operations.
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 (in prior years) 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 periodically utilizes hedging
transactions to manage a portion of its exposure to price fluctuations on its
sales of oil and natural gas. The impact of hedging transactions was an
increase to net revenue of $423,000 and $187,000, respectively for the years
ended December 31, 2002 and 2001. For the year ended December 31, 2000, hedging
transactions reduced revenue by $1,097,000. A change in commodity prices of
$0.10 per MCF of natural gas and $1.00 per barrel of oil would have caused the
Company's 2002 income from operations to change by approximately $1 million.
The merger with Southern Mineral resulted in PetroCorp assuming crude oil
and natural gas costless collars. The impact of these hedging transactions on
2002 financial results increased oil and gas revenues by $31,000 and increased
income from discontinued operations by $222,000. All assumed oil and gas
hedging transactions expired during the fourth quarter of 2002.
In April 2002, the Company entered into a swap transaction covering 8,000
MMBTU of natural gas per day at a price of $3.755 per MMBTU and covering the
period from May 2002 through December 2002. The swap index is NYMEX Henry Hub.
The impact of swap transactions for 2002 was an increase in oil and gas
revenues of $392,000 ($0.08 per Mcf).
Interest Rate Risk
Total debt at December 31, 2002, 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.
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, 2002
is a liability of $182,000. Changes in fair value are recorded in the results
of operations.
Foreign Currency Exchange Rate Risk
Prior to the sale of its Canadian subsidiaries (see Part I, Sale of Canadian
Subsidiaries), the Company conducted a significant portion of its business in
the Canadian dollar and was 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.
24
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,
Items 10 through 13 of Part III of this Report are 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, 2002 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).
Item 14. Controls and Procedures
Within 90 days before filing this Form 10-K, our Chief Executive Officer and
our Chief Financial Officer evaluated the effectiveness of the design and
operation of our disclosure controls and procedures. Our disclosure controls
are the controls and other procedures that we designed to ensure that we
record, process, summarize and report in a timely manner the information we
must disclose in reports that we file with the SEC. Our disclosure controls and
procedures include our internal accounting controls. Based on the evaluation of
our Chief Executive Officer and our Chief Financial Officer, our disclosure
controls and procedure controls are effective. There were no significant
changes in our internal controls or in other factors that could significantly
affect these controls subsequent to the date of our evaluation.
25
PART IV
Item 15. 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.............................................................. 33
Consolidated Balance Sheets as of December 31, 2002 and December 31, 2001...................... 34
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000..... 35
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2002, 2001 and
2000......................................................................................... 36
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000..... 37
Notes to Consolidated Financial Statements..................................................... 39
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.
26
4.3* Specimen certificate for shares of Common Stock. Incorporated by reference to Exhibit 4.1 to the
Registration Statement.
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.
27
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.
10.24 Share Purchase Agreement, dated December 24, 2002, between PetroCorp Incorporated, PetroCorp
Acquisition Company, 1022694 Alberta Ltd. and Enermark, Inc.
21 List of material subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Ryder Scott Company
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.
28
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)
By: /s/ GARY R. CHRISTOPHER
-----------------------------
Gary R. Christopher
President and Chief Executive
Officer (Principal Executive
Officer)
Date: March 20, 2003
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 20, 2003
----------------------------- Officer (Principal
Gary R. Christopher Executive Officer) and
Director
/s/ STEVEN R. BERLIN Vice President--Finance, March 20, 2003
----------------------------- Secretary & Treasurer
Steven R. Berlin (Principal Financial
Officer and Principal
Accounting Officer) and
Director
/s/ STEVEN E. AMOS Controller March 20, 2003
-----------------------------
Steven E. Amos
/s/ LEALON L. SARGENT Chairman of the Board of March 20, 2003
----------------------------- Directors
Lealon L. Sargent
/s/ THOMAS N. AMONETT Director March 20, 2003
-----------------------------
Thomas N. Amonett
/s/ PAUL J. COUGHLIN Director March 20, 2003
-----------------------------
Paul J. Coughlin
/s/ MARK W. FILES Director March 20, 2003
-----------------------------
Mark W. Files
/s/ THOMAS R. FULLER Director March 20, 2003
-----------------------------
Thomas R. Fuller
/s/ W. NEIL MCBEAN Director March 20, 2003
-----------------------------
W. Neil McBean
/s/ ROBERT C. THOMAS Director March 20, 2003
-----------------------------
Robert C. Thomas
29
PETROCORP INCORPORATED
CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
I, Gary R. Christopher, certify that:
1. I have reviewed this annual report on Form 10-K of PetroCorp Incorporated.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make statements made, in light of circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 20, 2003 By: /s/ GARY R. CHRISTOPHER
----------------------------------
Gary R. Christopher
President and Chief Executive
Officer
30
PETROCORP INCORPORATED
CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
I, Steven R. Berlin, certify that:
1. I have reviewed this annual report on Form 10-K of PetroCorp Incorporated.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make statements made, in light of circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 20, 2003 By: /s/ STEVEN R. BERLIN
----------------------------------
Steven R. Berlin
Chief Financial Officer and
Secretary
31
EXHIBIT INDEX
No. Item
10.24 -- Share Purchase Agreement, dated December 24, 2002, between PetroCorp Incorporated, PetroCorp
Acquisition Company, 1022694 Alberta Ltd. and Enermark, Inc.
21 -- List of material subsidiaries
23.1 -- Consent of PricewaterhouseCoopers LLP
23.2 -- Consent of Ryder Scott Company, L.P.
32
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, 2002 and
2001, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2002, 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, 2003
33
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEETS
December 31, 2002 and 2001
(in thousands, except share amounts)
2002 2001
-------- --------
ASSETS
Current assets:
Cash and cash equivalents........................................................... $ 3,087 $ 1,265
Accounts receivable, net............................................................ 11,537 13,267
Assets of discontinued operations................................................... 72,300 --
Other current assets................................................................ 1,107 1,411
-------- --------
Total current assets............................................................ 88,031 15,943
-------- --------
Property, plant and equipment:
Oil and gas properties, at cost, full cost method, net of accumulated depreciation,
depletion, amortization and impairment............................................ 48,761 126,925
Other, net.......................................................................... -- 1,527
-------- --------
48,761 128,452
-------- --------
Deferred income taxes.................................................................. 22,066 18,261
Other assets, net...................................................................... 2,723 2,699
-------- --------
Total assets.................................................................... $161,581 $165,355
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable.................................................................... $ 7,367 $ 6,708
Accrued liabilities................................................................. 2,758 3,877
Liabilities of discontinued operations.............................................. 22,111 --
Current portion of long-term debt................................................... -- 1,327
-------- --------
Total current liabilities....................................................... 32,236 11,912
-------- --------
Long-term debt......................................................................... 28,750 47,620
-------- --------
Deferred income taxes.................................................................. -- 13,908
-------- --------
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,
(12,645,309 shares and 12,556,109 shares outstanding
at December 31, 2002 and 2001, respectively)...................................... 130 128
Additional paid-in capital.......................................................... 111,905 111,114
Accumulated deficit................................................................. (982) (9,666)
Accumulated other comprehensive loss................................................ (7,746) (7,311)
Treasury stock, at cost (305,907 and 264,607 shares respectively) . . . . . . . .... (2,712) (2,350)
-------- --------
Total shareholders' equity........................................................ 100,595 91,915
-------- --------
Total liabilities and shareholders' equity...................................... $161,581 $165,355
======== ========
The accompanying notes are an integral part of these financial statements.
34
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2002, 2001 and 2000
(in thousands, except share amounts)
2002 2001 2000
------- ------- -------
Revenues:
Oil and gas.......................................................... $27,363 $24,970 $23,481
Other................................................................ 312 199 107
------- ------- -------
27,675 25,169 23,588
------- ------- -------
Expenses:
Production costs..................................................... 10,451 8,704 5,813
Depreciation, depletion and amortization............................. 8,002 9,616 5,178
Oil and gas property valuation adjustment............................ -- 15,400 --
General and administrative........................................... 1,838 933 428
Restructuring costs.................................................. -- -- (425)
Other operating expenses............................................. 98 169 243
------- ------- -------
20,389 34,822 11,237
------- ------- -------
Income (loss) from operations........................................... 7,286 (9,653) 12,351
------- ------- -------
Other income (expenses):
Investment income.................................................... 70 65 251
Interest expense..................................................... (1,566) (1,237) (2,895)
Other income (expenses).............................................. 565 921 (257)
------- ------- -------
(931) (251) (2,901)
------- ------- -------
Income (loss) from continuing operations before income taxes............ 6,355 (9,904) 9,450
------- ------- -------
Income tax provision (benefit):
Current.............................................................. (13) 157 --
Deferred............................................................. 2,133 (4,769) 3,662
------- ------- -------
2,120 (4,612) 3,662
------- ------- -------
Income (loss) from continuing operations................................ 4,235 (5,292) 5,788
Income from discontinued Canadian operations (net of applicable taxes of
$3,514, $4,332, and $6,304)........................................... 4,449 7,338 7,030
------- ------- -------
Net income.............................................................. $ 8,684 $ 2,046 $12,818
======= ======= =======
Net income (loss) per common share--basic:
Income (loss) from continuing operations............................. $ 0.34 $ (0.48) $ 0.66
Income from discontinued operations.................................. 0.35 0.67 0.81
------- ------- -------
Net income........................................................... $ 0.69 $ 0.19 $ 1.47
======= ======= =======
Net income (loss) per common share--diluted:.........................
Income (loss) from continuing operations............................. $ 0.34 $ (0.48) $ 0.66
Income from discontinued operations.................................. 0.35 0.66 0.80
------- ------- -------
Net income........................................................... $ 0.69 $ 0.18 $ 1.46
======= ======= =======
Weighted average number of common shares--basic......................... 12,584 10,975 8,692
======= ======= =======
Weighted average number of common shares--diluted....................... 12,676 11,119 8,786
======= ======= =======
The accompanying notes are an integral part of these financial statements.
35
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, 1999...... 8,683 87 71,380 (24,530) (4,574) -- $ 42,363
Net income.................... -- -- -- 12,818 -- -- 12,818
Exercise of stock options and
stock compensation
expense...................... 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 and
stock compensation
expense...................... 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
Net income.................... -- -- -- 8,684 -- -- 8,684
Exercise of stock options and
stock compensation
expense...................... 130 2 791 -- -- -- 793
Other comprehensive loss...... -- -- -- -- (435) -- (435)
Treasury stock................ (41) -- -- -- -- (362) (362)
------ ---- -------- -------- ------- ------- --------
Balance, December 31, 2002...... 12,645 $130 $111,905 $ (982) $(7,746) $(2,712) $100,595
====== ==== ======== ======== ======= ======= ========
The accompanying notes are an integral part of these financial statements.
36
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2002, 2001 and 2000
(in thousands)
2002 2001 2000
-------- -------- --------
Cash flows from operating activities:
Net income (loss)........................................................... $ 8,684 $ 2,046 $ 12,818
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation, depletion and amortization.................................. 8,002 9,616 5,178
Deferred income tax expense (benefit)..................................... 2,133 (4,769) 3,662
Oil and gas property valuation adjustment................................. -- 15,400 --
Other..................................................................... (284) 142 492
Changes in operating assets and liabilities:
Accounts receivable....................................................... (3,473) 4,157 (6,246)
Other current assets...................................................... (378) 372 (429)
Accounts payable.......................................................... 3,669 (3,180) 2,631
Accrued liabilities....................................................... (421) (444) (1,546)
Net change provided by discontinued operations............................ 6,158 (10,237) 16,631
-------- -------- --------
Net cash provided by operating activities............................. 24,090 13,103 33,191
-------- -------- --------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties................................ 11,359 -- 210
Additions to oil and gas properties......................................... (8,306) (11,632) (1,757)
Purchase of Southern Mineral Corporation, net of cash acquired.............. -- (20,989) --
Additions to other assets................................................... -- -- (16)
Net investing activities of discontinued operations......................... (5,534) (5,905) (5,630)
-------- -------- --------
Net cash used in investing activities................................. (2,481) (38,526) (7,193)
-------- -------- --------
Cash flows from financing activities:
Proceeds from long-term debt................................................ 1,800 90,967 29,500
Repayment of long-term debt................................................. (12,800) (91,000) (45,650)
Purchase of treasury shares................................................. (362) (2,350) --
Other....................................................................... 565 401 (83)
Net financing activities of discontinued operations.......................... (8,934) 5,523 (593)
-------- -------- --------
Net cash provided by (used in) financing activities................... (19,731) 3,541 (16,826)
-------- -------- --------
Effect of exchange rate changes on cash...................................... (56) 1,201 (125)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents......................... 1,822 (20,681) 9,047
Cash and cash equivalents at beginning of year............................... 1,265 21,946 12,899
-------- -------- --------
Cash and cash equivalents at end of year..................................... $ 3,087 $ 1,265 $ 21,946
======== ======== ========
The accompanying notes are an integral part of these financial statements.
37
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2002, 2001 and 2000
(in thousands)
Supplemental disclosures:
2002 2001 2000
------ ------ ------
Interest paid.... $1,696 $1,131 $2,917
====== ====== ======
Income taxes paid $ -- $ 210 $ --
====== ====== ======
In 2002, 2001 and 2000, the Company issued $324, $311 and $525 of additional
notes, respectively, as provided under the provisions of the agreements to
finance the company's portion of plant capital additions in Canada.
The accompanying notes are an integral part of these financial statements.
38
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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. See Note 2. In the United States, PetroCorp conducts business in its own
name.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
Petrocorp Incorporated. All balance sheet accounts as of December 31, 2002 and
statement of operations and cash flows for 2002, 2001 and 2000 for PetroCorp's
wholly-owned Canadian subsidiaries are reflected as discontinued operations and
all information in the accompanying notes, except for Notes 2, 10 and 14,
relate only to the continuing operations. 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. 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 for the U.S. properties of
$15,400,000. There was no valuation adjustment for the years ended December 31,
2002 or 2000.
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.
39
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Revenue Recognition
Revenues from the sale of oil and gas 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 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 gas balancing position to be approximately $642,000 (401,000 mcf)
on underproduced properties and approximately $787,000 (492,000 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, 2002 and 2001, the Company included $212,000
(141,000 mcf) and $171,000 (120,000 mcf) respectively, in accrued liabilities
with respect to overproduced imbalances. All overproduced and underproduced
imbalance situations are in the Unites States. 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.
Other revenues include fees associated with the Company's U.S. gathering
system.
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, 2002 and 2001, 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, 2002, the Company recognized a foreign currency transaction
gain of $389,000. For the years ended December 31, 2001 and 2000, the Company
recognized a foreign currency transaction gain of $916,000 and a loss of
$98,000, respectively. (See Note 2.)
40
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Cash Equivalents
For purposes of the consolidated statement of cash flows and the balance
sheet, 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 gas sales in the month of hedged production. In 2002 and 2001, the
impact of hedging transactions was a net increase in revenues of $423,000 and
$187,000, respectively. In 2000, the impact of hedging transactions was a net
reduction of revenues by $1,097,000. (See Note 7.)
Accounting for Stock Based Compensation
At December 31, 2002, the Company has a stock-based compensation plan, which
is more fully described in Note 9. The Company accounts for this plan under the
recognition and measurement principles of APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and related Interpretations. No compensation costs
are reflected for stock-based compensation to individuals who are "employees".
Costs are recorded for stock-based compensation to individuals who are not
"employees". The fair value of the options granted during 2002, 2001 and 2000
were $838,000, $751,000 and $432,000, respectively, on the dates of grants
using the Black-Scholes option-pricing model with the following assumptions:
2002 2001 2000
--------- --------- ---------
Weighted average life, in years 10 10 10
Risk-Free interest rate........ 5.3%-5.9% 5.1%-5.2% 6.0%-6.5%
Expected Volatility............ 36% 40% 41%
Expected Dividend Rate......... None None None
The following table illustrates the effect on net income and earnings per
shares if the Company had applied the fair value recognition provision of FASB
Statement No 123, "Accounting for Stock-Based Compensation," (in thousands,
except per share amounts):
Year Ended December 31,
---------------------
2002 2001 2000
------ ------ -------
Net income, as reported....................................... $8,684 $2,046 $12,818
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards, net
of related tax effects...................................... 666 383 330
------ ------ -------
Pro forma net income.......................................... $8,018 $1,663 $12,488
====== ====== =======
Earnings per share: Basic--as reported........................ $ 0.69 $ 0.19 $ 1.47
Basic--pro forma.............................................. $ 0.64 $ 0.15 $ 1.44
Diluted--as reported.......................................... $ 0.69 $ 0.18 $ 1.46
Diluted--pro forma............................................ $ 0.63 $ 0.15 $ 1.42
41
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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. 142, Goodwill and Other Intangible Assets, and in August 2001, FAS No. 144,
Accounting for Impairment or Disposal of Long-Lived Assets. Effective January
1, 2002, the Company adopted FAS No. 142 and 144. The adoption had no effect on
the Company's financial position or results of operations.
In June 2001, the FASB issued FAS No. 143, Accounting for Asset Retirement
Obligations. FAS 143 is effective for fiscal years beginning after June 15,
2002 (January 1, 2003 for the Company) and establishes an accounting standard
requiring the recording of the fair value of liabilities associated with the
retirement of long-lived assets (mainly plugging and abandonment costs for
depleted wells) in the period in which the liability is incurred (at the time
the wells are drilled). The effect of this standard on the Company's results of
operations and financial condition at adoption is expected to include an
unaudited increase in liabilities of approximately $4.6 million; an unaudited
net increase in property, plant and equipment of approximately $700,000; and an
unaudited charge to income, net of deferred income taxes, for the cumulative
effect of adopting the new standard of approximately $2.5 million and a
deferred tax asset of approximately $1.4 million.
During 2002, the company adopted FAS No. 145, Recission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. Under the provisions of this standard, gains and losses from
extinguishment of debt generally will no longer be classified as extraordinary
items in the statement of operations. Accordingly, the Company's loss on early
retirement of debt of $385 thousand in the year ended December 31, 2000, which
was previously presented as a net of tax extraordinary item, has been
reclassified in the accompanying financial statements and presented as a
component of other income. This reclassification had no impact on the Company's
financial position, net income or cash flows.
In July 2002, the FASB issued FAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which is effective for exit or disposal
activities initiated after December 31, 2002. Management anticipates the
adoption of FAS No. 146 will not materially affect the Company's current
financial position or results of operations.
In November 2002, the FASB issued FASB Interpretation ("FIN") 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, including
Indirect Guarantee of Indebtedness of Others. FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions
for initial recognition and measurement should be applied on a prospective
basis to guarantees issued or modified after December 31, 2002. The guarantor's
previous application may not be revised or restated to reflect the effect of
the recognition and measurement provisions of the interpretation. The
disclosure requirements are effective for financial statements of both interim
and annual periods that end after December 15, 2002. The Company is not a
guarantor under any significant guarantees and thus this interpretation is not
expected to have a significant effect on the Company's financial position or
results of operations.
42
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
On December 31, 2002, the FASB issued FAS No. 148, Accounting for
Stock-Based Compensation--Transition and Disclosure--an amendment of FAS 123,
Accounting For Stock-Based Compensation. FAS 148 does not change the provisions
of FAS 123 that permit entities to continue to apply the intrinsic value method
of APB 25, Accounting for Stock Issued to Employees. FAS 148 does require
certain new disclosures in both annual and interim financial statements. The
required annual disclosures were effective immediately for the Company and have
been included in Note 1 of the Company's financial statements. The new interim
disclosure provisions will be effective for the Company in the first calendar
quarter of 2003.
On January 17, 2003, the FASB issued FIN 46, Consolidation of Variable
Interest Entities, An Interpretation of Accounting Research Bulletin No. 51.
The primary objectives of FIN 46 are to provide guidance on how to identify
entities for which control is achieved thought means other than through voting
rights (variable interest entities "VIE" and how to determine when and which
business enterprise should consolidate the VIE. This new model for
consolidation applies to an entity in which either (1) the equity investors do
not have a controlling financial interest on (2) the equity investment at risk
is insufficient to finance that entity's activities without receiving
additional subordinated financial support from other parties. The Company does
not expect the adoption of this standard to have any impact on the financial
position and results of operations.
2. Sale of Canadian Subsidiaries
On December 24, 2002, PetroCorp signed an agreement to sell its two Canadian
subsidiaries, PCC Energy Inc. and PCC Energy Corp. for C$167.6 million
(approximately US$112 million), with an economically effective date of October
1, 2002. The sale, which closed on March 5, 2003, is subject to post closing
adjustments for certain working capital items. As of December 31, 2002, the
combined unaudited reserves of the Canadian subsidiaries was 2,458 MBbls and
50,799 MMcf. The financial statements reflect the results of the Canadian
operations as discontinued operations and segregate the Canadian assets and
liabilities at December 31, 2002. Prior year statements of operations and cash
flows have been restated to conform to the current year presentation.
Discontinued operations for the fourth quarter of 2002 include $6.7 million
unaudited revenue, 1,861 MMcf equivalent unaudited production and $3.0 million
unaudited pre-tax income.
Net sales and income of the discontinued operations are as follows (amounts
in thousands):
Years ended December 31,
-----------------------
2002 2001 2000
------- ------- -------
Net sales...................................... $23,982 $26,105 $20,985
------- ------- -------
Pre-tax income from discontinued operations.... $ 7,963 $11,670 $13,334
Income tax expense............................. 3,514 4,332 6,304
------- ------- -------
Income from discontinued operations, net of tax $ 4,449 $ 7,338 $ 7,030
======= ======= =======
43
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Assets and liabilities of the discontinued operations are as follows
(amounts in thousands):
December 31,
2002
------------
Cash......................... $ 5,865
Accounts receivable.......... 4,135
Property, plant and equipment 62,183
Other Assets................. 117
Accounts Payable............. (4,607)
Accrued liabilities.......... (2,220)
Long-term debt............... (451)
Deferred tax liability....... (14,833)
--------
$ 50,189
========
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, 2002, 2001 and 2000 are as follows (amounts in thousands):
Years ended December 31,
------------------------
2002 2001 2000
------ ------- -------
Net income................................................... $8,684 $ 2,046 $12,818
------ ------- -------
Derivative hedging gain (loss) (net of taxes of $2 and $679). (4) 1,057 --
Reclassification of hedging gain into income (net of taxes of
$572 and $105)............................................. (888) (165) --
Foreign currency translation gain (loss)..................... 457 (2,491) (1,138)
------ ------- -------
(435) (1,599) (1,138)
------ ------- -------
Comprehensive income......................................... $8,249 $ 447 $11,680
====== ======= =======
Derivative hedging gain (loss) include $31 gain (net of $22 taxes) for 2002
and $280 (net of $206 taxes) for 2001 pertaining to discontinued operations.
Reclassification of hedging gain into income includes $202 (net of $147 taxes)
for 2002 and $47 (net of $36 taxes) for 2001 related to discontinued operations.
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. As of December
31, 2002, accumulated other comprehensive loss included $7,746 of foreign
currency translation losses, which will be reclassified to income from
discontinued operations in the first quarter of 2003 when the sale of the
Canadian operations is recorded.
44
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
4. Merger with Southern Mineral Corporation
PetroCorp completed the acquisition of Southern Mineral on June 6, 2001. 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. Based on evaluations in connection with tax returns filed in 2002, the
Company adjusted its preliminary estimates of the deferred taxes attributable
to the assets acquired in June 2001. Proved oil and gas properties were reduced
by $5.8 million and Deferred tax assets increased by the same amount. In this
acquisition, $88.7 million of assets were acquired and $28.7 million of
liabilities assumed, with $0.4 million of legal, professional and other costs
incurred. $21 million of cash was expended, with the remaining $38.6 million
financed through the issuance of common stock.
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.......................... $ 33,485 $44,558
Income (loss) before income taxes. $(11,680) $10,786
Net income (loss)................. $ (6,376) $ 6,964
Earnings per common share--basic.. $ (0.50) $ 0.55
Earnings per common share--diluted $ (0.50) $ 0.55
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.
45
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
5. Property, Plant and Equipment
Investments in property, plant and equipment were as follows at December 31,
2002 and 2001 (amounts in thousands):
2002 2001/(A)/
--------- ---------
Oil and gas properties:
Proved.................................................. $ 225,414 $ 233,204
Unproved................................................ 233 263
--------- ---------
225,647 233,467
Gas gathering facilities................................... 1,698 1,698
Furniture, fixtures and equipment.......................... -- 22
--------- ---------
227,345 235,187
Less--accumulated depreciation, depletion, amortization and
impairment (178,584) (170,687)
--------- ---------
$ 48,761 $ 64,500
========= =========
--------
/(A)/ Total property, plant and equipment does not include $63,952 related to
discontinued operations.
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 2002, 2001 and 2000 was $7,897,
$9,537 and $5,118, respectively. Oil and gas property depreciation, depletion
and amortization for the years ended December 31, 2002, 2001 and 2000 was
$7,897, $9,484 and $4,782, 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, 2002, 2001 and 2000 was $0.99, $1.38 and
$0.85, respectively. During 2001 the Company also recorded a ceiling test
write-down of $15,400.
6. Long-Term Debt
The Company's total long-term debt, all which matures in 2004, is as follows
(amounts in thousands):
2002 2001/(A)/
------- --------
TD Bank Credit Agreement $28,750 $47,288
======= =======
--------
/(A) /Total long-term debt does not include $332 related to discontinued
operations.
In July 2000, the Company entered into a $75 million revolving credit
agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of
Nova Scotia. The agreement was amended in August 2002 to extend its term,
increase the borrowing base, and partially change the lenders. The amended term
of the facility is through May 1, 2004 and the amended borrowing base was set
at $70 million. The current lenders are TD Bank, as agent, and Fortis Capital
Corp. and Bank of Oklahoma, N.A. (Bank of Oklahoma, N. A.'s largest beneficial
owner is also the primary beneficial owner of Kaiser-Francis Oil Company.
Approximately 38% of the Company is owned by Kaiser-Francis Oil Company.)
46
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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 rate spread is determined
from a sliding scale based was 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, 2002, the
weighted average interest rate for loans outstanding under this facility was
approximately 4.25%.
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. The Company obtained
waivers of certain covenants relating to the sale of some of its Alabama
properties and the sale of Canadian operations.
Effective in March 2003, and in conjunction with the sale of Canadian
subsidiaries described in Note 2, the Company amended its revolving credit
agreement to adjust the borrowing base to $25 million, allocated entirely to
United States borrowing. The Canadian lenders were released from the agreement.
All outstanding debt was paid off with proceeds from the sale.
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.
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. At December 31, 2001, oil and gas hedges had an
estimated fair value of $644,000 (included in other assets), of which $479,000
related to hedges of US production. There were no oil and gas hedges
outstanding at December 31, 2000 or 2002.
As part of PetroCorp's acquisition of Southern Mineral Corporation
("Southern Mineral"), the Company obtained crude oil and natural gas costless
collars with a fair value (liability) at date of acquisition of $821,000. These
hedging transactions for the year ended December 31, 2002 increased oil and gas
revenues by $31,000 and increased income from discontinued operations by
$222,000 (reclassified from comprehensive income). All oil and gas hedging
transactions expired in the fourth quarter of 2002.
In April 2002, the Company entered into a swap transaction covering 8,000
MMBTU of natural gas per day at a price of $3.755 per MMBTU and covering the
period from May 2002 through December 2002. The swap index is NYMEX Henry Hub.
Swap transactions for the year ended December 31, 2002 increased oil and gas
revenues by $392,000 (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.
47
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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 through August 29, 2003. The interest rate swap
does not qualify for hedge accounting. The estimated fair value at December 31,
2002 is a liability (included in other liabilities) of $182,000 ($314,000 for
2001). During 2002 and 2001, $351,000 and $65,000, respectively, were recorded
as additional interest expense relating to this interest rate swap.
8. Income Taxes
The provision (benefit) for income taxes for the years ended December 31,
2002, 2001 and 2000 consists of the following (amounts in thousands):
2002 2001 2000
------ ------- ------
Deferred:
Federal. $1,926 $(4,448) $3,355
State... 207 (321) 307
------ ------- ------
2,133 (4,769) 3,662
Current:
Federal. -- 110 --
State... (13) 47 --
------ ------- ------
(13) 157 --
------ ------- ------
$2,120 $(4,612) $3,662
====== ======= ======
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) from continuing operations before income
taxes for the years ended December 31, 2002, 2001, and 2000 is presented in the
following table (amounts in thousands):
2002 2001 2000
------ ------- ------
United States federal income taxes (benefit) at statutory rate
of 35%...................................................... $2,224 $(3,466) $3,308
Increases (reductions) resulting from:
Statutory depletion........................................ (175) (1,079) --
State income taxes......................................... 126 (178) 200
Other...................................................... (55) 111 154
------ ------- ------
$2,120 $(4,612) $3,662
====== ======= ======
48
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Deferred tax assets and liabilities related to continuing operations consist
of the following at December 31, 2002 and 2001 (amounts in thousands):
2002 2001/(A)/
------- --------
Deferred tax assets:
Depletion and net operating loss carryforward--U.S............. $24,023 $23,542
------- -------
Gross deferred tax asset.......................................... 24,023 23,542
------- -------
Deferred tax liabilities:
Excess of basis in property, plant and equipment for financial
reporting purposes over the tax basis--U.S................... (1,957) (5,238)
Derivative asset............................................... -- (43)
------- -------
Gross deferred tax liability...................................... (1,957) (5,281)
------- -------
$22,066 $18,261
======= =======
--------
/(A) /Deferred tax assets and liabilities do not include $13,908 of deferred
tax liabilities related to discontinued operations.
As of December 31, 2002, the Company has U.S. net operating loss (NOL)
carryforwards of approximately $47,737,000 and $51,790,000 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, which have no expiration
dates, of $19,552,000 are available at December 31, 2002.
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.
49
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
9. Stock Option and Other Employee Benefit Plans
Details on the Company's four stock option plans are as follows:
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, 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
Granted...................... -- --
Forfeited.................... (187,000) $10.00
Exercised.................... (121,500) $ 5.00
--------
Outstanding at December 31, 2002 80,000 $ 6.38
========
Of the 80,000 outstanding options under the Option Plan at December 31,
2002, all had an exercise price of $6.38 and a weighted average contractual
life of 3.1 years. All of these options are exercisable as of December 31,
2002. No new options can be issued under this plan.
50
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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, 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
Granted...................... -- --
Forfeited.................... -- --
Exercised.................... -- --
-------
Outstanding at December 31, 2002 23,000 $8.23
=======
As of December 31, 2002, the weighted average remaining contractual life of
the outstanding options under the Director Option Plan was 5.0 years and the
exercise prices ranged from $6.75 to $8.63. No new options can be issued under
this plan.
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
Granted...................... 154,000 $9.31
Forfeited.................... (8,000) $9.53
Exercised.................... (9,000) $6.13
-------
Outstanding at December 31, 2002 393,650 $8.78
=======
51
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
As of December 31, 2002, the weighted average remaining contractual life of
the outstanding options under the 2000 Stock Option Plan was 8.4 years. Of the
outstanding options, 278,150 were exercisable at year end with an average
remaining contractual life of 8.1 years. At December 31, 2002, exercise prices
ranged from $6.13 to $9.75.
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
Options Exercise 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
Granted...................... -- --
Forfeited.................... (124,961) $21.01
Exercised.................... -- --
--------
Outstanding at December 31, 2002 -- --
========
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.
Effective January 1, 1993, the Company established a savings plan, which
qualified as a deferred compensation plan under Section 401(k) of the Internal
Revenue Code. The plan was in the wind up phase during 2001 and 2002 and was
fully liquidated at December 31, 2002. The Company's contributions to the plan,
which are charged to expense, totaled nil, nil and $100,000 in 2002, 2001 and
2000, respectively.
52
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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
-------------------------------
Income
(Loss) from Income from
Continuing Discontinued Net
Income Shares Operations Operations Income
------- ------ ----------- ------------ ------
Year ended December 31, 2002
Basic EPS:
Net income................. $ 8,684 12,584 $ 0.34 $ 0.35 $ 0.69
Effect of dilutive securities:
Options.................... -- 92 -- -- --
------- ------ ------ ------ ------
Diluted EPS:
Net income................. $ 8,684 12,676 $ 0.34 $ 0.35 $ 0.69
======= ====== ====== ====== ======
Year ended December 31, 2001
Basic EPS:
Net income................. $ 2,046 10,975 $(0.48) $ 0.67 $ 0.19
Effect of dilutive securities:
Options.................... -- 144 -- (0.01) (0.01)
------- ------ ------ ------ ------
Diluted EPS:
Net income................. $ 2,046 11,119 $(0.48) $ 0.66 $ 0.18
======= ====== ====== ====== ======
Year ended December 31, 2000
Basic EPS:
Net income................. $12,818 8,692 $ 0.66 $ 0.81 $ 1.47
Effect of dilutive securities:
Options.................... -- 94 -- (0.01) (0.01)
------- ------ ------ ------ ------
Diluted EPS:
Net income................. $12,818 8,786 $ 0.66 $ 0.80 $ 1.46
======= ====== ====== ====== ======
The 2002, 2001, and 2000 income per share amounts do not include the effect
of potentially dilutive securities of 303,500, 469,000 and 395,000,
respectively, as the impact of these outstanding options was antidilutive.
53
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
11. Industry Segment Data
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. The Company's continuing operations consist of oil and gas
operations in the US. Activity related to the Canadian operations are accounted
for as discontinued operations.
The following table reflects purchasers which accounted for more than 10% of
the Company's oil and gas revenues:
2002 2001 2000
---- ---- ----
EOTT Energy Trading Partnership Ltd 16% 12% 12%
Sunoco, Inc........................ 12% 9% 8%
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, 2002, 305,907 shares have been purchased at a cost
of $2,712,000, 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
$54,000 for the year ending December 31, 2003 with no payments after that date.
Future minimum sublease income with noncancellable terms in excess of one year
for office space is $34,000 for the year ending December 31, 2003. Total rental
expense for office space for the years ended December 31, 2002, 2001 and 2000
was $198,000, $140,000 and $111,000, 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 the New
York Supreme Court. 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 that 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, after indemnification and insurance
reimbursements, would not be material to the Company's consolidated financial
position.
14. Related Party Transactions
The Company is a joint-interest owner in a project operated by
Kaiser-Francis Oil Company, a shareholder. During 2002, 2001 and 2000, the
Company remitted $451,000, $63,000 and $154,000, respectively, to
Kaiser-Francis as payment of the Company's share of the joint operation. During
2002, 2001 and 2000, the Company remitted $3,146,000, $3,064,000 and
$2,076,000, respectively, to Kaiser-Francis, of which $1,965,000, $2,176,000
and $1,419,000, respectively, were administrative fees under the Management
Agreement. Of these administrative fees, $1,498,000, $1,693,000 and $1,234,000,
respectively, relate to continuing operations covered under the Management
Agreement. Amounts payable to Kaiser-Francis at December 31, 2002 and 2001 were
$213,000 and $272,000, respectively.
54
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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
the continuing oil and gas properties (amounts in thousands):
2002:
Proved properties.................................... $ 225,414
Unproved properties.................................. 233
---------
225,647
Accumulated depreciation, depletion and amortization. (176,886)
---------
$ 48,761
=========
2001:
Proved properties.................................... $ 233,204
Unproved properties.................................. 263
---------
233,467
Accumulated depreciation, depletion and amortization. (168,989)
---------
$ 64,478
=========
2000:
Proved properties.................................... $ 176,834
Unproved properties.................................. 1,223
---------
178,057
Accumulated depreciation, depletion and amortization. (144,105)
---------
$ 33,952
=========
Of the unproved properties capitalized cost at December 31, 2002, none and
approximately $96,000, respectively, were incurred in 2002 and 2001. The
Company anticipates evaluating these properties during subsequent years.
55
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Costs Incurred in Oil and Gas Producing Activities
Presented below are costs incurred in oil and gas property acquisition,
exploration and development activities of the continuing operations (amounts in
thousands):
2002:
Acquisition of properties:
Proved properties....... $ --
Unproved properties..... 415
Exploration costs........... --
Development costs/(A)/...... 8,886
-------
Total................... $ 9,301
=======
2001:
Acquisition of properties:
Proved properties....... $42,608
Unproved properties..... 678
Exploration costs........... 2,003
Development costs/(A)/...... 10,121
-------
Total................... $55,410
=======
2000:
Acquisition of properties:
Proved properties....... $ 104
Unproved properties..... 80
Exploration costs........... --
Development costs/(A)/...... 1,553
-------
Total................... $ 1,737
=======
--------
/(A) /Includes approximately $4,213, $42 and $600 of costs incurred in 2002,
2001 and 2000, respectively, for development of properties previously
classified as proved undeveloped properties in the prior year.
56
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Results of Operations From Oil and Gas Producing Activities (unaudited)
The results of operations from continuing oil and gas producing activities,
are as follows (amounts in thousands):
2002:
Revenues....................................................................... $ 27,363
Production costs............................................................... (10,451)
Depreciation, depletion and amortization....................................... (7,897)
Income tax benefit (expense)................................................... (3,336)
--------
Results of operations from petroleum producing activities (excluding corporate
overhead and interest costs)................................................. $ 5,679
========
2001:
Revenues....................................................................... $ 24,970
Production costs............................................................... (8,704)
Depreciation, depletion, amortization and......................................
impairment..................................................................... (24,884)
Income tax benefit (expense)................................................... 3,187
--------
Results of operations from petroleum producing activities (excluding corporate
overhead and interest costs)................................................. $ (5,431)
========
2000:
Revenues....................................................................... $ 23,481
Production costs............................................................... (5,813)
Depreciation, depletion and amortization....................................... (4,782)
Income tax benefit (expense)................................................... (4,728)
--------
Results of operations from petroleum producing activities (excluding corporate
overhead and interest costs)................................................. $ 8,158
========
Reserve Quantities (unaudited)
Estimates of proved reserves and the related standardized measure of
discounted future net cash flow information related to the continuing
operations are based on the reports of independent petroleum engineers for 2000
and reserve evaluations performed by the Company's engineer in 2002 and 2001
and reviewed by independent petroleum engineers. Approximately 85% and 100% of
the present value of reserves at December 31, 2002 and 2001, respectively, were
reviewed by independent petroleum engineers.
57
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
The Company's estimates of its continuing proved reserves and proved
developed reserves of oil and gas as of December 31, 2002, 2001 and 2000 and
the changes in its proved reserves are as follows:
U.S.
--------------
Oil Gas
(MBbls) (MMcf)
------- ------
2002:
Proved reserves:
Beginning of year.................. 3,931 41,384
Production......................... (479) (5,089)
Purchase of minerals-in-place...... -- --
Extensions and discoveries......... 429 1,849
Improved recoveries................ 33 (141)
Sales of minerals-in-place......... (1,349) (3,306)
Revision to previous estimates..... 144 4,063
------ ------
End of year........................ 2,709 38,760
====== ======
Proved developed reserves:
Beginning of year.................. 3,350 38,806
====== ======
End of year........................ 2,147 34,317
====== ======
2001:
Proved reserves:
Beginning of year.................. 3,109 22,709
Production......................... (396) (4,498)
Purchase of minerals-in-place...... 2,190 19,722
Extensions and discoveries......... 25 867
Improved recoveries................ -- --
Sales of minerals-in-place......... -- --
Revision to previous estimates..... (997) 2,584
------ ------
End of year........................ 3,931 41,384
====== ======
Proved developed reserves:
Beginning of year.................. 2,888 20,551
====== ======
End of year........................ 3,350 38,806
====== ======
2000:
Proved reserves:
Beginning of year.................. 3,261 20,950
Production......................... (294) (3,850)
Purchase of minerals-in-place...... 8 1
Extensions and discoveries......... 155 1,314
Improved recoveries................ -- --
Sales of minerals-in-place......... -- (213)
Revision to previous estimates..... (21) 4,507
------ ------
End of year........................ 3,109 22,709
====== ======
Proved developed reserves:
Beginning of year.................. 3,180 18,906
====== ======
End of year........................ 2,888 20,551
====== ======
58
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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, the
fair value of hedges related to U.S. production was an asset of $479,000. At
December 31, 2002 and 2000 there were no oil and gas collar hedges outstanding.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (amounts in thousands):
2002:
Future gross revenues........................................ $252,955
Less--future costs:
Production............................................... 69,164
Development/(A)/......................................... 9,364
--------
Future net cash flows before income taxes.................... 174,427
Less--10% annual discount for estimated timing of cash flows. 66,013
--------
Present value of future net cash flows before income tax..... 108,414
Less--present value of future income taxes................... 10,058
--------
Standardized measure of discounted future net cash flows..... $ 98,356
========
/(A)/ $7,618 of development costs are for proved undeveloped properties
2001:
Future gross revenues........................................ $169,025
Less--future costs:
Production............................................... 58,768
Development/(A)/......................................... 10,850
--------
Future net cash flows before income taxes.................... 99,407
Less--10% annual discount for estimated timing of cash flows. 39,836
--------
Present value of future net cash flows before income tax..... 59,571
Less--present value of future income taxes................... 752
--------
Standardized measure of discounted future net cash flows..... $ 58,819
========
/(A)/ $7,846 of development costs are for proved undeveloped properties
59
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
2000:
Future gross revenues........................................ $313,677
Less--future costs:
Production............................................... 55,534
Development/(A)/......................................... 2,457
--------
Future net cash flows before income taxes.................... 255,686
Less--10% annual discount for estimated timing of cash flows. 103,563
--------
Present value of future net cash flows before income tax..... 152,123
Less--present value of future income taxes................... 42,860
--------
Standardized measure of discounted future net cash flows..... $109,263
========
/(A)/ $1,204 of development costs are for proved undeveloped properties
60
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows (amounts in thousands):
2002:
Standardized measure--beginning of period.............. $ 58,819
Sales of oil and gas produced, net of production costs. (16,912)
Purchases of minerals-in-place......................... --
Extensions, discoveries and improved recovery.......... 5,311
Sales of minerals-in-place............................. (4,512)
Net changes in prices and productions costs............ 28,414
Changes in estimated future development costs.......... (7,807)
Development costs incurred............................. 8,886
Revisions to previous quantity estimates............... 30,006
Accretion of discount.................................. 5,238
Changes in timing of production and other.............. 386
Net changes in income taxes............................ (9,473)
---------
Standardized measure--end of period.................... $ 98,356
=========
2001:
Standardized measure--beginning of period.............. $ 109,263
Sales of oil and gas produced, net of production costs. (16,266)
Purchases of minerals-in-place......................... 27,385
Extensions, discoveries and improved recovery.......... 1,197
Sales of minerals-in-place............................. --
Net changes in prices and productions costs............ (114,680)
Changes in estimated future development costs.......... (11,036)
Development costs incurred............................. 10,121
Revisions to previous quantity estimates............... (3,103)
Accretion of discount.................................. 15,213
Changes in timing of production and other.............. (1,383)
Net changes in income taxes............................ 42,108
---------
Standardized measure--end of period.................... $ 58,819
=========
2000:
Standardized measure--beginning of period.............. $ 56,406
Sales of oil and gas produced, net of production costs. (17,668)
Purchases of minerals-in-place......................... 23
Extensions and discoveries............................. 8,502
Sales of minerals-in-place............................. (108)
Net changes in prices and productions costs............ 94,155
Development costs incurred............................. 1,553
Revisions to previous quantity estimates............... 16,130
Accretion of discount.................................. 6,068
Changes in timing of production and other.............. (17,214)
Net changes in income taxes............................ (38,584)
---------
Standardized measure--end of period.................... $ 109,263
=========
61
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
The standardized measure amounts are based on current prices at each year
end and reflect overall adjusted weighted average prices of:
2002:
Oil (per BBL). $29.73
Gas (per Mcf). 4.44
2001:
Oil (per BBL). $18.45
Gas (per Mcf). 2.67
2000:
Oil (per BBL). $25.45
Gas (per Mcf). 10.33
16. Supplementary Information
At December 31, 2002, accrued liabilities included $681,000 of accrued lease
operating expense, $867,000 of accrued capital costs and $1.2 million of other
miscellaneous accrued expense. 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 accrued expenses.
62
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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, 2002:
Revenues.................................... $6,176 $7,172 $7,255 $ 7,072 $27,675
Gross profit/(1)/........................... 1,239 2,104 3,054 2,727 9,124
Income from continuing operations........... 323 1,455 860 1,597 4,235
Income from discontinued operations......... 723 925 1,313 1,488 4,449
Net income.................................. 1,046 2,380 2,173 3,085 8,684
Net income per share from continuing
operations--basic......................... $ 0.02 $ 0.12 $ 0.07 $ 0.13 $ 0.34
Net income per share from continuing
operations--diluted....................... $ 0.02 $ 0.12 $ 0.07 $ 0.13 $ 0.34
Net income per share from discontinued
operations--basic......................... $ 0.06 $ 0.07 $ 0.10 $ 0.12 $ 0.35
Net income per share from discontinued
operations--diluted....................... $ 0.06 $ 0.07 $ 0.10 $ 0.12 $ 0.35
Year ended December 31, 2001:
Revenues.................................... $6,594 $6,447 $6,119 $ 6,009 $25,169
Gross profit/(1)/........................... 4,345 2,934 720 (16,719) (8,720)
Income (loss) from continuing operations.... 3,353 1,146 285 (10,076) (5,292)
Income from discontinued operations......... 2,853 1,453 2,764 268 7,338
Net income (loss)/(2)/...................... 6,206 2,599 3,049 (9,808) 2,046
Net income (loss) per share from continuing
operations--basic/(2)/.................... $ 0.38 $ 0.12 $ 0.02 $ (0.79) $ (0.48)
Net income (loss) per share from continuing
operations--diluted/(2)/.................. $ 0.38 $ 0.11 $ 0.02 $ (0.79) $ (0.48)
Net income per share from discontinued
operations--basic......................... $ 0.33 $ 0.15 $ 0.22 $ 0.02 $ 0.67
Net income per share from discontinued
operations--diluted....................... $ 0.32 $ 0.15 $ 0.22 $ 0.02 $ 0.66
Quarterly and prior year amounts have been restated to reflect the sale of
Canadian subsidiaries as discontinued operations, as described in Note 2 to the
consolidated financial statements of the Company.
--------
/(1)/ Revenues less operating expenses other than general and administrative
expenses.
/(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.
63