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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K/A
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2000
or
[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 0-22650
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PETROCORP INCORPORATED
(Exact name of registrant as specified in its charter)
Texas 76-0380430
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation organization)
6733 South Yale Avenue 74136
Tulsa, Oklahoma (Zip Code)
(Address of principal executive
offices)
Registrant's telephone number, including area code: (918) 491-4500
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Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.01 per share
Preferred Stock Purchase Rights
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. [X] Yes [_] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K ((S)(S)229.045 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of February 28, 2001 was $40,127,890. Indicate the number of
shares outstanding of each of the registrant's classes of common stock, as of
February 28, 2001:
Common Stock, par value $.01 per share: 8,720,619
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held in 2001 (to be filed within 120 days of the close of registrant's fiscal
year) is incorporated by reference into Part III.
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TABLE OF CONTENTS
Item Title Page
---- ----- ----
PART I
1 Business........................................................ 1
2 Properties...................................................... 6
3 Legal Proceedings............................................... 14
4 Submission of Matters to a Vote of Securities Holders........... 14
PART II
5 Market for Registrant's Common Equity and Related Stockholder
Matters........................................................ 15
6 Selected Financial Data......................................... 16
7 Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 17
7A Quantitative and Qualitative Disclosure about Market Risk....... 21
8 Financial Statements and Supplementary Data..................... 21
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................... 21
PART III
10-13 (Items 10-13 incorporated by reference to Proxy Statement)...... 22
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form
8-K............................................................ 22
As used in this report, "Bbl" means barrel, "MBbls" means thousand barrels,
"MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "BOPD" means barrel of oil
per day, "Mcf/D" means thousand cubic feet per day, "MMcf/D" means million
cubic feet per day, "Mcfe" means 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 one billion cubic feet of
natural gas equivalents, "Tcf" means one trillion cubic feet, "PV-10" means
estimated pretax present value of future net revenues discounted at 10% using
SEC rules, "gross" wells or acres are the wells or acres in which the Company
has a working interest, and "net" wells or acres are determined by multiplying
gross wells or acres by the Company's working interest in such wells or acres.
i
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, Louisiana and Kansas, and in the province of Alberta,
Canada.
At December 31, 2000, the Company's proved reserves totaled 4.2 MMBbls of
oil and 75.3 Bcf of natural gas and had an estimated pretax present value of
future net revenues (PV-10) of $410.3 million. On a Mcfe basis, approximately
75% of the Company's proved reserves were natural gas at such date. In
addition, the Company has unproved interest holdings with a net book value of
$2.0 million, as well as interests in natural gas processing and gathering
facilities with a net book value of $2.5 million.
The Company was formed in July 1983 as a Delaware corporation and in
December 1986 contributed its assets to a newly formed Texas general
partnership. In October 1992, the Company changed its legal form from a Texas
general partnership to a Texas corporation. In August 1999, the Company signed
a Management Agreement with its largest shareholder, Kaiser-Francis Oil
Company (Kaiser-Francis), under which Kaiser-Francis will 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 is an employee of Kaiser-
Francis Oil Company and has served on PetroCorp's Board of Directors since
1996. This Management Agreement was approved by the shareholders of the
Company in October 1999 and took effect on November 1, 1999. A new slate of
corporate officers was approved at that time. PetroCorp's principal executive
offices are located at 6733 South Yale Avenue, Tulsa, Oklahoma 74136, with a
mailing address of P.O. Box 21298, Tulsa, Oklahoma 74121-1298, and its
telephone number is (918) 491-4500. Unless the context otherwise requires, the
terms the "Company" and "PetroCorp" refer to and include PetroCorp
Incorporated, its predecessor entities (including the original Delaware
corporation and the subsequent Texas general partnership) and all subsidiaries
in which PetroCorp owns a 50% or greater interest.
Business Strategy
PetroCorp and its wholly-owned Canadian subsidiaries acquire, explore and
develop oil and natural gas properties in North America.
Acquisition Strategy. The Company has grown, in large part, through the
acquisition of producing oil and gas properties. The Company generally focuses
on acquisitions of long-lived natural gas reserves, located onshore in North
America, and prefers acquisitions that provide additional potential through
development or exploitation efforts, as well as exploratory drilling
opportunities.
Exploration and Development Strategy. Exploration and development
activities are an important component of PetroCorp's business strategy.
Through its Management Agreement with Kaiser-Francis, the Company will be able
to allocate a greater portion of future cash flows to exploration and
development activities.
Exploration and Development Activities
Pending Merger. On December 22, 2000, PetroCorp and Southern Mineral
Corporation (Southern Mineral) executed a definitive agreement whereby
Southern Mineral would be merged into PetroCorp. In the merger, shareholders
of Southern Mineral will receive consideration of $4.71 per share in cash or,
at their election, PetroCorp common stock or a combination of cash and stock,
subject to certain adjustments. For both companies, the merger provides
strategic and economic benefits. The operations of the two companies are very
complementary, with PetroCorp primarily operating in the onshore Gulf Coast
and Mid-continent areas of the United States and Southern Mineral primarily
operating in the onshore Gulf Coast area of the United States.
1
PetroCorp and Southern Mineral both have significant oil and gas interests in
the province of Alberta, Canada. Additionally, the combined company will
benefit by having a substantially greater critical mass and the cost savings
resulting from the consolidation of operations. PetroCorp will continue to
operate under the Management Agreement with Kaiser-Francis Oil Company.
PetroCorp and Southern Mineral have filed a preliminary joint
proxy/registration statement with the Securities and Exchange Commission and,
subject to receiving regulatory and shareholder approvals, anticipate a second
quarter 2001 closing.
United States. During 2000, the Company participated in three new
discoveries in the Cement Field area, located in Caddo County, Oklahoma,
increasing proved reserves by 317 MMcfe. In South Louisiana, PetroCorp
participated in the successful Martin Heirs well in the Scott field area,
adding 637 MMcfe of proved reserves.
At year-end 2000, PetroCorp was participating in three deep prospects in
the Mississippi Salt Basin in an area where several new field discoveries have
recently been made. The North Smithtown Prospect was drilling toward a
Smackover/Norphlet target at approximately 19,000 feet. The Northwest Clara
Prospect seeks the same objectives at approximately 17,000 feet. The Company
owns 7.5% and 10% working interests, respectively, in the two prospects. A
third prospect in the same area is anticipated to spud after the completion of
the Northwest Clara well. In South Texas, the Company plans to drill two
prospect ideas as part of its Duval County joint venture with industry
partners. Target objectives are Wilcox intervals between 10,000 and 16,000
feet. PetroCorp owns 17.5% working interest in this project.
PetroCorp's most significant domestic project is the SW Oklahoma City Unit,
which is showing positive response to water injection efforts. This is
consistent with both the Company's initial estimates and offset field response
in similar waterflood projects in the same region. Since the last half of
1999, the unit's production has more than doubled to over 400 barrels per day.
Additional infill drilling is anticipated during 2001, which should lead to a
projected peak waterflood response of between 800 and 1000 barrels per day by
2003.
Canada. Recent activity in the Hanlan-Robb area has focused on the
development of the Shaw, Basing and Redcap areas through the drilling of five
new horizontal wells. Three of these wells have begun production and the other
two are expected to be tied in to the Hanlan-Robb plant in the first quarter
of 2001. Gross production increase, which is prior to royalty payments, from
the addition of the three wells has added 34.5 MMcf/D and increased production
from this area by 300% verses 1999 levels. Drilling is expected to continue in
this area with up to 4 additional wells anticipated to be drilled in 2001. In
the Banshee/Medicine Lodge area, PetroCorp completed a suspended well in an
uphole zone which is currently producing 2 MMcf/D.
At the Hanlan Swan Hills Gas Unit #1 additional compression was added in
the south pool to protect the unit from a competing well outside the unit.
Early in 2000, PetroCorp acquired the interest of a small owner in the unit to
increase the Company's working interest to 7.6% of the unit.
In the Minehead exploratory prospect, located ten miles east of the Hanlan-
Robb Gas Plant, PetroCorp participated for a 4.7% working interest in a well
targeting the Swan Hills formation. Although the well was unsuccessful in the
Swan Hills, several up hole zones continue to be evaluated. PetroCorp has
working interest varying from 2.4% to 32.5% in the surrounding 12,800 leased
acres.
2
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, 2000, 1999, and 1998. The average oil sales price and average gas sales
price have been reduced, respectively, by $1,035,000 ($2.56 per Bbl) and
$62,000 ($0.01 per Mcf) for hedging losses during 2000. See Note 9 to the
Consolidated Financial Statements of the Company and "Supplemental Information
to the Consolidated Financial Statements" in the Notes thereto included
elsewhere in this report for additional financial information regarding the
Company's foreign and domestic operations.
Year Ended December
31,
--------------------
2000 1999 1998
------ ------ ------
Net oil produced (MBbls):
United States....................................... 294 324 422
Canada.............................................. 110 138 143
------ ------ ------
Total............................................. 404 462 565
Average oil sales price (per Bbl):
United States....................................... $26.38 $17.33 $12.55
Canada.............................................. 25.49 16.48 11.59
Weighted average.................................... 26.14 17.08 12.31
Net gas produced (MMcf):
United States....................................... 3,850 4,421 4,932
Canada.............................................. 4,519 4,660 4,579
------ ------ ------
Total............................................. 8,369 9,081 9,511
Average gas sales price (per Mcf):
United States....................................... $ 4.08 $ 2.24 $ 2.15
Canada.............................................. 3.54 1.58 1.32
Weighted average.................................... 3.79 1.90 1.75
Gas equivalents produced (MMcfe):
United States....................................... 5,614 6,365 7,464
Canada.............................................. 5,179 5,488 5,437
------ ------ ------
Total............................................. 10,793 11,853 12,901
Average sales price (per Mcfe):
United States....................................... $ 4.18 $ 2.44 $ 2.13
Canada.............................................. 3.63 1.76 1.42
Weighted average.................................... 3.92 2.13 1.83
Production costs (per Mcfe):
United States....................................... $ 1.04 $ 0.72 $ 0.69
Canada.............................................. 0.43 0.40 0.40
Weighted average.................................... 0.74 0.57 0.57
Marketing
PetroCorp's United States gas production is sold to a variety of pipelines,
marketing companies and utility end users at prices based on the spot market.
This gas is typically sold under short-term contracts ranging in length from
one month to one year. In Canada during 2000, nearly one-half of the Company's
gas was dedicated under long-term contracts to Pan-Alberta Gas Ltd. (Pan-
Alberta), a major Canadian gas aggregator and marketer. Under these contracts,
approximately 75% of the gas was resold into the United States, predominantly
to markets in the upper Midwest region. PetroCorp received a price, per Mcf,
from Pan-Alberta equal to Pan-Alberta's resale price less certain costs. Most
of the Company's remaining Canadian gas was sold to Engage Energy at spot
prices on either a daily or a monthly basis.
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
3
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, 2000, Engage Energy and Pan-Alberta
accounted for 27% and 19% of the Company's total sales, respectively. The
Company does not believe the loss of any purchaser would have a material
adverse effect on its financial position since the Company believes
alternative sales arrangements could be made on relatively comparable terms.
In general, prices of oil and gas are dependent on numerous factors beyond
the control of the Company, such as competition, international events and
circumstances (including actions taken by the Organization of Petroleum
Exporting Countries (OPEC)), and certain economic, political and regulatory
developments. Since demand for natural gas is generally highest during winter
months, prices received for the Company's natural gas are subject to seasonal
variations.
Hedging Activities
Prior to 1997, the Company utilized hedging transactions to manage its
exposure to price fluctuations in crude oil and natural gas. The Company has
reviewed this strategy and has begun hedging activities again, effective April
2000. No contracts were outstanding as of December 31, 2000. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" for
the impact of hedging transactions on financial results.
Competition
The oil and gas industry is highly competitive. The Company competes in
acquisitions and in the exploration, development, production and marketing of
oil and gas with major oil companies, larger independent oil and gas concerns
and individual producers and operators. Many of these competitors have
substantially greater financial and other resources than the Company.
Regulation
United States
General. The Company's business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation and tax laws.
For example, state and federal agencies have issued rules and regulations that
require permits for the drilling of wells, regulate the spacing of wells,
prevent the waste of reserves through proration, and regulate oilfield and
pipeline environmental and safety matters. Changes in any of these laws could
have a material adverse effect on the Company's business, and the Company
cannot predict the overall effects of such laws and regulations on its future
operations. Although these regulations have an impact on the Company and
others in the oil and gas industry, the Company does not believe that it is
affected in a significantly different manner by these regulations than are its
competitors in the oil and gas industry.
The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.
Regulation of Transportation and Sale of Natural Gas and Oil. Various
aspects of the Company's oil and gas operations are regulated by agencies of
the federal government. The transportation of natural gas in interstate
commerce is generally regulated by the Federal Energy Regulatory Commission
(FERC) pursuant to the Natural Gas Act of 1938 (the NGA) and the Natural Gas
Policy Act of 1978 (NGPA). The intrastate transportation and gathering of
natural gas (and operational and safety matters related thereto) may be
subject to regulation by state and local governments.
In the past, the federal government regulated the prices at which the
Company's produced oil and gas could be sold. Currently, "first sales" of
natural gas by producers and marketers, and all sales of crude oil, condensate
4
and natural gas liquids, can be made at uncontrolled market prices, but
Congress could reenact price controls at any time.
Within the past decade, the FERC has issued numerous orders and policy
statements designed to create a more competitive environment in the national
natural gas marketplace, including orders promoting "open-access"
transportation on natural gas pipelines subject to the FERC's NGA and NGPA
jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed
to restructure the interstate natural gas transportation and marketing system
and to promote competition within all phases of the natural gas industry.
Among other things, Order 636 required interstate pipelines to separate the
transportation of gas from the sale of gas, to change the manner in which
pipeline rates were designed and to implement other changes intended to
promote the growth of market centers. Subsequent FERC initiatives have
attempted to standardize interstate pipeline business practices and to allow
pipelines to implement market-based, negotiated and incentive rates. The
restructured services implemented by Order 636 and successor orders have now
been in effect for a number of winter heating seasons and have significantly
affected the manner in which natural gas (both domestic and foreign) is
transported and sold to consumers.
Order 636 has generally been upheld in judicial appeals to date. However,
FERC routinely evaluates whether its approach to regulation of the natural gas
industry should be changed and whether further refinements or changes to
existing policies should be made in view of developments in the natural gas
industry since Order 636 was originally issued. Although FERC has indicated
that it remains committed to Order 636's "fundamental goal" of "improving the
competitive structure of the natural gas industry in order to maximize the
benefits of wellhead decontrol," the future regulatory goals and priorities of
FERC may change, and it is not possible to predict the effect, if any, of
future restructuring orders or policies on the Company's operations. FERC's
policies may also be impacted by the ongoing restructuring of the electric
power industry pursuant to FERC Order No. 888.
While Order 636 and related orders do not directly regulate either the
production or sale of gas that may be produced from the Company's properties,
the increased competition and changes in business practices within the natural
gas industry resulting from such orders have affected the terms and conditions
under which the Company markets and transports its available gas supplies. To
date, the FERC's pro-competition policies have not materially affected the
Company's business or operations. On a prospective basis, however, such orders
may substantially increase the burden on producers and transporters to
accurately nominate and deliver on a daily basis specified volumes of natural
gas, or to bear penalties or increased costs in the event scheduled deliveries
are not made.
Environmental Regulation. Various federal, state and local laws and
regulations governing the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs. In particular, the Company's exploration,
exploitation and production operations, its activities in connection with
storage and transportation of crude oil and other liquid hydrocarbons and its
use of facilities for treating, processing or otherwise handling hydrocarbons
and wastes therefrom are subject to stringent environmental regulation.
Although compliance with these regulations increases the cost of Company
operations, such compliance has not in the past had a material effect on the
Company's capital expenditures, earnings or competitive position.
Environmental regulations have historically been subject to frequent change by
regulatory authorities. The trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation
has been proposed in Congress from time to time that would reclassify certain
oil and gas exploration and production wastes as "hazardous wastes," which
would make the reclassified wastes subject to much more stringent handling,
disposal and cleanup requirements. If such legislation were to be enacted, it
could have a significant impact on the operating costs of the Company, as well
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
5
such an increase is warranted. These financial responsibility requirements
could have a significant adverse impact on small oil and gas companies like
PetroCorp. State initiatives to further regulate the disposal of oil and gas
wastes are also pending in certain states, and these various initiatives could
have a similar impact on the Company. The Company is unable to predict the
ongoing cost to it of complying with these laws and regulations or the future
impact of such regulations on its operation. Management believes that the
Company is in substantial compliance with current applicable environmental
laws and regulations and that continued compliance with existing requirements
will not have a material adverse impact on the Company. A catastrophic
discharge of hydrocarbons into the environment could, to the extent such event
is not insured, subject the Company to substantial expense.
Canada
In Canada, the petroleum industry operates under federal, provincial and
municipal legislation and regulations governing taxes, land tenure, royalties,
production rates, environmental protection, exports and other matters. Prices
of oil and natural gas in Canada have been deregulated and are determined by
market conditions and negotiations between buyers and sellers, although oil
production volumes are regulated. Various matters relating to the
transportation and distribution of natural gas are the subject of hearings
before various regulatory tribunals. In addition, although the price of
natural gas exported from Canada is subject to negotiation between buyers and
sellers, the National Energy Board, which regulates exports of natural gas,
requires that natural gas export contracts meet certain criteria as a
condition of approving such contracts. These criteria, including price
considerations, are designed to demonstrate that the export is in the Canadian
public interest. Several provincial governments have introduced a number of
programs to encourage and assist the oil and natural gas industry, including
incentive payments, royalty holidays and royalty tax credits. Canadian
governmental regulations may have a material effect on the economic parameters
for engaging in oil and gas activities in Canada and may have a material
effect on the advisability of investments in Canadian oil and gas drilling
activities.
Employees
At December 31, 2000, PetroCorp had 2 full-time employees. (See
"Restructuring" included in Item 7--Management's Discussion and Analysis of
Financial Condition and Result of Operations.)
Item 2. Properties.
Principal Properties
The Company's proved oil and gas properties are relatively concentrated.
Approximately 76% of the PV-10 from the Company's proved reserves at December
31, 2000 was attributable to four principal areas.
The following table presents data regarding the estimated quantities of
proved oil and gas reserves and the PV-10 attributable to the Company's
principal properties as of December 31, 2000, all of which are taken from
reports prepared by Huddleston & Co., Inc. in accordance with the rules and
regulations of the Securities and Exchange Commission (SEC).
December 31, 2000
-------------------------------------
Estimated Proved
Reserves
----------------------
Oil Gas
Property/Area (MBbls) (MMcf) MMcfe PV-10
------------- ------- ------ ------- --------------
(in thousands)
Hanlan-Robb (Canada)................... 109 45,263 45,917 $215,558
Oklahoma City Area..................... 2,329 2,761 16,735 38,971
South Louisiana Area................... 75 3,638 4,088 35,021
McLeod Field (Canada).................. 233 4,391 5,789 20,382
----- ------ ------- --------
Subtotal............................. 2,746 56,053 72,529 309,932
----- ------ ------- --------
Others................................. 1,464 19,206 27,990 100,323
----- ------ ------- --------
Total................................ 4,210 75,259 100,519 $410,255
===== ====== ======= ========
6
Hanlan-Robb. PetroCorp's largest single producing area is the Hanlan-Robb
natural gas production complex located in the foothills region of western
Alberta, Canada, which accounted for approximately 42% of the Company's 2000
net daily gas production. The Company owns an interest in eleven producing
fields in this area, covering 46,000 developed acres, with current combined
production of 240 MMcf/D. PetroCorp has additional interests in 80,000
undeveloped acres in this area. The key field is the Hanlan Swan Hills Gas
Unit #1, with a current gross production of 134 MMcf/D. PetroCorp's ownership
is part of a joint venture managed by the Company with institutional investors
that collectively own 21.7% of the field. PetroCorp's working interest in this
field is 35% of the joint venture, or 7.6%. Petro-Canada (not an affiliate of
PetroCorp) is the largest interest owner in the area and operates the Hanlan-
Robb area fields and the related gathering system and processing plant. Other
PetroCorp fields in this area include Shaw/Basing, Minehead, Columbia, Red
Cap, Lambert, Banshee and Medicine Lodge.
Oklahoma City Area. Includes the Southwest Oklahoma City Field located
within the metropolitan Oklahoma City area in Oklahoma and the Edmond Prospect
located just north of Oklahoma City. In the Southwest Oklahoma City Field
area, PetroCorp operates 61 wells and has a working interest in two additional
wells. The Company also owns a 4% working interest in the adjacent Will Rogers
Unit, operated by Marathon. The key property is the PetroCorp operated SW
Oklahoma City Unit, a field-wide waterflood unit targeting the Prue formation
at 6,500 feet. Current unit production is approximately 400 BOPD and 2,200
Mcf/D. The Company owns an 86.4% working interest in the unit.
South Louisiana Area. Includes ownership in the East Riceville Field in
Vermillion Parish and the Scott Field in Lafayette Parish. East Riceville is a
two-well gas field producing 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.
McLeod Field. As part of an acquisition in late 1996, the Company acquired
one shut-in oil well in this field in west central Alberta, Canada. Since
then, PetroCorp has drilled seven successful wells and acquired an interest in
two producing wells. A gas conservation project is expected to be completed in
early 2001 to capture flared solution gas from the oil wells. The Company's
working interests vary from 12% to 100% in 9.8 sections (approximately 6,240
acres).
Other Properties. Other significant U.S. properties include the Glick Field
located in south-central Kansas, the Hunter Misener Unit located in Alfalfa
County, Oklahoma, the Maynor Creek Field in Wayne County, Mississippi, the
Harris Field in Live Oak County, Texas, and the Paradox Basin area of
southwest Colorado. Other significant Canadian properties include the Trochu
Prospect in south-central Alberta and the Worsley Triassic A Pool located on
the north flank of the Peace River Arch in Alberta.
Title to Properties
United States. Except for the Company-owned mineral fee, royalty and
overriding royalty interests shown in the "Acreage and Wells" table below,
substantially all of the Company's United States property interests are held
pursuant to leases from third parties. The Company believes that it has
satisfactory title to its properties in accordance with standards generally
accepted in the oil and gas industry. In numerous instances, the Company has
acquired legal title to producing properties and has carved out of the
properties so acquired net profits royalty interests in favor of institutional
investors who supplied a substantial portion of the funds for the acquisition
of such properties. The producing property reserves of the Company are stated
after giving effect to the reduction in cash flow attributable to such net
profits royalty interests. In addition, the Company's properties are subject
to customary royalty interests, liens for current taxes and other burdens that
the Company believes do not materially interfere with the use of or affect the
value of such properties.
Canada. Canadian property interests are held primarily under leases from
the Crown. A small percentage are from freehold owners. Prior to drilling on a
non-Crown lease or acquiring a non-Crown producing lease, the Company
generally obtains a title opinion covering the "historical" (freehold) title.
The Company generally
7
relies on a title certificate under Canada's Torrens title registration system
to verify "current" (leasehold) ownership. Except for these differences, title
matters in Canada are similar to those in the United States.
Oil and Gas Reserves
All information herein regarding estimates of the Company's proved
reserves, related future net revenues and PV-10 is taken from reports prepared
by Huddleston & Co., Inc. (the Independent Engineers) in accordance with the
rules and regulations of the SEC. The Independent Engineers' estimates were
based upon a review of production histories and other geologic, economic,
ownership and engineering data provided by the Company.
The following table sets forth summary information with respect to the
estimates made by the Independent Engineers of the Company's proved oil and
gas reserves as of December 31, 2000. The PV-10 values shown in the table are
not intended to represent the current market value of the estimated oil and
gas reserves owned by the Company. The average prices used in determining
future cash inflows for natural gas and oil as of December 31, 2000, were
$9.19 per Mcf and $27.16 per barrel, respectively. These prices were based on
the adjusted cash spot price for natural gas and oil at December 31, 2000.
These prices are significantly higher than the average natural gas and oil
price received by PetroCorp during December 2000, and the prices PetroCorp
expects to receive during 2001 and ensuing years.
December 31, 2000
--------------------------
United
States Canada Total
-------- -------- --------
Proved reserves:
Oil (MBbls).................................... 3,109 1,101 4,210
Gas (MMcf)..................................... 22,709 52,550 75,259
Gas equivalents (MMcfe)........................ 41,363 59,156 100,519
Future net revenues ($000s)...................... $255,686 $467,251 $722,937
Present value of future net revenues ($000s)..... $152,123 $258,132 $410,255
Proved developed reserves:
Oil (MBbls).................................... 2,888 1,068 3,956
Gas (MMcf)..................................... 20,551 46,624 67,175
Gas equivalents (MMcfe)........................ 37,879 53,032 90,911
Future net revenues ($000s)...................... $228,084 $417,264 $645,348
Present value of future net revenues ($000s)..... $130,596 $228,797 $359,393
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and future
amounts and timing of development expenditures, including many factors beyond
the control of the Company. Reserve engineering is a subjective process of
estimating underground accumulations of crude oil and natural gas that cannot
be measured in an exact manner, and the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Estimates of proved undeveloped reserves are
inherently less certain than estimates of proved developed reserves. The
quantities of oil and gas that are ultimately recovered, production and
operating costs, the amount and timing of future development expenditures,
geologic success and future oil and gas sales prices may all differ from those
assumed in these estimates. In addition, the Company's reserves may be subject
to downward or upward revision based upon production history, purchases or
sales of properties, results of future development, prevailing oil and gas
prices and other factors. Therefore, the present value shown above should not
be construed as the current market value of the estimated oil and gas reserves
attributable to the Company's properties.
In accordance with SEC guidelines, the Independent Engineers' estimates of
future net revenues from the Company's proved reserves and the present value
thereof are made using oil 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
8
contractual price escalations. See "Marketing" under Item 1 of this report,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Item 7 of this report and "Supplemental Information to
Consolidated Financial Statements" in the Notes to the Consolidated Financial
Statements of the Company. Estimates of the Company's proved oil and gas
reserves were not filed with or included in reports to any other federal
authority or agency other than the SEC during the fiscal year ended December
31, 2000.
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, 2000.
Developed Undeveloped
Acres Acres(1)
-------------- --------------
Gross Net Gross Net
------- ------ ------- ------
United States:
Colorado..................................... 10,186 7,958 -- --
Kansas....................................... 5,360 667 10 1
Louisiana.................................... 2,091 202 661 71
Mississippi.................................. 640 405 10,735 6,257
Oklahoma..................................... 39,629 9,708 12,783 5,092
Texas........................................ 34,020 3,386 50,030 3,590
Other........................................ 1,807 343 5,109 480
Canada:
Alberta...................................... 59,920 10,130 107,520 13,808
------- ------ ------- ------
Total...................................... 153,653 32,799 186,848 29,299
======= ====== ======= ======
- --------
(1) Approximately 16% of net undeveloped acres are covered by leases that
expire during 2001, unless drilling or production otherwise extends lease
terms.
As of December 31, 2000, the Company had working interests in 233 gross (75
net) producing oil wells and 197 gross (35 net) producing gas wells. Of these
wells, 20 gross (18 net) oil wells and 56 gross (11 net) gas wells were in
Canada, and the remainder of the oil and gas wells were in the United States.
9
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, 2000, 1999 and 1998 is set forth below:
Year Ended December 31,
----------------------------------------------
2000 1999 1998
-------------- -------------- --------------
Net Net Net
Working Working Working
Type of Well Gross Interest Gross Interest Gross Interest
------------ ----- -------- ----- -------- ----- --------
United States
Development:
Oil........................... 4 .2 4 .2 -- --
Gas........................... 5 .3 1 .0(1) 9 1.3
Nonproductive................. 1 .2 1 .2 -- --
--- --- --- --- --- ---
Total....................... 10 .7 6 .4 9 1.3
--- --- --- --- --- ---
Exploratory:
Oil........................... -- -- -- -- -- --
Gas........................... -- -- -- -- 2 .3
Nonproductive................. 1 .0(1) 1 .2 8 2.6
--- --- --- --- --- ---
Total....................... 1 .0 1 .2 10 2.9
--- --- --- --- --- ---
Canada
Development:
Oil........................... 1 1 1 1 -- --
Gas........................... 6 1.1 2 .2 2 .1
Nonproductive................. -- -- 2 .0(1) -- --
--- --- --- --- --- ---
Total....................... 7 2.1 5 1.2 2 .1
--- --- --- --- --- ---
Exploratory:
Oil........................... -- -- -- -- -- --
Gas........................... 3 .4 4 .2 2 1.1
Nonproductive................. -- -- 3 .1 2 1.2
--- --- --- --- --- ---
Total....................... 3 .4 7 .3 4 2.3
--- --- --- --- --- ---
Total........................... 21 3.2 19 2.1 25 6.6
=== === === === === ===
- --------
(1) The Company has a net working interest less than 0.05% in these wells.
At December 31, 2000, the Company was participating in the drilling of 3
gross (.3 net) wells. Of these, 1 gross (.1 net) was in the United States and
2 gross (.2 net) were in Canada.
Hanlan-Robb Natural Gas Processing Plant and Gas Gathering Systems
PetroCorp owns interests in a centrally located gas processing plant and in
a gas gathering system that connects all of the Company's currently producing
Hanlan-Robb fields to the Hanlan-Robb plant. Commissioned in 1983, the
estimated replacement value is approximately $340 ($C500) million. The
original design capacity of 300 MMcf/D has been expanded to 380 MMcf/D and two
new major pipeline systems began delivering third-party gas to the plant for
processing in September 1998. This third-party gas, for which processing fees
are received, plus gas from additional drilling in the area, has increased
plant throughput from 220 MMcf/D to approximately 340 MMcf/D at year-end 2000.
PetroCorp owns a 24.5% working interest in the plant and varying working
interests in the gathering systems, dehydration and compression facilities
that deliver gas to the plant.
10
Previously a wholly-owned subsidiary of the Company, Fidelity Gas Systems,
Inc. ("FGS"), owned and operated the Anasazi Gas Gathering System, which
gathers gas produced from the Company-operated lease in the Paradox Basin area
of southwest Colorado. In December 1997, FGS was merged into the Company. The
working interest owners have entered into contracts with the Company pursuant
to which the Company purchases all of the gas produced from the area. This gas
is then resold by the Company to a purchaser at a redelivery point on the
national transmission pipeline system. Proceeds payable by the Company are
based upon the Company's resale price less a contractually agreed-upon fee.
Amounts received by the Company are distributed to all working interest and
royalty owners in the producing area in accordance with their ownership
interests. Because it is a gas gathering system, the Anasazi Gas Gathering
System has been deemed nonjurisdictional with respect to existing FERC rules
and regulations.
Other Facilities
In 2000, the Company found a replacement lessee for approximately 31,600
square feet in Houston, Texas where its primary office was previously located.
The Company leases, and subleases to others, approximately 8,200 square feet
in Oklahoma City, Oklahoma and approximately 4,000 square feet in Calgary,
Alberta where divisional offices were previously located. The obligation under
these leases will end in 2001 for the Oklahoma City lease and 2002 for the
Calgary lease. Additionally, the Company owns an 18,400 square-foot building
and surface pads covering approximately 42 acres related to its Southwest
Oklahoma City Field operations.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Current and prospective stockholders should carefully consider the
following risk factors in evaluating an investment in PetroCorp. The
information discussed herein includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of
historical facts included herein regarding planned capital expenditures,
increases in oil and gas production, the number of anticipated wells to be
drilled after the date hereof, the Company's financial position, business
strategy and other plans and objectives for future operations, are forward-
looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, they do involve
certain assumptions, risks and uncertainties, and the Company can give no
assurance that such expectations will prove to have been correct. The
Company's actual results could differ materially from those anticipated in
these forward-looking statements as a result of certain factors, including
those set forth in the following risk factors.
All subsequent written and oral forward-looking statements attributable to
the Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
Volatile Nature of Oil and Gas Markets; Fluctuations in Prices
The Company's future financial condition and results of operations are
highly dependent on the demand and prices received for oil and gas production
and on the costs of acquiring, developing and producing reserves. Oil and gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the Company's control. These factors include political
conditions in the Middle East and elsewhere, domestic and foreign supply of
oil and gas, the level of consumer demand, weather conditions, domestic and
foreign government regulations and taxes, the price and availability of
alternative fuels and overall economic conditions. A decline in oil or gas
prices may adversely affect the Company's cash flow, liquidity and
profitability. Lower oil or gas prices also may reduce the amount of the
Company's oil and gas that can be produced economically.
11
Dependence on Acquiring and Finding Additional Reserves
The Company's prospects for future growth and profitability will depend
predominantly on its ability to replace present reserves through acquisitions
and exploratory drilling, as well as on its ability to successfully develop
additional reserves. There can be no assurance that the Company's acquisition
and exploration activities or planned development projects will result in
significant additional reserves or that the Company will have continuing
success at drilling economically productive wells.
Substantial Capital Requirements
The Company has made substantial capital expenditures in connection with
the acquisition, exploration and development of oil and gas properties. Future
cash flows and the availability of credit are subject to a number of
variables, such as the level of production from existing wells, prices of oil
and gas and the Company's success in locating and producing new reserves. If
revenues were to decrease as a result of lower oil and gas prices, decreased
production or otherwise, and the Company had no available credit, the Company
could be limited in its ability to replace its reserves or to maintain
production at current levels, resulting in a decrease in production and
revenue over time. If the Company's cash flow from operations and available
credit are not sufficient to satisfy its capital expenditure requirements,
there can be no assurance that additional debt or equity financing will be
available to meet these requirements.
Reliance on Estimates of Reserves and Future Net Cash Flows
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves, including many factors beyond the Company's
control. Petroleum engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. Estimates of economically recoverable oil and gas reserves and of
future net cash flow necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area compared with
production from other producing areas, the assumed effects of regulation by
governmental agencies, assumptions concerning future oil and gas prices,
future operating costs, severance and excise taxes, development costs and
workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of
the future net cash flows expected therefrom prepared by different engineers
or by the same engineers at different times may vary significantly. Actual
production, revenues and expenditures with respect to the Company's reserves
likely will vary from estimates, and such variances may be material. In
addition, the Company's reserves and future cash flows may be subject to
revisions based upon production history, results of future development, oil
and gas prices, performance of counterparties under agreements to which the
Company is a party, operating and development costs and other factors.
The PV-10 values referred to herein should not be construed as the current
market value of the estimated oil and gas reserves attributable to the
Company's properties. In accordance with applicable requirements of the SEC,
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.
12
Exploration Risks
Exploratory drilling activities are subject to many risks, including the
risk that no commercially productive reservoirs will be encountered, and there
can be no assurance that new wells drilled by the Company will be productive
or that the Company will recover all or any portion of its investment.
Drilling for oil and gas may involve unprofitable efforts, not only from non-
productive wells, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs. The cost of drilling, completing and operating wells is often
uncertain. The Company's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, many of which are beyond the
Company's control, including title problems, weather conditions, compliance
with governmental requirements and shortages or delays in the delivery of
equipment and services.
Marketing Risks
The Company's ability to market its oil and gas production at commercially
acceptable prices is dependent on, among other factors, the availability and
capacity of gathering systems and pipelines, federal and state regulation of
production and transportation, general economic conditions, and changes in
supply and in demand.
Acquisition Risks
Acquisitions of oil and gas businesses and properties and volumetric
production payments have been an important element of the Company's success,
and the Company will continue to seek acquisitions in the future. Even though
the Company performs a review (including a limited review of title and other
records) of the major properties it seeks to acquire that it believes is
consistent with industry practices, such reviews are inherently incomplete and
it is generally not feasible for the Company to review in-depth every property
and all records. Even an in-depth review may not reveal existing or potential
problems or permit the Company to become familiar enough with the properties
to assess fully their deficiencies and capabilities, and the Company often
assumes environmental and other liabilities in connection with acquired
businesses and properties.
Operating Risks
The Company's operations are subject to numerous risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as
oil spills, natural gas leaks, ruptures or discharges of toxic gases, the
occurrence of any of which could result in substantial losses to the Company
due to injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. The Company's operations may be materially
curtailed, delayed or canceled as a result of numerous factors, including the
presence of unanticipated pressure or irregularities in formations, accidents,
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. In accordance with
customary industry practice, the Company maintains insurance against some, but
not all, of the risks described above. There can be no assurance that the
levels of insurance maintained by the Company will be adequate to cover any
losses or liabilities.
Competitive Industry
The oil and gas industry is highly competitive. The Company competes for
corporate and property acquisitions and the exploration, development,
production, transportation and marketing of oil and gas, as well as
contracting for equipment and securing personnel, with major oil and gas
companies, other independent oil and gas concerns and individual producers and
operators. Many of these competitors have financial and other resources which
substantially exceed those available to the Company.
13
Risks That Might Arise from the Management Agreement
Potential operational inefficiencies may occur during a transition period.
Although a change is not currently anticipated, the Management Agreement with
Kaiser-Francis provides for termination by either party after a six-month
notice. In that unlikely event, some operational inefficiencies may occur as
replacement personnel become familiar with the Company's properties and
operations.
Government Regulation
The Company's business is subject to certain federal, state and local laws
and regulations relating to the drilling for and production, transportation
and marketing of oil and gas, as well as environmental and safety matters.
Such laws and regulations have generally become more stringent in recent
years, often imposing greater liability on an increasing number of parties.
Because the requirements imposed by such laws and regulations are frequently
changed, the Company is unable to predict the effect or cost of compliance
with such requirements or their effects on oil and gas use or prices. In
addition, legislative proposals are frequently introduced in Congress and
state legislatures which, if enacted, might significantly affect the oil and
gas industry. In view of the many uncertainties which exist with respect to
any legislative proposals, the effect on the Company of any legislation which
might be enacted cannot be predicted.
Item 3. Legal Proceedings.
The Company is a party to various lawsuits and governmental proceedings,
all arising in the ordinary course of business. Although the outcome of these
lawsuits cannot be predicted with certainty, the Company does not expect such
matters to have a material adverse effect, either singly or in the aggregate,
on the financial position of the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
14
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
The Company's Common Stock is currently listed on the American Stock
Exchange (the "AMEX") and trades under the symbol PEX. The Company's Common
Stock has been listed with the AMEX since September 17, 1998. Prior to that
time, the Company's Common Stock had been listed on The Nasdaq Stock Market
since October 28, 1993. The following table presents the high and low closing
prices for the Company's Common Stock for each quarter during 1999 and 2000,
and for a portion of the Company's current quarter, as reported by the AMEX.
1999 2000 2001
------------------------------- ------------------------------- -------------------------
First Quarter
First Second Third Fourth First Second Third Fourth (through
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter February 28)
------- ------- ------- ------- ------- ------- ------- ------- -------------
High.................... $5.88 $6.13 $7.50 $6.88 $6.75 $7.25 $9.88 $10.19 $10.63
Low..................... 5.19 4.38 5.50 5.75 5.25 5.50 7.00 8.63 9.69
As of February 28, 2001, the closing price for the Company's Common Stock
was $9.75 per share. As of February 28, 2001, there were approximately 500
holders of record of the Common Stock.
The Company has not declared or paid any cash dividends on its Common Stock
to date. The Board of Directors of the Company does not intend to declare cash
dividends on its Common Stock in the foreseeable future. The Company intends
instead to retain its earnings to support the growth of the Company's
business. Any future cash dividends would depend on future earnings, capital
requirements, the Company's financial condition and other factors deemed
relevant by the Company's Board of Directors. The terms of the Company's
credit facility prohibits the declaration or payment of any dividends.
15
Item 6. Selected Financial Data.
The following table summarizes consolidated financial data of the Company
and should be read in conjunction with the "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the
Consolidated Financial Statements of the Company, including the Notes thereto,
included elsewhere in this report.
For the Year Ended December 31,
------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
Income Statement Data:
Revenues:
Oil and gas................ $ 42,264 $ 25,162 $ 23,621 $ 33,502 $ 29,718
Plant processing........... 1,934 1,785 1,550 1,420 1,658
Other...................... 375 179 36 172 170
-------- -------- -------- -------- --------
44,573 27,126 25,207 35,094 31,546
-------- -------- -------- -------- --------
Expenses:
Production costs........... 8,038 6,733 7,344 7,793 6,660
Depreciation, depletion and
amortization.............. 9,471 9,906 16,568 17,065 12,433
Oil and gas property
valuation adjustment...... -- -- 33,600 -- --
General and
administrative............ 1,529 4,311 4,482 4,846 4,542
Restructuring costs........ (445) 3,643 -- -- --
Other operating expenses... 309 281 265 367 333
-------- -------- -------- -------- --------
18,902 24,874 62,259 30,071 23,968
-------- -------- -------- -------- --------
Income (loss) from
operations.................. 25,671 2,252 (37,052) 5,023 7,578
-------- -------- -------- -------- --------
Other income (expenses):
Investment income.......... 584 585 1,151 558 1,910
Interest expense........... (3,381) (3,865) (3,622) (3,528) (3,391)
Other income (expenses).... 295 (132) 14 (47) (46)
-------- -------- -------- -------- --------
(2,502) (3,412) (2,457) (3,017) (1,527)
-------- -------- -------- -------- --------
Income (loss) before income
taxes....................... 23,169 (1,160) (39,509) 2,006 6,051
-------- -------- -------- -------- --------
Income tax provision
(benefit):
Current.................... 5,497 -- -- -- --
Deferred................... 4,612 (954) (15,114) 136 1,807
-------- -------- -------- -------- --------
10,109 (954) (15,114) 136 1,807
-------- -------- -------- -------- --------
Net income (loss) before
extraordinary item.......... 13,060 (206) (24,395) 1,870 4,244
Extraordinary loss--
extinguishment of debt (less
applicable tax benefit of
$143,000)................... 242 -- -- -- --
-------- -------- -------- -------- --------
Net income (loss)............ $ 12,818 $ (206) $(24,395) $ 1,870 $ 4,244
======== ======== ======== ======== ========
Net income (loss) per share--
basic(A).................... $ 1.47 $ (0.02) $ (2.82) $ 0.22 $ 0.49
======== ======== ======== ======== ========
Net income (loss) per share--
diluted(A).................. $ 1.46 $ (0.02) $ (2.82) $ 0.22 $ 0.49
======== ======== ======== ======== ========
Weighted average number of
common shares--basic........ 8,692 8,658 8,637 8,586 8,585
======== ======== ======== ======== ========
Weighted average number of
common shares--diluted...... 8,786 8,658 8,637 8,688 8,669
======== ======== ======== ======== ========
Balance Sheet Data (at
December 31):
Working capital............ $ 9,029 $ 3,642 $ 2,080 $ 2,638 $ 1,946
Total assets............... 117,319 105,395 103,992 130,924 122,864
Long-term debt............. 29,992 43,410 47,305 42,192 33,462
Shareholders equity........ 54,277 42,363 40,744 66,557 65,665
- -------
(A) Basic and diluted net income per share before extraordinary loss for the
year ended December 31, 2000 was $1.50 and $1.49, respectively.
16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
General
The Company's principal line of business is the production and sale of its
oil and natural gas reserves located in North America. Results of operations
are dependent upon the quantity of production and the price obtained for such
production. Prices received by the Company for the sale of its oil and natural
gas have fluctuated significantly from period to period. Such fluctuations
affect the Company's ability to maintain or increase its production from
existing oil and gas properties and to explore, develop or acquire new
properties.
The following table reflects certain operating data for the periods
presented:
For the Year Ended
December 31,
-----------------------
2000 1999 1998
------- ------- -------
Production:
United States:
Oil (Mbbls)..................................... 294 324 422
Gas (MMcf)...................................... 3,850 4,421 4,932
Gas equivalents (MMcfe)......................... 5,614 6,365 7,464
Canada:
Oil (Mbbls)..................................... 110 138 143
Gas (MMcf)...................................... 4,519 4,660 4,579
Gas equivalents (MMcfe)......................... 5,179 5,488 5,437
Total:
Oil (Mbbls)..................................... 404 462 565
Gas (MMcf)...................................... 8,369 9,081 9,511
Gas equivalents (MMcfe)......................... 10,793 11,853 12,901
Average sales prices:
United States:
Oil (per Bbl)................................... $ 26.38 $ 17.33 $ 12.55
Gas (per Mcf)................................... 4.08 2.24 2.15
Canada:
Oil (per Bbl)................................... 25.49 16.48 11.59
Gas (per Mcf)................................... 3.54 1.58 1.32
Weighted average:
Oil (per Bbl)................................... 26.14 17.08 12.31
Gas (per Mcf)................................... 3.79 1.90 1.75
Selected data per Mcfe:
Average sales price.............................. $ 3.92 $ 2.13 $ 1.83
Production costs................................. 0.74 0.57 0.57
General and administrative expenses.............. 0.14 0.36 0.35
Oil and gas depreciation, depletion and
amortization.................................... 0.74 0.69 1.16
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
17
fees of no more than $50 per well for non-operated properties. Fees for 2000
and 1999, respectively, were $1,419,000 and $218,000.
The Company recorded restructuring costs of $3,643,000 during 1999.
Included in the costs are employee termination costs of $2,371,000, $807,000
in nonrefundable office lease discontinuance, $363,000 in investment banking
and legal costs, and $102,000 in other related costs. As of December 31, 1999,
$2,161,000 of the restructuring costs are included in accrued liabilities.
As a result of the restructuring, fifty-two employees were terminated in
1999 with one employee terminated in 2000. Several employees elected to defer
receipt of their termination benefits until 2000. The Houston, Oklahoma City
and Calgary offices were closed but the Company was still liable under the
lease agreements. In the second quarter of 2000, the Company was able to find
a replacement lessee for some of the idle office space earlier than
anticipated. The following table shows the change in accrued restructuring
costs during 2000:
Balance at Expenditures Balance at
December 31, charged Changes December 31,
1999 against accrual in estimates 2000
------------ --------------- ------------ ------------
Employee termination
costs.................. $1,341,000 $1,341,000 $ -- $ --
Office lease
discontinuance and
other related costs.... 820,000 305,000 (445,000) 70,000
---------- ---------- --------- -------
$2,161,000 $1,646,000 $(445,000) $70,000
========== ========== ========= =======
Results of Operations
2000 Compared to 1999
Overview. The Company recorded net income of $12,818,000 or $1.47 per share
in 2000, compared to a loss of $206,000, or $0.02 per share, for the
corresponding period of 1999. This improvement results from higher oil and gas
prices and lower general and administrative, restructuring costs and
depreciation, depletion, and amortization expenses.
Revenues. Total revenues increased 64% to $44.6 million in 2000 compared to
$27.1 million in 1999. Oil production decreased 13% to 404 MBbls from 462
MBbls. Natural gas production decreased 8% to 8,369 MMcf from 9,081 MMcf,
resulting in overall production decreasing 9% to 10,793 MMcfe from 11,853
MMcfe. Production decreases are due to normal production declines.
The Company's average U.S. natural gas price increased 82% to $4.08 per Mcf
in 2000 from $2.24 per Mcf in 1999, while the average Canadian natural gas
price increased 124% to $3.54 from $1.58. The Company's composite average oil
price increased 53% to $26.14 per barrel in 2000 from $17.08 per barrel in
1999. Primarily as a result of price increases, oil and gas revenues increased
68% to $42.3 million in 2000 from $25.2 million in 1999. Plant processing
revenues increased 8% to $1.9 million from $1.8 million primarily as a result
of new third party processing in the Canadian Hanlan-Robb gas processing
plant.
Production Costs. Production costs increased 19% to $8.0 million in 2000
compared to $6.7 million in 1999 as a result of workover operations for
repairs and production enhancements and production tax increases related to
higher commodity prices. Production costs per Mcfe were $0.74 for 2000 and
$0.57 for 1999. Approximately $0.18 per Mcfe of increased costs are due to
workover operations and increased production taxes.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 4% to
$9.5 million in 2000 from $9.9 million in 1999. The increase in the oil and
gas DD&A rate per Mcfe to $0.74 in 2000 from $0.69 in 1999 reflects the impact
of previously unevaluated properties evaluated in 2000 and moved into the full
cost pool.
General and Administrative Expenses. General and administrative expenses
decreased 65% to $1.5 million in 2000 from $4.3 million in 1999 as a result of
the Company's restructuring efforts and the Management Agreement with Kaiser-
Francis.
18
Investment Income. Investment income decreased less than 1% to $584,000 in
2000 from $585,000 in 1999.
Interest Expense. Interest expense decreased 13% to $3.4 million in 2000
from $3.9 million in 1999, reflecting the impact of reduced debt levels,
partially offset by an increase in interest rates.
Income Taxes. The Company recorded a $10.1 million income tax expense on
pre-tax income of $23.2 million with an effective tax rate of 44% in 2000
compared to an income tax benefit of $954,000 on a pre-tax loss of $1.2
million with an effective tax rate of 82% in 1999. During 2000, the Company
recorded an income tax provision for its Canadian operations with an effective
tax rate of 47% and tax provision for its U.S. operations with an effective
tax rate of 39%, resulting in an overall effective tax rate of 44%. Effective
tax rates in excess of statutory rates are primarily due to adjustments of
approximately $1.2 million resulting from audits by Canadian tax authorities.
1999 Compared to 1998
Overview. Net loss decreased 99% to a loss of $.2 million, or $0.02 per
share, compared to a loss of $24.4 million, or $2.82 per share, for the
corresponding period. Net income in 1998 was significantly impacted by a $33.6
million oil and gas property valuation adjustment while 1999 net income was
impacted by $3,643,000 of restructuring costs.
Revenues. Total revenues increased 7% to $27.1 million in 1999 compared to
$25.2 million in 1998. Oil production decreased 18% to 462 MBbls from 565
MBbls. Natural gas production decreased 5% to 9,081 MMcf from 9,511 MMcf,
resulting in overall production decreasing 8% to 11,853 MMcfe from 12,901
MMcfe.
The Company's average U.S. natural gas price increased 4% to $2.24 per Mcf
in 1999 from $2.15 per Mcf in 1998, while the average Canadian natural gas
price increased 20% to $1.58 from $1.32. The Company's composite average oil
price increased 39% to $17.08 per barrel in 1999 from $12.31 per barrel in
1998. Primarily as a result of price increases, oil and gas revenues increased
7% to $25.2 million in 1999 from $23.6 million in 1998. Plant processing
revenues increased 15% to $1.8 million from $1.6 million primarily as a result
of new third party processing in the Canadian Hanlan-Robb gas processing
plant.
Production Costs. Production costs decreased 8% to $6.7 million in 1999
compared to $7.3 million in 1998 primarily as a result of the 8% decrease in
production volumes. Production costs per Mcfe were $0.57 for both 1999 and
1998.
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 40% to
$9.9 million in 1999 from $16.6 million in 1998. The decrease in the oil and
gas DD&A rate per Mcfe to $0.69 in 1999 from $1.16 in 1998 reflects the impact
of the year-end 1999 increase in proved reserves and the impact of the 1998
oil and gas property valuation adjustment.
General and Administrative Expenses. General and administrative expenses
decreased 4% to $4.3 million in 1999 from $4.5 million in 1998. The overall
decrease is primarily due to cost reduction efforts, including reductions in
personnel. This decrease was partially offset by $805,000 of incentives paid
to now-terminated employees to induce them to stay through the close down of
existing offices.
Investment Income. Investment and other income decreased 49% to $585,000 in
1999 from $1.2 million in 1998, primarily as a result of gas contract
settlements received in 1998.
Interest Expense. Interest expense increased 7% to $3.9 million in 1999
from $3.6 million in 1998, reflecting the impact of increased debt associated
with a producing property acquisition completed in June 1998.
Income Taxes. The Company recorded a $954,000 income tax benefit on pre-tax
loss of $1.2 million with an effective tax rate of 82% in 1999 compared to an
income tax benefit of $15.1 million on pre-tax loss of $39.5 million with an
effective tax rate of 38% in 1998. During 1999, the Company recorded an income
tax provision for its Canadian operations with an effective tax rate of 7%
which was offset by an income tax benefit for its U.S. operations with an
effective tax rate of 28%, resulting in an overall effective tax rate of 82%.
19
Liquidity and Capital Resources
As of December 31, 2000, the Company had working capital of $9.0 million as
compared to $3.6 million at December 31, 1999. Cash provided by operating
activities was $33.2 million, $10.6 million and $10.7 million in 2000, 1999
and 1998, respectively.
The Company's total capital expenditures were $8.2 million, $3.3 million
and $19.4 million for 2000, 1999 and 1998, respectively. In 2000, the Company
spent $7.1 million related to exploration and development and $579,000 related
to acquisitions of oil and gas properties. During 1999, the Company spent $2.6
million related to exploration and development and $.4 million related to
acquisitions. In 1998, the Company spent $11.6 million related to exploration
and development and $4.8 million related to acquisitions.
Sales of oil and gas properties totaled $.2 million, nil, and $2.8 million
in 2000, 1999 and 1998, respectively.
In June 1997, the Company entered into a $50 million five-year revolving
credit agreement with the Toronto-Dominion Bank, the agent, and the Bank of
Nova Scotia. On June 30, 1997, the Company was advanced $13.0 million to fund
an acquisition of producing properties completed in early July 1997 and to
fund certain debt repayments. During 1998, the Company borrowed $12.0 million
to fund additional acquisitions and other debt repayments. At December 31,
1999, the Company had a total of $27.0 million outstanding under the revolver
and $3,850,000 available based on the current borrowing base, as defined,
subject to certain limitations. The facility was amended in June 1998 to
extend the initial five-year term an additional year to July 1, 2003 with
quarterly borrowing base amortization beginning September 30, 2001. The
borrowings can be funded by either Eurodollar loans or Prime loans. The
interest rate on the borrowings is equal to an interest rate spread plus
either the Eurodollar rate or the Prime rate. The interest spread is
determined from a sliding scale based on the Company's borrowing base
percentage utilization in effect from time to time. The spread ranges from 1-
3/8% to 2% on Eurodollar loans and 3/8% to 1% on Prime loans. The Company's
average interest rate under this facility was approximately 8.4% through July
21, 2000, which was the date this facility was terminated.
In June 2000, the revolving credit agreement was amended to increase the
current borrowing base to $40 million and change the termination date to July
31, 2000, pending a new loan agreement between Toronto-Dominion, as agent, and
the Company. The new loan agreement was successfully completed in July 2000
(see next paragraph). Also in June 2000, the Company paid off the Series B
fixed rate notes, using available capital and borrowings under the revolving
credit agreement. Early termination payments required by the Series B
agreement and remaining unamortized debt costs were expensed and are reflected
in the financial statements as an extraordinary item of $385,000, less
applicable taxes of $143,000.
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 term of the facility is through April 30, 2003 and the
initial borrowing base was set at $58 million. Borrowings can be funded by
either Eurodollar loans or Base Rate loans. The interest rate on the
borrowings is equal to an interest rate spread plus either the Eurodollar rate
or the Base Rate. The interest spread is determined from a sliding scale based
on the Company's borrowing base percentage utilization in effect from time to
time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25
on Base Rate loans. At December 31, 2000, the Company had a total of
$28,500,000 outstanding under the revolver and $29,500,000 available based on
the current borrowing base, as defined, subject to certain limitations. From
July 21, 2000, the date of inception of this facility, through December 31,
2000, the weighted average interest rate under this facility was approximately
8.3%.
The Company's Canadian subsidiary redeemed its redeemable preferred stock
on August 9, 1994 for $7.0 million and simultaneously issued $7.0 million in
nonrecourse long-term notes payable (Nonrecourse Notes Payable) with similar
financial terms. At December 31, 2000, the nonrecourse long-term notes payable
balance was $2.7 million, of which $1,194,000 was classified as "current."
The Company has historically funded its capital expenditures and working
capital requirements with its cash flow from operations, debt and equity
capital and participation by institutional investors. If the Company
20
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.
Possible Merger with Southern Mineral
As indicated in Note 11 to the financial statements and Part I, Item 1,
"Exploration and Development Activity", PetroCorp has entered into an
agreement to merge with Southern Mineral Corporation. Funds needed to complete
this transaction will be provided by cash on hand and borrowings under
existing lines of credit.
Subsequent to the signing of the merger agreement, PetroCorp purchased
shares of Southern Mineral common stock via open-market and negotiated
transactions. As of March 31, 2001, PetroCorp had acquired 738,836 shares of
Southern Mineral stock at an average price of $4.21 per share. As a result,
PetroCorp currently owns 6% of the outstanding shares of Southern Mineral
stock.
Year 2000 Issues
PetroCorp had no Year 2000 computer problems. Minimal costs were expended
in this area.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
The Company's primary sources of market risk are from fluctuations in
commodity prices, interest rates and exchange rates.
Commodity Price Risk
The Company produces and sells natural gas, crude oil, condensate, natural
gas liquids and sulfur. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response
to changing market forces. The Company has previously utilized hedging
transactions to manage its exposure to price fluctuations on its sales of oil
and natural gas. In 2000, the Company entered into swap transactions in an
effort to lock in a portion of higher oil and gas prices. The impact of
hedging transactions on 2000 financial results was a net reduction of revenues
by $1,097,000. No contracts were outstanding as of December 31, 2000. No hedge
transactions were in place during 1999 and 1998.
Interest Rate Risk
Total debt at December 31, 2000, included no fixed-rate debt. The Company
has elected to use only variable rate financing, therefore the Company has
limited control over interest rate changes, which may adversely affect the
Company's results of operations and cash flows. See Note 5 to the Consolidated
Financial Statements for information regarding future maturities of the
Company's debt.
Foreign Currency Exchange Rate Risk
The Company conducts a significant portion of its business in the Canadian
dollar and is therefore subject to foreign currency exchange rate risk on cash
flows related to sales, expenses, financing and investing transactions.
Exposure from market rate fluctuations related to activities in Canada, where
the Company's functional currency is the Canadian dollar, is not material at
this time.
Item 8. Financial Statements and Supplementary Data.
The information required by this item appears on pages 26 through 52 of
this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
There is no matter required to be disclosed in response to this item.
21
PART III
In accordance with paragraph (3) of General Instruction G to Form 10-K,
Part III of this Report is omitted because the Company will file with the
Securities and Exchange Commission not later than 120 days after the end of
the fiscal year ended December 31, 2000 a definitive proxy statement pursuant
to Regulation 14A involving the election of directors, which proxy statement
is incorporated herein by reference (with the exception of certain portions
noted therein that are not so incorporated by reference).
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements
Page
of
this
Report
------
Report of Independent Accountants...................................... 25
Consolidated Balance Sheets as of December 31, 2000 and December 31,
1999.................................................................. 26
Consolidated Statements of Operations for the Years Ended December 31,
2000, 1999 and 1998................................................... 27
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 2000, 1999 and 1998...................................... 28
Consolidated Statements of Cash Flows for the Years Ended December 31,
2000, 1999 and 1998................................................... 29
Notes to Consolidated Financial Statements............................. 30
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.
22
4.1* Rights Agreement dated as of November 12, 1998, between PetroCorp
Incorporated and First Union National Bank, as Rights Agent.
Incorporated by reference to Exhibit 4.1 to the Company's Form 8-K,
dated November 20, 1998.
4.2* Form of Right Certificate. Incorporated by reference to Exhibit 4.2 to
the Company's Form 8-K, dated November 20, 1998.
4.3* Specimen certificate for shares of Common Stock. Incorporated by
reference to Exhibit 4.1 to the Registration Statement.
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.
23
10.10* Agreement for Purchase and Sale, dated June 5, 1997, between PetroCorp
Incorporated and Great River Oil and Gas Corporation. Incorporated by
reference to Exhibit 2.1 to the Company's Current Report on Form 8-K
dated July 1, 1997.
10.11* First Amendment to Agreement for Purchase and Sale, dated June 30,
1997, between PetroCorp Incorporated and Great River Oil and Gas
Corporation. Incorporated by reference to Exhibit 2.2 to the Company's
Current Report on Form 8-K dated July 1, 1997.
10.12* Credit Agreement, dated 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.
21 List of material subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Huddleston & Co., Inc.
99.1* Agreement to furnish document relating to subsidiary. Incorporated by
reference to Exhibit 99.1 to the 1994 Form 10-K.
- --------
* Incorporated by reference.
(b) Reports on Form 8-K
Report dated December 22, 2000 regarding merger agreement with Southern
Mineral Corporation.
24
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,
2000 and 1999, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2000, 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 9, 2001
25
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEETS
December 31, 2000 and 1999
(in thousands, except share amounts)
2000 1999
ASSETS -------- --------
Current assets:
Cash and cash equivalents................................ $ 21,946 $ 12,899
Accounts receivable, net................................. 13,332 4,605
Other current assets..................................... 609 162
-------- --------
Total current assets................................... 35,887 17,666
-------- --------
Property, plant and equipment:
Proved oil and gas properties, at cost, full cost method,
net of accumulated depreciation, depletion and
amortization............................................ 66,400 63,998
Unproved oil and gas properties, not subject to
depletion............................................... 2,032 6,154
Plant and related facilities............................. 2,451 3,151
Other, net............................................... 53 403
-------- --------
70,936 73,706
-------- --------
Deferred income taxes...................................... 10,254 13,916
Other assets, net.......................................... 242 107
-------- --------
Total assets........................................... $117,319 $105,395
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable......................................... $ 17,732 $ 6,138
Accrued liabilities...................................... 2,488 3,609
Income tax payable....................................... 5,444 --
Current portion of long-term debt........................ 1,194 4,277
-------- --------
Total current liabilities.............................. 26,858 14,024
-------- --------
Long-term debt............................................. 29,992 43,410
-------- --------
Deferred income taxes...................................... 6,192 5,598
-------- --------
Commitments and contingencies (Note 11)
Shareholders' equity:
Preferred stock, $0.01 par value, 1,000,000 shares
authorized, none issued................................. -- --
Common stock, $0.01 par value, 25,000,000 shares
authorized, (8,703,719 shares and 8,683,019 shares
outstanding at December 31, 2000 and 1999,
respectively)........................................... 87 87
Additional paid-in capital............................... 71,614 71,380
Retained earnings (accumulated deficit).................. (11,712) (24,530)
Accumulated other comprehensive loss..................... (5,712) (4,574)
-------- --------
Total shareholders' equity............................. 54,277 42,363
-------- --------
Total liabilities and shareholders' equity............. $117,319 $105,395
======== ========
The accompanying notes are an integral part of these financial statements.
26
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2000, 1999 and 1998
(in thousands, except share amounts)
2000 1999 1998
------- ------- --------
Revenues:
Oil and gas..................................... $42,264 $25,162 $ 23,621
Plant processing................................ 1,934 1,785 1,550
Other........................................... 375 179 36
------- ------- --------
44,573 27,126 25,207
------- ------- --------
Expenses:
Production costs................................ 8,038 6,733 7,344
Depreciation, depletion and amortization........ 9,471 9,906 16,568
Oil and gas property valuation adjustment....... -- -- 33,600
General and administrative...................... 1,529 4,311 4,482
Restructuring costs............................. (445) 3,643 --
Other operating expenses........................ 309 281 265
------- ------- --------
18,902 24,874 62,259
------- ------- --------
Income (loss) from operations..................... 25,671 2,252 (37,052)
------- ------- --------
Other income (expenses):
Investment income............................... 584 585 1,151
Interest expense................................ (3,381) (3,865) (3,622)
Other income (expenses)......................... 295 (132) 14
------- ------- --------
(2,502) (3,412) (2,457)
------- ------- --------
Income (loss) before income taxes................. 23,169 (1,160) (39,509)
------- ------- --------
Income tax provision (benefit):
Current......................................... 5,497 -- --
Deferred........................................ 4,612 (954) (15,114)
------- ------- --------
10,109 (954) (15,114)
------- ------- --------
Net income (loss) before extraordinary item....... 13,060 (206) (24,395)
Extraordinary loss--extinguishment of debt (less
applicable tax benefit of $143,000).............. 242 -- --
------- ------- --------
Net income (loss)................................. $12,818 $ (206) $(24,395)
======= ======= ========
Net income (loss) per common share--basic:
Income (loss) before extraordinary item......... $ 1.50 $ (0.02) $ (2.82)
Extraordinary item.............................. (0.03) -- --
------- ------- --------
Net income (loss)............................... $ 1.47 $ (0.02) $ (2.82)
======= ======= ========
Net income (loss) per common share--diluted:
Income (loss) before extraordinary item......... $ 1.49 $ (0.02) $ (2.82)
Extraordinary item.............................. (0.03) -- --
------- ------- --------
Net income (loss)............................... $ 1.46 $ (0.02) $ (2.82)
======= ======= ========
Weighted average number of common shares--basic... 8,692 8,658 8,637
======= ======= ========
Weighted average number of common shares--
diluted.......................................... 8,786 8,658 8,637
======= ======= ========
The accompanying notes are an integral part of these financial statements.
27
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
Retained
Common Stock earnings Accumulated
------------- Additional (accumu- other
Shares paid-in lated comprehensive Treasury
issued Amount capital deficit) loss stock Total
------ ------ ---------- -------- ------------- -------- -------
Balance, December 31,
1997................... 8,616 $86 $71,143 $ 71 $(4,496) $(247) $66,557
Net loss.............. -- -- -- (24,395) -- -- (24,395)
Additional paid-in
capital.............. 40 1 102 -- -- -- 103
Accumulated other
comprehensive loss... -- -- -- -- (1,768) -- (1,768)
Treasury stock (24,697
shares).............. -- -- -- -- -- 247 247
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1998................... 8,656 87 71,245 (24,324) (6,264) -- 40,744
Net loss.............. -- -- -- (206) -- -- (206)
Exercise of stock
options.............. 27 -- 135 -- -- -- 135
Accumulated other
comprehensive
income............... -- -- -- -- 1,690 -- 1,690
Treasury stock........ -- -- -- -- -- -- --
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1999................... 8,683 87 71,380 (24,530) (4,574) -- 42,363
Net income............ -- -- -- 12,818 -- -- 12,818
Exercise of stock
options.............. 21 -- 234 -- -- -- 234
Accumulated other
comprehensive loss... -- -- -- -- (1,138) -- (1,138)
----- --- ------- -------- ------- ----- -------
Balance, December 31,
2000................... 8,704 $87 $71,614 $(11,712) $(5,712) $ -- $54,277
===== === ======= ======== ======= ===== =======
The accompanying notes are an integral part of these financial statements.
28
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2000, 1999 and 1998
(in thousands)
2000 1999 1998
-------- ------- --------
Cash flows from operating activities:
Net income (loss)............................... $ 12,818 $ (206) $(24,395)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Extraordinary loss............................ 242 -- --
Depreciation, depletion and amortization...... 9,471 9,906 16,568
Deferred income tax expense (benefit)......... 4,612 (954) (15,114)
Oil and gas property valuation adjustment..... -- -- 33,600
Other......................................... 107 (112) (437)
Changes in operating assets and liabilities:
Accounts receivable........................... (8,727) (36) 2,039
Other current assets.......................... (447) 164 11
Accounts payable.............................. 11,594 1,714 (1,743)
Accrued liabilities........................... (1,923) 142 122
Income taxes payable.......................... 5,444 -- --
-------- ------- --------
Net cash provided by operating activities... 33,191 10,618 10,651
-------- ------- --------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties.... 210 -- 2,812
Additions to oil and gas properties............. (6,862) (3,089) (18,260)
Additions to plant and related facilities....... (525) (166) (919)
Additions to other property, plant and
equipment...................................... -- -- (71)
Additions to other assets....................... (16) -- (144)
-------- ------- --------
Net cash used in investing activities......... (7,193) (3,255) (16,582)
-------- ------- --------
Cash flows from financing activities:
Proceeds from long-term debt.................... 30,030 2,238 14,845
Repayment of long-term debt..................... (46,714) (4,566) (10,876)
Other........................................... (142) 135 350
-------- ------- --------
Net cash provided by (used in) financing
activities................................... (16,826) (2,193) 4,319
-------- ------- --------
Effect of exchange rate changes on cash........... (125) (57) 7
-------- ------- --------
Net increase (decrease) in cash and cash
equivalents...................................... 9,047 5,113 (1,605)
Cash and cash equivalents at beginning of year.... 12,899 7,786 9,391
-------- ------- --------
Cash and cash equivalents at end of year.......... $ 21,946 $12,899 $ 7,786
======== ======= ========
Supplemental disclosure:
Interest paid................................... $ 3,423 $ 3,150 $ 3,573
======== ======= ========
Income taxes paid............................... $ -- $ -- $ --
======== ======= ========
The accompanying notes are an integral part of these financial statements.
29
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000, 1999 and 1998
1. Summary of Accounting Policies
General
PetroCorp Incorporated, a Texas corporation, is engaged in the acquisition,
exploration, development, and the production and sale of crude oil and natural
gas in North America. The terms "PetroCorp" and "Company" refer to PetroCorp
Incorporated and its subsidiaries. PetroCorp operates in Canada through its
wholly-owned Canadian subsidiaries as follows: PCC Energy Inc. (PCC Inc.), PCC
Energy Limited and PCC Energy Corp.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
Petrocorp Incorporated and its wholly-owned subsidiaries. All significant
intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the amounts reported in the financial statements and
the accompanying notes. Actual results may differ from such estimates. In
addition, the oil and gas reserve data and the deferred tax asset include
significant estimates which, in the near term, could materially differ from
the amounts ultimately realized.
Property, Plant and Equipment
The Company follows the full cost method of accounting for oil and gas
properties whereby all productive and nonproductive exploration and
development costs incurred for the purpose of finding oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and
geophysical work, delay rentals, drilling, completing and equipping oil and
gas wells, together with internal costs directly attributable to property
acquisition, exploration and development activities. No gains or losses are
recognized upon the sale or other disposition of oil and gas properties,
except in unusually significant transactions.
The costs of the Company's oil and gas properties, including estimated
future development and dismantlement costs, are depreciated on a country-by-
country basis using a composite unit-of-production rate. An additional
valuation adjustment is made on a country-by-country basis if net capitalized
costs of the Company's oil and gas properties exceed the capitalization
ceiling, which is calculated on a quarterly basis as the sum of (1) the
present value (10%) of future net revenues from estimated production of proved
oil and gas reserves plus (2) the lower of cost or estimated fair value of the
unproved properties, less (3) the related income tax effects. At December 31,
1998, the Company's net capitalized costs of its U.S. oil and gas properties
exceeded the capitalization ceiling by $21,168,000 resulting in a pre-tax
valuation adjustment of $33,600,000. Such valuation adjustment is reflected in
the Company's results of operations for the year ended December 31, 1998.
There was no valuation adjustment for the years ended December 31, 2000 and
1999.
Plant and related facilities, consisting principally of a gas processing
plant in Alberta, Canada, are being depreciated on a straight-line basis over
the remaining estimated useful life. Other property and equipment are
depreciated by the straight-line method at rates based on the estimated useful
lives of the assets ranging from five to ten years.
Revenue Recognition
Revenues from the sale of petroleum produced are recognized upon the
passage of title, net of royalties and net profits royalty interests.
30
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
Revenues from natural gas production are recorded using the sales method,
net of royalties and net profits interests, which may result in more or less
than the Company's share of pro-rata production from certain wells. The
Company estimates its balancing position to be approximately $277,000 (173,000
mcf) on underproduced properties and approximately $326,000 (204,000 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, 2000 and 1999, the Company
included $53,000 (33,000 mcf) and $40,000 (26,000 mcf) respectively, in
accrued liabilities with respect to overproduced imbalances. The Company's
policy is to expense the pro-rata share of lease operating costs from all
wells as incurred. Such expenses relating to the balancing position on wells
in which the Company has imbalances are not significant.
Revenues from plant processing are recognized at the time associated
natural gas is processed. Other revenues include fees associated with the
Company's U.S. gathering system and from the sale of sulfur in Canada.
Accounts Receivable
Accounts receivable relate primarily to sales of oil and gas and amounts
due from joint-interest partners for expenditures made by the Company on
behalf of such partners. The Company reviews the financial condition of
potential purchasers and partners prior to signing sales or joint-interest
agreements. At December 31, 2000 and 1999, 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 years ended December 31, 2000, 1999 and 1998, the Company recognized
foreign currency transaction losses of $98,000, $22,000 and $2,000,
respectively.
Cash Equivalents
For purposes of the consolidated statement of cash flows, the Company
considers all highly liquid debt instruments purchased with a maturity date of
three months or less at the date of purchase to be cash equivalents. Cash and
cash equivalents are not insured above FDIC limits, which subjects the Company
to credit risk.
Hedging Activities
To reduce the impact of fluctuations in the market prices of oil and
natural gas, the Company periodically utilized hedging strategies such as
futures transactions or swaps to hedge the price of a portion of its future
oil
31
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
and natural gas production. Results of these hedging transactions are
reflected in oil and natural gas sales in the month of hedged production. At
December 31, 2000, 1999 and 1998, the Company had no such hedging or
derivative contracts. In 2000, the impact of hedging transactions was a net
reduction of revenues by $1,097,000. No hedging transactions occurred in 1999
or 1998.
Other
On June 15, 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133, as amended, is effective
January 1, 2001 for the Company. SFAS 133 requires that all derivative
instruments be recorded on the balance sheet at their fair value. Changes in
the fair value of derivatives will be recorded each period in current earnings
or other comprehensive income (only certain types of hedge transactions are
reported as a component of other comprehensive income). Additionally, for all
hedge transactions the nature and type of hedge will be disclosed. Based on
the types of hedging transactions historically employed, the Company does not
anticipate that the adoption of SFAS 133 will have a significant effect on the
results of operations or financial position.
2. Restructuring
As part of a restructuring plan, on August 3, 1999, PetroCorp's Board of
Directors entered into a Management Agreement with its largest shareholder,
Kaiser-Francis Oil Company ("Kaiser-Francis"), under which Kaiser-Francis
provides management, technical, and administrative support services for all
PetroCorp operations in the United States and Canada.
As a result of the restructuring, fifty-two employees were terminated in
1999 with one employee terminated in 2000. Several employees elected to defer
receipt of their termination benefits until 2000. The Houston, Oklahoma City
and Calgary offices were closed but the Company was still liable under the
lease agreements. In the second quarter of 2000, the Company was able to find
a replacement lessee for some of the idle office space earlier than
anticipated.
The company recorded restructuring costs of $3,643,000 during 1999.
Included in the costs are employee termination costs of $2,371,000, $807,000
in nonrefundable office lease discontinuance, $363,000 in investment banking
and legal costs, and $102,000 in other related costs. As of December 31, 1999,
$2,161,000 of the restructuring costs are included in accrued liabilities.
The following table shows the change in accrued restructuring costs during
2000:
Expenditures
Balance at charged Changes Balance at
December 31, against in December 31,
1999 accrual estimates 2000
------------ ------------ --------- ------------
Employee termination costs... $1,341,000 $1,341,000 $ -- $ --
Office lease discontinuance
and other
related costs............... 820,000 305,000 (445,000) 70,000
---------- ---------- --------- -------
$2,161,000 $1,646,000 $(445,000) $70,000
========== ========== ========= =======
32
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
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
adjustment. The Company's comprehensive income (loss) for the years ended
December 31, 2000, 1999 and 1998 are as follows (amounts in thousands):
Years ended December
31,
-------------------------
2000 1999 1998
------- ------ --------
Net income (loss)............................. $12,818 $ (206) $(24,395)
Foreign currency translation.................. (1,138) 1,690 (1,768)
------- ------ --------
Comprehensive income (loss)................... $11,680 $1,484 $(26,163)
======= ====== ========
4. Property, Plant and Equipment
Investments in property, plant and equipment were as follows at December
31, 2000 and 1999 (amounts in thousands):
2000 1999
--------- ---------
Oil and gas properties:
Proved.......................................... $ 226,813 $ 216,991
Unproved........................................ 2,032 6,154
--------- ---------
228,845 223,145
Plant and related facilities...................... 9,969 9,806
Gas gathering facilities.......................... 1,698 1,698
Furniture, fixtures and equipment................. -- 29
--------- ---------
240,512 234,678
Less--accumulated depreciation, depletion and
amortization..................................... (169,576) (160,972)
--------- ---------
$ 70,936 $ 73,706
========= =========
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 2000, 1999 and 1998 was $9,471,000,
$9,906,000 and $16,406,000, respectively. Oil and gas property depreciation,
depletion and amortization for the years ended December 31, 2000, 1999 and
1998 was $7,947,000, $8,138,000 and $14,961,000 , respectively. Depreciation,
depletion and amortization per equivalent Mcf (using a Mcf-to-barrel
conversion factor of 6 to 1) for the years ended December 31, 2000, 1999 and
1998 was $0.85, $0.85 and $1.62, respectively, for U.S. operations and $0.61,
$0.50 and $0.53, respectively, for Canadian operations. The total composite
rates were $0.74, $0.69 and $1.16 for the years ended December 31, 2000, 1999
and 1998, respectively.
5. Long-Term Debt
The Company's total long-term debt is as follows (amounts in thousands):
2000 1999
------- -------
Series A & B Senior Notes............................... $ -- $17,350
TD Bank Credit Agreement................................ 28,500 27,000
Nonrecourse Note Payable................................ 2,686 3,337
Less: Current portion of long-term debt................. (1,194) (4,277)
------- -------
Total long-term debt.................................... $29,992 $43,410
======= =======
33
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
Debt maturing subsequent to December 31, 2000 is as follows: $1,194,000 in
2001, $1,194,000 in 2002, and $28,798,000 in 2003.
Series A and Series B Senior Notes
On July 29, 1993, the Company entered into the Note Purchase Agreement with
subsidiaries of CIGNA Corporation and USF&G Corporation together with certain
other insurance companies to refinance existing notes. The final payment of
$875,000 on the Series A Note was made in June 1999 to an affiliate. During
2000, the Series B Notes were paid off prior to their maturity date. The loss
from extinguishment of the Series B Notes is shown as an extraordinary item.
Bank Debt
On June 26, 1997, the Company entered into a $50 million, five-year
revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the
agent, and the Bank of Nova Scotia. The facility was amended in June 1998 and
July 1999 to extend the initial five-year term an additional year to July 1,
2003 with quarterly borrowing base amortization beginning September 30, 2001.
The borrowings can be funded by either Eurodollar loans or Prime loans. The
interest rate on the borrowings is equal to an interest rate spread plus
either the Eurodollar rate or the Prime rate. The interest spread is
determined from a sliding scale based on the Company's borrowing base
percentage utilization in effect from time to time. The spread ranged from 1
3/8% to 2% on Eurodollar loans and 3/8% to 1% on Prime loans.
In June 2000, the revolving credit agreement was amended to increase the
current borrowing base to $40 million and change the termination date to July
31, 2000, pending a new loan agreement between Toronto-Dominion, as agent, and
the Company. The new loan agreement was successfully completed in July, 2000
(see next paragraph). Also in June 2000, the Company paid off the Series B
fixed rate notes, using available capital and borrowings under the revolving
credit agreement. Early termination payments required by the Series B
agreement and remaining unamortized debt costs were expensed and are reflected
in the financial statements as an extraordinary item of $385,000, less
applicable taxes of $143,000.
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 term of the facility is through April 30, 2003 and the
initial borrowing base was set at $58 million. Borrowings can be funded by
either Eurodollar loans or Base Rate loans. The interest rate on the
borrowings is equal to an interest rate spread plus either the Eurodollar rate
or the Base Rate. The interest spread is determined from a sliding scale based
on the Company's borrowing base percentage utilization in effect from time to
time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25
on Base Rate loans. At December 31, 2000, the weighted average interest rate
under this facility was approximately 9.4%.
The $75 million revolving credit agreement prohibits the declaration and
payment of dividends on the common stock of the Company. Also, the debt
agreement requires the Company to maintain a minimum current ratio, a minimum
tangible net worth, and a minimum interest coverage ratio.
Nonrecourse Notes Payable
On December 12, 1991, the Company (through its Canadian subsidiary, PCC
Inc.) acquired an interest in certain oil and gas properties and related gas
processing facilities located in the Hanlan-Robb area in western Alberta,
Canada. The Company used the proceeds from the issuance of redeemable
preferred stock of PCC Inc. to partially fund the acquisition. The holders of
the preferred stock also separately and concurrently acquired an interest in
the same oil and gas properties as the Company.
34
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
On August 9, 1994, PCC Inc. entered into agreements whereby PCC Inc.
redeemed the remaining shares of its redeemable preferred stock for
$7,034,000. Simultaneously, PCC Inc. issued $7,034,000 in nonrecourse long-
term notes payable (the Nonrecourse Notes Payable) to the previous holders of
the preferred stock with financial terms similar to the redeemable preferred
stock. Consistent with the redeemable preferred stock, the Nonrecourse Notes
Payable are denominated in Canadian dollars.
In 2000, 1999 and 1998, the Company issued $525,000, $238,000 and $846,000
of additional notes, respectively, as provided under the provisions of the
agreements to finance the company's portion of plant capital additions.
Interest accrues and is payable on a quarterly basis at a rate of 15% per
annum. In addition, redemptions are required to be made quarterly, based on a
fixed schedule through December 31, 2002. Interest and redemption payments are
made only to the extent there are sufficient cash proceeds from production and
sale of oil and gas reserves related to the interest in the Hanlan-Robb assets
acquired by the holders of the Nonrecourse Notes Payable. To the extent
interest and redemptions exceed such cash proceeds, the excess amount is
carried forward to the next quarter. At December 31, 2000 and 1999, unpaid
interest and redemptions totaled $503,000 and $449,000, respectively.
6. Income Taxes
The components of income (loss) before income taxes for the years ended
December 31, 2000, 1999 and 1998 consisted of the following (amounts in
thousands):
2000 1999 1998
------- ------- --------
United States operations................... $ 9,834 $(4,191) $(40,630)
Canadian operations........................ 13,335 3,031 1,121
------- ------- --------
$23,169(A) $(1,160) $(39,509)
======= ======= ========
The provision (benefit) for income taxes consists of the following (amounts
in thousands):
2000 1999 1998
------- ------- --------
Deferred:
Federal................................... $ 3,488 $(1,090) $(14,348)
State..................................... 317 (65) (820)
Canadian.................................. 807 201 54
------- ------- --------
4,612 (954) (15,114)
Current:
Canadian.................................. 5,497 -- --
------- ------- --------
$10,109(A) $ (954) $(15,114)
======= ======= ========
- --------
(A) Excludes extraordinary loss of $385,000 and related taxes of $143,000.
35
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
A reconciliation of the Company's United States income tax provision
(benefit) computed by applying the statutory United States federal income tax
rate to the Company's income (loss) before income taxes and extraordinary loss
for the years ended December 31, 2000, 1999 and 1998 is presented in the
following table (amounts in thousands):
2000 1999 1998
------- ------- --------
United States federal income taxes
(benefit) at statutory rate of 35%........ $ 8,109 $ (406) $(13,828)
Increases (reductions) resulting from:
Canadian earnings not subject to United
States taxes............................ (4,667) (1,061) (392)
Canadian income taxes.................... 6,304 201 54
State income taxes....................... 206 (65) (820)
Other.................................... 157 377 (128)
------- ------- --------
$10,109 $ (954) $(15,114)
======= ======= ========
Deferred tax assets and liabilities consist of the following at December
31, 2000 and 1999 (amounts in thousands):
2000 1999
-------- --------
Deferred tax assets:
Net operating loss carryforward--U.S............... $ 15,404 $ 17,786
Net operating loss carryforward--Canada............ 633 1,708
-------- --------
Gross deferred tax asset............................. 16,037 19,494
Deferred tax liabilities:
Excess of basis in oil and gas properties for
financial reporting purposes over the tax basis--
U.S............................................... (5,150) (3,870)
Excess of basis in oil and gas properties for
financial reporting purposes over the tax basis--
Canada............................................ (6,825) (7,306)
-------- --------
Gross deferred tax liability......................... (11,975) (11,176)
-------- --------
$ 4,062 $ 8,318
======== ========
As of December 31, 2000, the Company has U.S. net operating loss (NOL)
carryforwards of $41,631,000 and $39,973,000 for regular tax and alternative
minimum tax purposes, respectively. Regular tax NOL carryforwards and
alternative minimum tax NOL carryforwards begin to expire in 2009.
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.
36
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
The provision for Canadian income taxes differs from the amount of income
tax determined by applying the Canadian statutory income tax rate to pretax
Canadian income as a result of the following (amounts in thousands):
Years ended December
31,
-------------------------
2000 1999 1998
------- ------- -------
Tax computed at statutory rate of 44.62%..... $ 5,950 $ 1,352 $ 500
Nondeductible crown royalties, net of royalty
credits..................................... 4,411 1,515 896
Resource allowance........................... (5,299) (2,666) (1,342)
Revenue Canada audit adjustments............. 1,242 -- --
------- ------- -------
$ 6,304 $ 201 $ 54
======= ======= =======
7. Stock Option and Other Employee Benefit Plans
In 1992, the Company established the 1992 PetroCorp Stock Option Plan (the
Option Plan). The Option Plan allows up to 957,357 option shares to be
granted. The following table summarizes these options:
Weighted
Average Exercise
Options Price
------- ----------------
Outstanding at December 31, 1997................ 865,740 $ 7.86
Granted....................................... -- --
Forfeited..................................... (81,740) $10.00
Exercised..................................... (64,500) $ 5.42
-------
Outstanding at December 31, 1998................ 719,500 $ 7.87
Granted....................................... -- --
Forfeited..................................... (20,000) $ 6.38
Exercised..................................... (27,000) $ 5.00
-------
Outstanding at December 31, 1999................ 672,500 $ 8.04
Granted....................................... -- --
Forfeited..................................... -- --
Exercised..................................... (20,700) $ 6.38
-------
Outstanding at December 31, 2000................ 651,800 $ 8.09
=======
Of the 651,800 outstanding options under the Option Plan at December 31,
2000, 148,500 options with an exercise price of $5.00, 139,300 options with an
exercise price of $6.38 and 364,000 options with an exercise price of $10 had
weighted average contractual lives of 1.3 years, 1.1 years and 1.0 years,
respectively. All of these options are exercisable as of December 31, 2000.
37
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
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 Exercise
Options Price
------- ----------------
Outstanding at December 31, 1997................. 25,000 $8.63
Granted........................................ 6,000 $8.25
Forfeited...................................... -- --
Exercised...................................... -- --
------
Outstanding at December 31, 1998................. 31,000 $8.55
Granted........................................ 6,000 $6.75
Forfeited...................................... -- --
Exercised...................................... -- --
------
Outstanding at December 31, 1999................. 37,000 $8.26
Granted........................................ -- --
Forfeited...................................... -- --
Exercised...................................... -- --
------
Outstanding at December 31, 2000................. 37,000 $8.26
======
As of December 31, 2000, the weighted average remaining contractual life of
the outstanding options under the Director Option Plan was 7.1 years and the
exercise prices ranged from $6.75 to $8.63.
In 2000, the Company established the 2000 Stock Option Plan for the benefit
of employees and the Company's Board of Directors. Employee options vest one
year from date of grant and director options vest six months from the date of
grant. This plan allows up to 600,000 option shares to be granted. The
following table summarizes these options:
Weighted
Average Exercise
Options Price
------- ----------------
Outstanding at December 31, 1999................. -- --
Granted........................................ 106,650 $6.34
Forfeited...................................... -- --
Exercised...................................... -- --
-------
Outstanding at December 31, 2000................. 106,650 $6.34
=======
As of December 31, 2000, the weighted average remaining contractual life of
the outstanding options under the 2000 Stock Option Plan was 9.2 years. Of the
outstanding options, 5,000 were exercisable at year end with an average
remaining contractual life of 9.4 years. At December 31, 2000, exercise prices
ranged from $6.13 to $7.06.
Stock options under all three plans expire ten years from the date of grant
and exercise price equals market value on the grant date.
38
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
The Company adopted SFAS No. 123, "Accounting for Stock Based
Compensation," effective July 1, 1996. While SFAS No. 123 encourages entities
to adopt the fair value based method of accounting for their stock-based
compensation plans, the Company has elected to continue to utilize the
intrinsic value method under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees." Compensation expense has been
recognized for these stock-based compensation plans for any grants to
individuals who do not meet the definition of employee. Had compensation cost
for the 2000 Stock Option Plan and the Director Option Plan been determined
based upon the fair value at the grant date for awards under the plans,
consistent with the methodology prescribed under SFAS No. 123, the Company's
2000, 1999 and 1998 net income and earnings per share would have been reduced
by approximately $330,000, $17,000 and $16,000, or $0.04, nil and nil per
share, respectively. The fair value of the options granted during 2000, 1999
and 1998 were $432,000, $27,000 and $26,000, respectively, on the dates of
grants using the Black-Scholes option-pricing model with the following
assumptions:
2000 1999 1998
--------- ---- ----
Weighted average life, in years..................... 10 10 10
Risk-Free interest rate............................. 6.0%-6.5% 6.1% 5.8%
Expected Volatility................................. 41% 46% 26%
Expected Dividend Rate None None None
Effective January 1, 1993, the Company established a savings plan, which is
available to eligible employees and qualifies as a deferred compensation plan
under Section 401(k) of the Internal Revenue Code. The Company matches
employee contributions for an amount up to 6% of each employee's salary. The
Company's contributions to the plan, which are charged to expense, totaled
$100,000, $198,000 and $192,000 in 2000, 1999 and 1998, respectively.
39
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
8. Earnings Per Share
The following is a reconciliation of the numerators and denominators of the
basic and diluted per share computations for the periods presented (in
thousands, except per share amounts).
Per Share Amounts
----------------------------------
Net Income
(Loss) Before Net
Extraordinary Extraordinary Income
Income Shares Item Item (Loss)
-------- ------ ------------- ------------- ------
Year ended December 31,
2000
Basic EPS:
Net income(A)......... $ 12,818 8,692 $ 1.50 $(0.03) $ 1.47
Effect of dilutive
securities:
Options............... -- 94 (0.01) -- (0.01)
-------- ----- ------ ------ ------
Diluted EPS:
Net income(A)......... $ 12,818 8,786 $ 1.49 $(0.03) $ 1.46
======== ===== ====== ====== ======
Year ended December 31,
1999
Basic EPS:
Net loss.............. $ (206) 8,658 $(0.02) $ -- $(0.02)
Effect of dilutive
securities:
Options............... -- -- -- -- --
-------- ----- ------ ------ ------
Diluted EPS:
Net loss.............. $ (206) 8,658 $(0.02) $ -- $(0.02)
======== ===== ====== ====== ======
Year ended December 31,
1998
Basic EPS:
Net loss.............. $(24,395) 8,637 $(2.82) $ -- $(2.82)
Effect of dilutive
securities:
Options............... -- -- -- -- --
-------- ----- ------ ------ ------
Diluted EPS:
Net loss.............. $(24,395) 8,637 $(2.82) $ -- $(2.82)
======== ===== ====== ====== ======
- --------
(A) Net of extraordinary loss of $242.
The 2000 net income per share and the 1999 and 1998 net loss per share
amounts do not include the effect of potentially dilutive securities of
395,000, 709,500 and 750,500, respectively, as the impact of these outstanding
options was antidilutive.
40
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
9. Geographic Area Information
The principal business of the Company is oil and gas, which consists of the
exploration, development, acquisition, exploitation and operation of oil and
gas properties and the production and sale of crude oil and natural gas in
North America. Pertinent information with respect to the Company's oil and gas
business is presented in the following table (amounts in thousands):
United General
States Canada Corporate Total
------- ------- --------- --------
2000:
Revenues.......................... $23,588 $20,985 $ -- $ 44,573
Income (loss) from operations..... 12,353 14,402 (1,084)(A) 25,671
Depreciation, depletion and
amortization..................... 5,178 4,293 -- 9,471
Capital expenditures.............. 1,730 6,459 -- 8,189
Long-lived assets at December 31.. 44,259 36,931 242 81,432
1999:
Revenues.......................... $15,565 $11,561 $ -- $ 27,126
Income (loss) from operations 5,045 5,607 (8,400)(B) 2,252
Depreciation, depletion and
amortization..................... 5,746 3,714 446 9,906
Capital expenditures.............. 1,043 2,212 -- 3,255
Long-lived assets at December 31.. 51,516 36,106 107 87,729
1998:
Revenues.......................... $15,911 $ 9,296 $ -- $ 25,207
Income (loss) from operations (35,593)(C) 3,381 (4,840) (37,052)
Depreciation, depletion and
amortization..................... 12,511 3,698 359 16,568
Capital expenditures.............. 11,673 7,653 68 19,394
Long-lived assets at December 31.. 54,335 36,668 308 91,311
- --------
(A) Net of $445 restructuring cost credits.
(B) Includes $3,643 of restructuring costs.
(C) Includes a $33,600 oil and gas property valuation adjustment.
The following table reflects purchasers which accounted for more than 10%
of the Company's oil and gas revenues:
2000 1999 1998
---- ---- ----
Pan-Alberta Gas Ltd........................................... 19% 18% 23%
EOTT Energy Operating Limited Partnership..................... -- 11% 10%
Conoco Inc.................................................... -- -- 10%
Engage Energy LP.............................................. 27% 17% --
During 1999 and prior, the majority of the Company's Canadian gas was
dedicated under long-term contracts to Pan-Alberta Gas Ltd., a major Canadian
aggregator. However, as part of a legal settlement effective December 31,
1998, approximately 50% of PetroCorp's dedicated gas volumes have been
released from the Pan-Alberta contracts. These released volumes are now sold
on the spot market at prevailing prices. The Company does not believe the loss
of any purchaser would have a material adverse effect on its financial
position since the Company believes alternative sales arrangements could be
made on relatively comparable terms.
41
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
10. Fair Value of Financial Instruments
The following information discloses the fair value of the Company's
financial instruments in accordance with SFAS 107, "Disclosures About Fair
Value of Financial Instruments" (amounts in thousands):
Carrying Fair
Amount Value
-------- -------
1999:
Long-term debt:
Series B, 7.55% senior notes........................ $17,350 $17,811
The carrying amounts approximate fair value for the Company's cash and cash
equivalents, accounts receivable, accounts payable, and bank debt. Due to the
nature and terms of the Nonrecourse Notes Payable, the Company believes that
it is not practicable to estimate the fair value. The Company estimated the
fair value of the Series B, 7.55% senior notes using discounted cash flow
analysis based on 115 basis points above year end LIBOR rates.
11. Commitments and Contingencies
The Company has entered into operating lease agreements with noncancelable
terms in excess of one year for office space. Future minimum lease payments
are $99,000 and $58,000 for the years ending December 31, 2001 and 2002,
respectively with no payments after that time. Future minimum sublease income
with noncancelable terms in excess of one year for office space are $60,000
and $35,000 for the years ending December 31, 2001 and 2002. Total rental
expense for office space for the years ended December 31, 2000, 1999 and 1998
was $111,000, $583,000 and $560,000, respectively. Accrued restructuring costs
include $70,000 of office lease discontinuance costs at December 31, 2000.
On December 22, 2000, the Company and Southern Mineral Corporation
(Southern Mineral) announced they have executed a definitive agreement
regarding Southern Mineral's merger into PetroCorp. In the merger, expected to
close in the second quarter of 2001, shareholders of Southern Mineral will
receive consideration of $4.71 per share in cash or, at their election,
PetroCorp common stock or a combination of cash and stock, subject to certain
adjustments. The merger will be accounted for under the purchase method of
accounting.
There are other claims and actions pending against the Company. In the
opinion of management, the amounts, if any, which may be awarded in connection
with any of these claims and actions would not be material to the Company's
consolidated financial position or results of operations.
12. Related Party Transactions
The Company has engaged an engineering consulting company to procure
certain services and equipment pertaining to its Canadian operations. The
consulting company solicits bids from various vendors in order to obtain
competitive pricing. During 2000, 1999 and 1998, the consulting company
procured nil, $45,000 and $236,000 from an equipment supplier partly owned by
a director of the Company's Canadian subsidiaries who is a relative of the
Company's previous Chief Executive Officer.
The Company is a joint-interest owner in a project operated by Kaiser-
Francis Oil Company, a shareholder. During 2000, 1999 and 1998, the Company
remitted $154,000, $95,000 and $181,000, respectively, to Kaiser-Francis as
payment of the Company's share of the joint operation. During 2000, the
Company remitted $2,076,000 to Kaiser-Francis for management fees and cost
reimbursements under the Management Agreement (see Note 2). Amounts payable to
Kaiser-Francis at December 31, 2000 and 1999 were $22,055 and $100,000,
respectively.
42
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
13. Oil and Gas Reserves and Related Financial Data
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents total capitalized costs of proved and unproved
properties and accumulated depreciation, depletion and amortization related to
petroleum producing operations (amounts in thousands):
U.S. Canada Total
--------- -------- ---------
2000:
Proved properties........................ $ 176,834 $ 49,979 $ 226,813
Unproved properties...................... 1,223 809 2,032
--------- -------- ---------
178,057 50,788 228,845
Accumulated depreciation, depletion and
amortization............................ (144,105) (16,308) (160,413)
--------- -------- ---------
$ 33,952 $ 34,480 $ 68,432
========= ======== =========
1999:
Proved properties........................ $ 171,931 $ 45,060 $ 216,991
Unproved properties...................... 4,599 1,555 6,154
--------- -------- ---------
176,530 46,615 223,145
Accumulated depreciation, depletion and
amortization............................ (139,323) (13,670) (152,993)
--------- -------- ---------
$ 37,207 $ 32,945 $ 70,152
========= ======== =========
1998:
Proved properties........................ $ 168,071 $ 40,283 $ 208,354
Unproved properties...................... 7,417 1,734 9,151
--------- -------- ---------
175,488 42,017 217,505
Accumulated depreciation, depletion and
amortization............................ (133,914) (10,261) (144,175)
--------- -------- ---------
$ 41,574 $ 31,756 $ 73,330
========= ======== =========
Of the unproved properties capitalized cost at December 31, 2000,
approximately $349,000 and $99,000 were incurred in 2000 and 1999,
respectively. The Company anticipates evaluating these properties during
subsequent years.
43
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
Costs Incurred in Oil and Gas Producing Activities
Presented below are costs incurred in petroleum property acquisition,
exploration and development activities (amounts in thousands):
U.S. Canada Total
------- ------ -------
2000:
Acquisition of properties:
Proved properties................................. $ 104 $ 126 $ 230
Unproved properties............................... 80 269 349
Exploration costs................................... -- 166 166
Development costs(A)................................ 1,553 5,365 6,918
------- ------ -------
Total........................................... $ 1,737 $5,926 $ 7,663
======= ====== =======
1999:
Acquisition of properties:
Proved properties................................. $ 150 $ 230 $ 380
Unproved properties............................... 90 9 99
Exploration costs................................... 27 204 231
Development costs................................... 776 1,603 2,379
------- ------ -------
Total........................................... $ 1,043 $2,046 $ 3,089
======= ====== =======
1998:
Acquisition of properties:
Proved properties................................. $ 4,260 $ 595 $ 4,855
Unproved properties............................... 1,227 -- 1,227
Exploration Costs................................... 3,168 4,436 7,604
Development costs................................... 2,861 1,713 4,574
------- ------ -------
Total........................................... $11,516 $6,744 $18,260
======= ====== =======
Included in the above amounts for the years ended December 31, 2000, 1999
and 1998 were nil, $1,188 and $1,811, respectively, of capitalized internal
costs related to property acquisition, exploration and development.
(A) Includes approximately $600 of costs for development of properties
previously classified as proved undeveloped properties.
44
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
Results of Operations From Petroleum Producing Activities (unaudited)
The results of operations from petroleum producing activities, which do not
include revenues associated with the production and sale of sulfur, are as
follows (amounts in thousands):
U.S. Canada Total
-------- ------- --------
2000:
Revenues........................................ $ 23,481 $18,783 $ 42,264
Production costs................................ (5,813) (2,225) (8,038)
Depreciation, depletion and amortization........ (4,782) (3,165) (7,947)
Income tax benefit (expense).................... (4,728) (5,078) (9,806)
-------- ------- --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................ $ 8,158 $ 8,315 $ 16,473
======== ======= ========
1999:
Revenues........................................ $ 15,506 $ 9,656 $ 25,162
Production costs................................ (4,555) (2,178) (6,733)
Depreciation, depletion and amortization........ (5,410) (2,728) (8,138)
Income tax benefit (expense).................... (2,050) (973) (3,023)
-------- ------- --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................ $ 3,491 $ 3,777 $ 7,268
======== ======= ========
1998:
Revenues........................................ $ 15,911 $ 7,710 $ 23,621
Production costs................................ (5,171) (2,173) (7,344)
Depreciation, depletion and amortization........ (12,105) (2,856) (14,961)
Oil and gas property valuation adjustment....... (33,600) -- (33,600)
Income tax benefit (expense).................... 12,937 (134) 12,803
-------- ------- --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................ $(22,028) $ 2,547 $(19,481)
======== ======= ========
45
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
Reserve Quantities (unauditied)
Estimates of proved reserves and the related standardized measure of
discounted future net cash flow information are based on the reports of
independent petroleum engineers. These estimates represent the Company's
interest in the reserves associated with properties held directly and its
proportionate share of reserves held indirectly through partnerships or joint
ventures.
The Company's estimates of its proved reserves and proved developed
reserves of oil and gas as of December 31, 2000, 1999 and 1998 and the changes
in its proved reserves are as follows:
U.S. Canada Total
-------------- -------------- --------------
Oil Gas Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
------- ------ ------- ------ ------- ------
2000:
Proved reserves:
Beginning of year............ 3,261 20,950 1,320 55,409 4,581 76,359
Production................... (294) (3,850) (110) (4,519) (404) (8,369)
Purchase of minerals-in-
place....................... 8 1 -- 213 8 214
Extensions and discoveries... 155 1,314 100 4,049 255 5,363
Improved recoveries.......... -- -- -- -- -- --
Sales of minerals-in-place... -- (213) -- -- -- (213)
Revision to previous
estimates................... (21) 4,507 (209) (2,602) (230) 1,905
----- ------ ----- ------ ----- ------
End of year.................. 3,109 22,709 1,101 52,550 4,210 75,259
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year............ 3,180 18,906 1,187 47,026 4,367 65,932
===== ====== ===== ====== ===== ======
End of year.................. 2,888 20,551 1,068 46,624 3,956 67,175
===== ====== ===== ====== ===== ======
1999:
Proved reserves:
Beginning of year............ 2,578 21,970 1,412 57,422 3,990 79,392
Production................... (324) (4,421) (138) (4,660) (462) (9,081)
Purchase of minerals-in-
place....................... -- 148 -- 1,098 -- 1,246
Extensions and discoveries... -- -- 6 1,066 6 1,066
Improved recoveries.......... 605 91 -- -- 605 91
Sales of minerals-in-place... -- -- -- -- -- --
Revision to previous
estimates................... 402 3,162 40 483 442 3,645
----- ------ ----- ------ ----- ------
End of year.................. 3,261 20,950 1,320 55,409 4,581 76,359
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year............ 2,499 19,454 1,081 47,460 3,580 66,914
===== ====== ===== ====== ===== ======
End of year.................. 3,180 18,906 1,187 47,026 4,367 65,932
===== ====== ===== ====== ===== ======
1998:
Proved reserves:
Beginning of year............ 3,473 27,279 1,562 60,025 5,035 87,304
Production................... (422) (4,932) (143) (4,579) (565) (9,511)
Purchase of minerals-in-
place....................... 22 1,807 4 382 26 2,189
Extensions and discoveries... 11 694 155 4,613 166 5,307
Sales of minerals-in-place... (53) (3) (48) (2,746) (101) (2,749)
Revision to previous
estimates................... (453) (2,875) (118) (273) (571) (3,148)
----- ------ ----- ------ ----- ------
End of year.................. 2,578 21,970 1,412 57,422 3,990 79,392
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year............ 3,385 24,011 1,469 55,204 4,854 79,215
===== ====== ===== ====== ===== ======
End of year.................. 2,499 19,454 1,081 47,460 3,580 66,914
===== ====== ===== ====== ===== ======
46
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
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 in determining future cash
inflows for natural gas and oil as of December 31, 2000, were $9.19 per Mcf
and $27.16 per barrel, respectively. These prices were based on the adjusted
cash spot price for natural gas and oil at December 31, 2000. These prices are
significantly higher than the average natural gas and oil price received by
PetroCorp during December 2000, and the prices PetroCorp expects to receive
during 2001 and ensuing years. At December 31, 2000, there were no hedges
outstanding.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (amounts in thousands):
U.S. Canada Total
-------- -------- --------
2000:
Future gross revenues............................. $313,677 $501,760 $815,437
Less--future costs:
Production...................................... 55,534 31,530 87,064
Development(A).................................. 2,457 2,979 5,436
-------- -------- --------
Future net cash flows before income taxes......... 255,686 467,251 722,937
Less--10% annual discount for estimated timing of
cash flows....................................... 103,563 209,119 312,682
-------- -------- --------
Present value of future net cash flows before
income tax....................................... 152,123 258,132 410,255
Less--present value of future income taxes........ 42,860 110,860 153,720
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................ $109,263 $147,272 $256,535
======== ======== ========
(A) $3,232 of development costs are for proved undeveloped properties.
1999:
Future gross revenues............................. $128,792 $129,892 $258,684
Less--future costs:
Production...................................... 35,640 23,544 59,184
Development..................................... 1,799 3,530 5,329
-------- -------- --------
Future net cash flows before income taxes......... 91,353 102,818 194,171
Less--10% annual discount for estimated timing of
cash flows....................................... 30,671 44,753 75,424
-------- -------- --------
Present value of future net cash flows before
income tax....................................... 60,682 58,065 118,747
Less--present value of future income taxes........ 4,276 20,711 24,987
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................ $ 56,406 $ 37,354 $ 93,760
======== ======== ========
47
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
U.S. Canada Total
------- -------- --------
1998:
Future gross revenues.............................. $73,407 $107,803 $181,210
Less--future costs:
Production....................................... 27,841 17,501 45,342
Development...................................... 2,094 3,719 5,813
------- -------- --------
Future net cash flows before income taxes.......... 43,472 86,583 130,055
Less--10% annual discount for estimated timing of
cash flows........................................ 12,508 39,535 52,043
------- -------- --------
Present value of future net cash flows before
income tax........................................ 30,964 47,048 78,012
Less--present value of future income taxes......... -- 16,470 16,470
------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $30,964 $ 30,578 $ 61,542
======= ======== ========
The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows (amounts in
thousands):
U.S. Canada Total
-------- -------- --------
2000:
Standardized measure--beginning of period...... $ 56,406 $ 37,354 $ 93,760
Sales of oil and gas produced, net of
production costs.............................. (17,668) (16,558) (34,226)
Purchases of minerals-in-place................. 23 75 98
Extensions, discoveries and improved recovery.. 8,502 18,626 27,128
Sales of minerals-in-place..................... (108) -- (108)
Net changes in prices and productions costs.... 94,155 219,553 313,708
Development costs incurred and changes in
estimated future development costs............ 238 2,705 2,943
Revisions to previous quantity estimates....... 16,130 (18,563) (2,433)
Accretion of discount.......................... 6,068 5,807 11,875
Changes in timing of production and other...... (15,899) (11,579) (27,478)
Net changes in income taxes.................... (38,584) (90,148) (128,732)
-------- -------- --------
Standardized measure--end of period............ $109,263 $147,272 $256,535
======== ======== ========
1999:
Standardized measure--beginning of period...... $ 30,964 $ 30,578 $ 61,542
Sales of oil and gas produced, net of
production costs.............................. (10,950) (7,479) (18,429)
Purchases of minerals-in-place................. 187 1,491 1,678
Extensions and discoveries..................... 3,198 1,100 4,298
Sales of minerals-in-place..................... -- -- --
Net changes in prices and productions costs.... 27,195 11,517 38,712
Development costs incurred and changes in
estimated future development costs............ 456 805 1,261
Revisions to previous quantity estimates....... 14,144 1,672 15,816
Accretion of discount.......................... 3,096 4,706 7,802
Changes in timing of production and other...... (7,608) (2,795) (10,403)
Net changes in income taxes.................... (4,276) (4,241) (8,517)
-------- -------- --------
Standardized measure--end of period............ $ 56,406 $ 37,354 $ 93,760
======== ======== ========
48
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
U.S. Canada Total
------- ------- -------
1998:
Standardized measure--beginning of period......... $61,239 $31,048 $92,287
Sales of oil and gas produced, net of production
costs............................................ (10,740) (5,537) (16,277)
Purchases of minerals-in-place.................... 2,547 437 2,984
Extensions and discoveries........................ 609 2,833 3,442
Sales of minerals-in-place........................ (266) (1,432) (1,698)
Net changes in prices and productions costs....... (29,854) 11,599 (18,255)
Development costs incurred and changes in
estimated future development costs............... 1,870 714 2,584
Revisions to previous quantity estimates.......... (4,790) (1,191) (5,981)
Accretion of discount............................. 6,863 4,219 11,082
Changes in timing of production and other......... (4,378) (6,622) (11,000)
Net changes in income taxes....................... 7,864 (5,490) 2,374
------- ------- -------
Standardized measure--end of period............... $30,964 $30,578 $61,542
======= ======= =======
The standardized measure amounts are based on current prices at each year
end and reflect overall weighted average prices of:
U.S. Canada Total
------ ------ ------
2000:
Oil (per BBL)...................................... $26.25 $29.73 $27.16
Gas (per Mcf)...................................... 9.98 8.85 9.19
1999:
Oil (per BBL)...................................... $24.40 $22.84 $23.95
Gas (per Mcf)...................................... 2.35 1.80 1.95
1998:
Oil (per BBL)...................................... $10.15 $ 8.63 $ 9.63
Gas (per Mcf)...................................... 2.15 1.66 1.80
49
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000, 1999 and 1998
14. Summarized Quarterly Financial Data (unaudited)
(amounts in thousands, except per share
data)
First Second Third Fourth
quarter quarter quarter quarter Year
------- ------- ------- ------- -------
Year ended December 31, 2000:
Revenues........................... $7,742 $9,203 $11,787 $15,841 $44,573
Gross profit(1).................... 3,778 4,917 6,850 11,210 26,755
Income from operations............. 3,394 4,840 6,422 11,015 25,671
Net income (loss)(2)............... 1,510 2,330 3,264 5,714 12,818
Net income (loss) per share--
basic(2).......................... $ 0.17 $ 0.27 $ 0.38 $ 0.66 $ 1.47
Year ended December 31, 1999:
Revenues........................... $5,405 $6,460 $ 7,728 $ 7,533 $27,126
Gross profit(1).................... 1,038 2,094 3,223 3,851 10,206
Income from operations............. (1,106) 1,273 (3) 2,088 2,252
Net income (loss).................. (1,121) 483 (370) 802 (206)
Net income (loss) per share--
basic............................. $(0.13) $ 0.06 $ (0.04) $ 0.09 $ (0.02)
- --------
(1) Revenues less operating expenses other than general and administrative and
restructuring costs.
(2) Net income for the second quarter and year are net of a $242 extraordinary
loss ($0.03 per share).
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
PetroCorp Incorporated
(Registrant)
/s/ Gary R. Christopher
By:__________________________________
Gary R. Christopher
President and Chief Executive
Officer
(Principal Executive Officer)
Date: March 26, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Gary R. Christopher President, Chief Executive March 26, 2001
______________________________________ Officer (Principal
Gary R. Christopher Executive Officer) and
Director
/s/ Steven R. Berlin Vice President--Finance, March 26, 2001
______________________________________ Secretary & Treasurer
Steven R. Berlin (Principal Financial
Officer and Principal
Accounting Officer)
/s/ Steven E. Amos Controller March 26, 2001
______________________________________
Steven E. Amos
/s/ Lealon L. Sargent Chairman of the Board of March 26, 2001
______________________________________ Directors
Lealon L. Sargent
/s/ Thomas N. Amonett Director March 26, 2001
______________________________________
Thomas N. Amonett
/s/ Mark W. Files Director March 26, 2001
______________________________________
Mark W. Files
/s/ W. Neil McBean Director March 26, 2001
______________________________________
W. Neil McBean
/s/ Stephen M. McGrath Director March 26, 2001
______________________________________
Stephen M. McGrath
/s/ Robert C. Thomas Director March 26, 2001
______________________________________
Robert C. Thomas
51
EXHIBIT INDEX
No. Item
--- ----
21 --List of material subsidiaries
23.1 --Consent of PricewaterhouseCoopers LLP
23.2 --Consent of Huddleston & Co., Inc.
52