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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 1999
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 March 20, 2000 was $15,218,625. Indicate the number of shares
outstanding of each of the registrant's classes of common stock, as of March
20, 2000:
Common Stock, par value $.01 per share: 8,683,019
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy Statement for the registrant's Annual Meeting of Shareholders to be
held in 2000 (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........................................................ 7
3 Legal Proceedings................................................. 15
4 Submission of Matters to a Vote of Security Holders............... 16
PART II
5 Market for Registrant's Common Equity and Related Stockholder
Matters........................................................... 16
6 Selected Financial Data........................................... 17
7 Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 18
7A Quantitative and Qualitative Disclosure about Market Risk......... 23
8 Financial Statements and Supplementary Data....................... 23
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 23
PART III
10-13 (Items 10-13 incorporated by reference to Proxy Statement)........ 23
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 24
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 thousand cubic feet of natural gas equivalent
determined 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.
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, 1999, the Company's proved reserves totaled 4.5 MMBbls of
oil and 76.4 Bcf of natural gas and had an estimated pretax present value of
future net revenues (PV-10) of $120.4 million. On a Mcfe basis, approximately
74% of the Company's proved reserves were natural gas at such date. In
addition, the Company has unproved interest holdings with a net book value of
$6.2 million, as well as interests in natural gas processing and gathering
facilities with a net book value of $3.2 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
United States. The SW Oklahoma City Unit is showing a positive response to
water injection consistent with both the Company's initial estimates and
offset field response to similar waterflood projects. During the last half of
1999, unit production has more than doubled to 400+ barrels of oil per
1
day (as compared to the summer of 1998, when production averaged approximately
190 barrels/day). With this proven response, PetroCorp has realized a 600,000
barrel net increase in proven reserves for this field. A peak waterflood
response of 800--1,100 barrels/day is still anticipated by 2002.
Current U.S. exploration activity is focused on the south Texas Wilcox play
in Duval County where PetroCorp has committed to participate in the drilling of
a 16,500 ft. well to test the Ronnie and House X sands. This test is on trend
with Destino Field, a 22 Bcfe Ronnie sand field, and Rosita, a 265 Bcfe House
sand field. Two shallow Hinnant prospects have also been identified and leased
based upon 3-D seismic interpretation. Twenty square miles of new 3-D seismic
data were received at year end and current interpretations indicate multiple
Hinnant prospects are present.
In addition to the south Texas area, PetroCorp is reevaluating the viability
of company-controlled oil prospects in the Mississippi Salt Basin. Two
drillable prospects are currently being marketed to industry partners for
drilling during 2000.
Canada. Recent activity in the Hanlan-Robb area has focused on the
sidetracking of existing vertical wells and the installation of field
compression for the Hanlan Swan Hills Gas Unit #1 (a 1.4 Tcf gas field).
PetroCorp also participated in two horizontal wells in the Shaw/Basing area and
two farmout wells in the Red Cap area which increased gross production 150%
from the Company's acreage to 37 MMcf/D. PetroCorp has access to substantial
seismic and other data covering the Hanlan-Robb properties and plans to
continue participation in additional seismic surveys in the area.
PetroCorp owns a 24.5% working interest in the centrally located Hanlan-Robb
gas processing plant and varying interests in a gas gathering system that
connects all of the Company's currently producing Hanlan-Robb fields to the
plant. Beginning in September 1998, new third-party gas, for which processing
fees are received, has increased plant throughput from 220 MMcf/D to
approximately 300 MMcf/D at year-end 1999. As a result of the increased plant
throughput and third-party processing revenue, total operating costs for
PetroCorp have been reduced from $0.15/Mcf in 1998 to $0.06/Mcf for 1999. The
Company has adequate excess capacity in the plant for its exploration,
development and acquisition plans in the area.
The Minehead exploratory prospect, located ten miles east of the Hanlan-Robb
Gas Plant, exposes the Company to significant reserve additions. Targeting the
Swan Hills formation, the prospect is on trend with the Blackstone Field (1.0
Tcf) and the Hanlan Unit (1.4 Tcf). In 1999, a well testing the concept was
drilled at no cost to the Company. The well has been cased and is awaiting
further evaluation. PetroCorp has a 9.4% working interest upon payout of the
well, as well as a 9.4% working interest in the 12,800 surrounding 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,
1999, 1998, and 1997. 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,
-----------------------
1999 1998 1997
------- ------- -------
Net oil produced (MBbls):
United States........................................ 324 422 580
Canada............................................... 138 143 142
------- ------- -------
Total.............................................. 462 565 722
Average oil sales price (per Bbl):
United States........................................ $ 17.33 $ 12.55 $ 19.57
Canada............................................... 16.48 11.59 17.19
Weighted average..................................... 17.08 12.31 19.10
Net gas produced (MMcf):
United States........................................ 4,421 4,932 4,853
Canada............................................... 4,660 4,579 4,787
------- ------- -------
Total.............................................. 9,081 9,511 9,640
Average gas sales price (per Mcf):
United States........................................ $ 2.24 $ 2.15 $ 2.62
Canada............................................... 1.58 1.32 1.46
Weighted average..................................... 1.90 1.75 2.04
Gas equivalents produced (MMcfe):
United States........................................ 6,365 7,464 8,333
Canada............................................... 5,488 5,437 5,639
------- ------- -------
Total.............................................. 11,853 12,901 13,972
Average sales price (per Mcfe):
United States........................................ $ 2.44 $ 2.13 $ 2.89
Canada............................................... 1.76 1.42 1.67
Weighted average..................................... 2.13 1.83 2.39
Production costs (per Mcfe):
United States........................................ $ 0.72 $ 0.69 $ 0.73
Canada............................................... 0.40 0.40 0.30
Weighted average..................................... 0.57 0.57 0.56
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.
The gas is typically sold under short-term contracts ranging in length from one
month to one year. During 1999, nearly one-half of the Company's Canadian 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 under a one-year contract.
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
3
particular areas, where production volumes are significant or the location is
desirable for a particular purchaser, or both, the Company has successfully
negotiated bonuses over the purchaser's general field postings for its
production.
During the year ended December 31, 1999, Pan-Alberta, Engage Energy, and
EOTT Energy Operated Limited Partnership accounted for 18%, 17% and 11% 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, 1999. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
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.
4
In the past, the federal government regulated the prices at which the
Company's produced oil and gas could be sold. Currently, "first sales" of
natural gas by producers and marketers, and all sales of crude oil, condensate
and natural gas liquids, can be made at uncontrolled market prices, but
Congress could reenact price controls at any time.
Within the past decade, the FERC has issued numerous orders and policy
statements designed to create a more competitive environment in the national
natural gas marketplace, including orders promoting "open-access"
transportation on natural gas pipelines subject to the FERC's NGA and NGPA
jurisdiction. The FERC's "Order 636" was issued in April 1992 and was designed
to restructure the interstate natural gas transportation and marketing system
and to promote competition within all phases of the natural gas industry. Among
other things, Order 636 required interstate pipelines to separate the
transportation of gas from the sale of gas, to change the manner in which
pipeline rates were designed and to implement other changes intended to promote
the growth of market centers. Subsequent FERC initiatives have attempted to
standardize interstate pipeline business practices and to allow pipelines to
implement market-based, negotiated and incentive rates. The restructured
services implemented by Order 636 and successor orders have now been in effect
for a number of winter heating seasons and have significantly affected the
manner in which natural gas (both domestic and foreign) is transported and sold
to consumers.
Order 636 has generally been upheld in judicial appeals to date. However,
FERC routinely evaluates whether its approach to regulation of the natural gas
industry should be changed and whether further refinements or changes to
existing policies should be made in view of developments in the natural gas
industry since Order 636 was originally issued. Although FERC has indicated
that it remains committed to Order 636's "fundamental goal" of "improving the
competitive structure of the natural gas industry in order to maximize the
benefits of wellhead decontrol," the future regulatory goals and priorities of
FERC may change, and it is not possible to predict the effect, if any, of
future restructuring orders or policies on the Company's operations. FERC's
policies may also be impacted by the ongoing restructuring of the electric
power industry pursuant to FERC Order No. 888.
While Order 636 and related orders do not directly regulate either the
production or sale of gas that may be produced from the Company's properties,
the increased competition and changes in business practices within the natural
gas industry resulting from such orders have affected the terms and conditions
under which the Company markets and transports its available gas supplies. To
date, the FERC's pro-competition policies have not materially affected the
Company's business or operations. On a prospective basis, however, such orders
may substantially increase the burden on producers and transporters to
accurately nominate and deliver on a daily basis specified volumes of natural
gas, or to bear penalties or increased costs in the event scheduled deliveries
are not made.
Environmental Regulation. Various federal, state and local laws and
regulations governing the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs. In particular, the Company's exploration,
exploitation and production operations, its activities in connection with
storage and transportation of crude oil and other liquid hydrocarbons and its
use of facilities for treating, processing or otherwise handling hydrocarbons
and wastes therefrom are subject to stringent environmental regulation.
Although compliance with these regulations increases the cost of Company
operations, such compliance has not in the past had a material effect on the
Company's capital expenditures, earnings or competitive position. Environmental
regulations have historically been subject to frequent change by regulatory
authorities. The trend toward stricter standards in environmental legislation
and regulation is likely to continue. For instance, legislation has been
proposed in Congress from time to time that would reclassify certain oil and
gas exploration and production wastes as "hazardous wastes," which would make
the reclassified wastes subject to much more stringent handling, disposal and
cleanup requirements. If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil
and gas industry in general.
5
Also at the federal level, the U.S. Oil Pollution Act requires owners and
operators of facilities that could be the source of an oil spill into "waters
of the United States" (a term defined to include rivers, creeks, wetlands and
coastal waters) to demonstrate that they have at least $35 million in financial
resources to pay for the costs of cleaning up an oil spill and compensating any
parties damaged by an oil spill. Such financial assurances may be increased to
as much as $150 million if a formal assessment indicates such an increase is
warranted. These financial responsibility requirements could have a significant
adverse impact on small oil and gas companies like PetroCorp. State initiatives
to further regulate the disposal of oil and gas wastes are also pending in
certain states, and these various initiatives could have a similar impact on
the Company. The Company is unable to predict the ongoing cost to it of
complying with these laws and regulations or the future impact of such
regulations on its operation. Management believes that the Company is in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on the Company. A catastrophic discharge of
hydrocarbons into the environment could, to the extent such event is not
insured, subject the Company to substantial expense.
Canada
In Canada, the petroleum industry operates under federal, provincial and
municipal legislation and regulations governing taxes, land tenure, royalties,
production rates, environmental protection, exports and other matters. Prices
of oil and natural gas in Canada have been deregulated and are determined by
market conditions and negotiations between buyers and sellers, although oil
production volumes are regulated. Various matters relating to the
transportation and distribution of natural gas are the subject of hearings
before various regulatory tribunals. In addition, although the price of natural
gas exported from Canada is subject to negotiation between buyers and sellers,
the National Energy Board, which regulates exports of natural gas, requires
that natural gas export contracts meet certain criteria as a condition of
approving such contracts. These criteria, including price considerations, are
designed to demonstrate that the export is in the Canadian public interest.
Several provincial governments have introduced a number of programs to
encourage and assist the oil and natural gas industry, including incentive
payments, royalty holidays and royalty tax credits. Canadian governmental
regulations may have a material effect on the economic parameters for engaging
in oil and gas activities in Canada and may have a material effect on the
advisability of investments in Canadian oil and gas drilling activities.
Employees
At December 31, 1999, PetroCorp had 3 full-time employees. (See
"Restructuring" included in Item 7--Management's Discussion and Analysis of
Financial Condition and Results of Operations.)
6
Item 2. Properties.
Principal Properties
The Company's proved oil and gas properties are relatively concentrated.
Approximately 80% of the PV-10 from the Company's proved reserves at December
31, 1999 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, 1999, 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, 1999
---------------------------------
Estimated Proved
Reserves
----------------------
Oil Gas
Property/Area (MBbls) (MMcf) MMcfe PV-10
------------- ------- ------ ------- ----------
(in
thousands)
Hanlan-Robb............................. 83 48,077 48,575 $ 48,983
Oklahoma City Area...................... 2,431 2,908 17,494 30,412
McLeod Field............................ 443 4,038 6,696 8,404
South Louisiana Area.................... 91 3,897 4,443 8,031
----- ------ ------- --------
Subtotal.............................. 3,048 58,920 77,208 95,830
----- ------ ------- --------
Others.................................. 1,533 17,439 26,637 24,547
----- ------ ------- --------
Total................................. 4,581 76,359 103,845 $120,377
===== ====== ======= ========
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 40% of the Company's 1999
net daily gas production. The Company owns an interest in ten producing fields
in this area, covering 47,000 developed acres, with current combined production
of 223 MMcf/D. PetroCorp has additional interests in 73,900 undeveloped acres
in this area. The key field is the world-class Hanlan Swan Hills Gas Unit #1,
with an estimated ultimate recovery of 1.4 Tcf and current gross production of
142 MMcf/D. PetroCorp's ownership is part of a joint venture managed by the
Company with institutional investors that collectively own 21.6% 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.
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.
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 six wells to develop production from three formations.
The Company's working interests vary from 12% to 100% in 9.8 sections
(approximately 6,240 acres).
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 28 MMcf/D from a Miogyp
7
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.
Other Properties. Other significant U.S. properties include the Rich Hurt
Field in western Duval County, Texas, 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 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.
8
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, 1999. The PV-10 values shown in the table are not
intended to represent the current market value of the estimated oil and gas
reserves owned by the Company.
December 31, 1999
-------------------------
United
States Canada Total
------- -------- --------
Proved reserves:
Oil (MBbls)...................................... 3,261 1,320 4,581
Gas (MMcf)....................................... 20,950 55,409 76,359
Gas equivalents (MMcfe).......................... 40,516 63,329 103,845
Future net revenues ($000s)(1)..................... $91,353 $105,703 $197,056
Present value of future net revenues ($000s)(2).... $60,682 $ 59,695 $120,377
Proved developed reserves:
Oil (MBbls)...................................... 3,180 1,187 4,367
Gas (MMcf)....................................... 18,906 47,026 65,932
Gas equivalents (MMcfe).......................... 37,986 54,148 92,134
Future net revenues ($000s)(1)..................... $86,050 $ 90,400 $176,450
Present value of future net revenues ($000s)(2).... $57,216 $ 51,134 $108,350
- --------
(1) Proved and proved developed future net revenues include $2,885,000 related
to the sale of sulfur.
(2) Proved and proved developed present values of future net revenues include
$1,630,000 related to the sale of sulfur.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and future amounts and
timing of development expenditures, including many factors beyond the control
of the Company. Reserve engineering is a subjective process of estimating
underground accumulations of crude oil and natural gas that cannot be measured
in an exact manner, and the accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Estimates of proved undeveloped reserves are inherently less
certain than estimates of proved developed reserves. The quantities of oil and
gas that are ultimately recovered, production and operating costs, the amount
and timing of future development expenditures, geologic success and future oil
and gas sales prices may all differ from those assumed in these estimates. In
addition, the Company's reserves may be subject to downward or upward revision
based upon production history, purchases or sales of properties, results of
future development, prevailing oil and gas prices and other factors. Therefore,
the present value shown above should not be construed as the current market
value of the estimated oil and gas reserves attributable to the Company's
properties.
In accordance with SEC guidelines, the Independent Engineers' estimates of
future net revenues from the Company's proved reserves and the present value
thereof are made using oil, gas and sulfur sales prices in effect as of the
dates of such estimates and are held constant throughout the life of the
properties except where such guidelines permit alternate treatment, including,
in the case of gas contracts, the use of fixed and determinable contractual
price escalations. See "Marketing" under Item 1 of this report, "Management's
Discussion and Analysis of Financial Condition and Results of Operations" under
Item 7 of this report and "Supplemental Information to Consolidated Financial
Statements" in the Notes to the Consolidated Financial Statements of the
Company. Estimates of the Company's proved oil and gas reserves were not filed
with or included in reports to any other federal authority or agency other than
the SEC during the fiscal year ended December 31, 1999.
9
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, 1999.
Developed Undeveloped
Acres Acres(1)
-------------- --------------
Gross Net Gross Net
------- ------ ------- ------
United States:
Colorado........................................ 10,186 7,958 0 0
Kansas.......................................... 5,360 667 10 1
Louisiana....................................... 2,091 202 341 69
Mississippi..................................... 640 405 10,238 6,770
Oklahoma........................................ 40,429 10,558 14,284 6,137
Texas........................................... 24,963 3,304 102,308 7,310
Other........................................... 2,287 446 5,109 480
Canada:
Alberta......................................... 62,640 11,416 84,000 21,519
------- ------ ------- ------
Total......................................... 148,596 34,956 216,290 42,286
======= ====== ======= ======
- --------
(1) Approximately 20% of net undeveloped acres are covered by leases that
expire during 2000, unless drilling or production otherwise extends lease
terms.
As of December 31, 1999, the Company had working interests in 230 gross (74
net) producing oil wells and 188 gross (36 net) producing gas wells. Of these
wells, 19 gross (17 net) oil wells and 48 gross (10 net) gas wells were in
Canada, and the remainder of the oil and gas wells were in the United States.
10
Drilling Activities
All of PetroCorp's drilling activities are conducted through arrangements
with independent contractors, and it owns no drilling equipment. Certain
information with regard to the Company's drilling activities, during the years
ended December 31, 1999, 1998 and 1997 is set forth below:
Year Ended December 31,
---------------------------------------------
1999 1998 1997
-------------- -------------- --------------
Net Net Net
Working Working Working
Type of Well Gross Interest Gross Interest Gross Interest
------------ ----- -------- ----- -------- ----- --------
United States:
Development:
Oil............................. 4 .2 6 1.2
Gas............................. 1 .0(1) 9 1.3 3 .6
Nonproductive................... 1 .2 3 .8
--- --- --- --- --- ----
Total......................... 6 .4 9 1.3 12 2.6
--- --- --- --- --- ----
Exploratory:
Oil............................. 2 .6
Gas............................. 2 .3 1 .5
Nonproductive................... 1 .2 8 2.6 6 2.2
--- --- --- --- --- ----
Total......................... 1 .2 10 2.9 9 3.3
--- --- --- --- --- ----
Canada:
Development:
Oil............................. 1 1 2 .5
Gas............................. 2 .2 2 .1 5 1.4
Nonproductive................... 2 .0(1)
--- --- --- --- --- ----
Total......................... 5 1.2 2 .1 7 1.9
--- --- --- --- --- ----
Exploratory:
Oil............................. 1 1.0
Gas............................. 4 .2 2 1.1 8 2.2
Nonproductive................... 3 .1 2 1.2 4 .4
--- --- --- --- --- ----
Total......................... 7 .3 4 2.3 13 3.6
--- --- --- --- --- ----
Total.............................. 19 2.1 25 6.6 41 11.4
=== === === === === ====
- --------
(1) The Company has a net working interest less than 0.05% in these wells.
At December 31, 1999, the Company was participating in the drilling of 4
gross (.2 net) wells. Of these, 2 gross (.1 net) were in the United States and
2 gross (.1 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 new third-party gas, for which processing fees are
received, has increased plant throughput from 220 MMcf/D to approximately 300
MMcf/D at year-end 1999. 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.
11
Previously a wholly-owned subsidiary of the Company, Fidelity Gas Systems,
Inc. ("FGS"), owned and operated the Anasazi Gas Gathering System, which
gathers gas produced from the Company-operated lease in the Paradox Basin area
of southwest Colorado. In December 1997, FGS was merged into the Company. The
working interest owners have entered into contracts with the Company pursuant
to which the Company purchases all of the gas produced from the area. This gas
is then resold by the Company to a purchaser at a redelivery point on the
national transmission pipeline system. Proceeds payable by the Company are
based upon the Company's resale price less a contractually agreed-upon fee.
Amounts received by the Company are distributed to all working interest and
royalty owners in the producing area in accordance with their ownership
interests. Because it is a gas gathering system, the Anasazi Gas Gathering
System has been deemed nonjurisdictional with respect to existing FERC rules
and regulations.
Other Facilities
The Company leases approximately 31,600 square feet in Houston, Texas where
its primary office was previously located. The Company also leases
approximately 8,200 square feet in Oklahoma City, Oklahoma and approximately
4,000 square feet in Calgary, Alberta for divisional offices. 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.
12
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,
PV-10 is generally based on prices and costs as of the date of the estimate,
whereas actual future prices and costs may be materially higher or lower.
Actual future net cash flows also will be affected by factors such as the
amount and timing of actual production, supply and demand for oil and gas,
curtailments or increases in consumption by natural gas purchasers and changes
in governmental regulations or taxation. The timing of actual future net cash
flows from proved reserves, and thus their actual present value, will be
affected by the timing of both the production and the incurrence of expenses in
connection with development and production of oil and gas properties. In
addition, the 10% discount factor (which is required by the SEC to be used to
calculate PV-10 for reporting purposes), is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company and its properties or the oil and gas
industry in general.
13
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.
Risks That Might Arise from the Management Agreement
Operational inefficiencies may occur during the transition period.
During the transition period to operation by Kaiser-Francis, which is not
anticipated to exceed six months, some operational inefficiencies may occur as
Kaiser-Francis' personnel become familiar with the Company's properties and
operations.
14
Kaiser-Francis may not perform to the Company's satisfaction.
Although the Company believes that Kaiser-Francis is well qualified to
perform oil and gas operations and administrative services on behalf of the
Company, there is the risk that Kaiser-Francis may not perform the services to
the Company's satisfaction.
If the Management Agreement is terminated, the Company will need to hire
employees to conduct the business.
After the end of the transition period to operation by Kaiser-Francis, the
Company will no longer employ the personnel necessary to perform the Company's
functions. Consequently, should the Management Agreement be terminated by
either party, the Company will need to contract with another party to provide
these services or hire the personnel necessary to perform these functions.
There is no assurance that the Company will be able to timely and cost-
effectively make such alternate arrangements.
Kaiser-Francis may have conflicts of interest with the Company.
Kaiser-Francis is actively and substantially engaged in the oil and gas
exploration and production business, including, in some cases, operations in
geographical areas in which the Company currently owns interests. Under the
Management Agreement, Kaiser-Francis may continue to engage in such activities,
even though its activities might be considered to be in competition with the
Company's oil and gas activities. Accordingly, in some cases, if Kaiser-Francis
acquires new properties or develops new prospects on its own behalf, rather
than on behalf of the Company, the potential for actual or apparent conflicts
of interest exists. Kaiser-Francis also may from time to time arrange contracts
with certain of its affiliates to perform services on behalf of the Company.
Such arrangements have the potential to create real or apparent conflicts of
interest.
Competitive Industry
The oil and gas industry is highly competitive. The Company competes for
corporate and property acquisitions and the exploration, development,
production, transportation and marketing of oil and gas, as well as contracting
for equipment and securing personnel, with major oil and gas companies, other
independent oil and gas concerns and individual producers and operators. Many
of these competitors have financial and other resources which substantially
exceed those available to the Company.
Government Regulation
The Company's business is subject to certain federal, state and local laws
and regulations relating to the drilling for and production, transportation and
marketing of oil and gas, as well as environmental and safety matters. Such
laws and regulations have generally become more stringent in recent years,
often imposing greater liability on an increasing number of parties. Because
the requirements imposed by such laws and regulations are frequently changed,
the Company is unable to predict the effect or cost of compliance with such
requirements or their effects on oil and gas use or prices. In addition,
legislative proposals are frequently introduced in Congress and state
legislatures which, if enacted, might significantly affect the oil and gas
industry. In view of the many uncertainties which exist with respect to any
legislative proposals, the effect on the Company of any legislation which might
be enacted cannot be predicted.
Item 3. Legal Proceedings.
The Company is a party to various lawsuits and governmental proceedings, all
arising in the ordinary course of business. Although the outcome of these
lawsuits cannot be predicted with certainty, the Company does not expect such
matters to have a material adverse effect, either singly or in the aggregate,
on the financial position of the Company.
15
Item 4. Submission of Matters to a Vote of Security Holders.
(a)October 28, 1999 annual meeting of shareholders.
(b) (1) Approval of the Management Agreement between the Company and Kaiser-
Francis pursuant to which Kaiser-Francis provides management and
administrative support services for all the Company's operations and
the operations of its wholly-owned subsidiaries, both in the United
States and in Canada.
Number of Votes
-------------------------------
Abstentions
Withheld and Broker
For Authority Non-Votes
--------- --------- -----------
Including Kaiser-Francis Shares................ 7,876,244 6,720 --
Excluding Kaiser-Francis Shares (The
"Disinterested Shares")....................... 3,548,787 6,720 --
(2) Election of Directors
Number of Votes
-------------------------------
Abstentions
Withheld and Broker
Nominee For Authority Non-Votes
------- --------- --------- -----------
Gary R. Christopher............................ 7,881,264 -- 1,700
Stephen M. McGrath............................. 7,880,911 353 1,700
The term of office for each of Lealon L. Sargent, Thomas N. Amonett, G. Jay
Erbe, Jr., W. Niel McBean and Robert C. Thomas as directors of the Company
continued after the meeting.
(3) Ratification of the Reappointment of PricewaterhouseCoopers LLP as
the Company's independent accountants for the fiscal year ending
December 31, 1999.
Number of Votes
-------------------------------
Abstentions
Withheld and Broker
For Authority Non-Votes
--------- --------- -----------
7,878,844 4,020 100
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 1998 and 1999, and for a portion
of the Company's current quarter, as reported by the AMEX.
1998 1999 2000
------------------------------- ------------------------------- ------------------
First Second Third Fourth First Second Third Fourth First Quarter
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter (through March 20)
------- ------- ------- ------- ------- ------- ------- ------- ------------------
High.................... $9.31 $9.00 $8.25 $7.88 $5.88 $6.13 $7.50 $6.88 $6.75
Low..................... 7.75 7.13 5.13 5.25 5.19 4.38 5.50 5.75 5.25
As of March 20, 2000, the closing price for the Company's Common Stock was
$6.50 per share. As of March 20, 2000, 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.
16
Item 6. Selected Financial Data.
The following table summarizes consolidated financial data of the Company and
should be read in conjunction with the "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements of the Company, including the Notes thereto, included elsewhere in
this report.
For the Year Ended December 31,
------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
Income Statement Data:
Revenues:
Oil and gas................ $ 25,162 $ 23,621 $ 33,502 $ 29,718 $ 24,448
Plant processing........... 1,785 1,550 1,420 1,658 1,880
Other...................... 179 36 172 170 1,037
-------- -------- -------- -------- --------
27,126 25,207 35,094 31,546 27,365
-------- -------- -------- -------- --------
Expenses:
Production costs........... 6,733 7,344 7,793 6,660 7,304
Depreciation, depletion and
amortization.............. 9,906 16,568 17,065 12,433 13,300
Oil and gas property
valuation adjustment...... 33,600 8,500
General and administrative. 4,311 4,482 4,846 4,542 5,544
Restructuring costs........ 3,643
Other operating expenses... 281 265 367 333 256
-------- -------- -------- -------- --------
24,874 62,259 30,071 23,968 34,904
-------- -------- -------- -------- --------
Income (loss) from
operations.................. 2,252 (37,052) 5,023 7,578 (7,539)
-------- -------- -------- -------- --------
Other income (expenses):
Investment and other
income.................... 585 1,151 558 1,910 1,470
Interest expense........... (3,865) (3,622) (3,528) (3,391) (3,917)
Other income (expenses).... (132) 14 (47) (46) (159)
-------- -------- -------- -------- --------
(3,412) (2,457) (3,017) (1,527) (2,606)
-------- -------- -------- -------- --------
Income (loss) before income
taxes....................... (1,160) (39,509) 2,006 6,051 (10,145)
Income tax provision
(benefit)................... (954) (15,114) 136 1,807 (608)
-------- -------- -------- -------- --------
Net income (loss)............ $ (206) $(24,395) $ 1,870 $ 4,244 $ (9,537)
======== ======== ======== ======== ========
Net income (loss) per share--
basic....................... $ (0.02) $ (2.82) $ 0.22 $ 0.49 $ (1.11)
======== ======== ======== ======== ========
Net income (loss) per share--
diluted..................... $ (0.02) $ (2.82) $ 0.22 $ 0.49 $ (1.11)
======== ======== ======== ======== ========
Weighted average number of
common shares--basic........ 8,658 8,637 8,586 8,585 8,585
======== ======== ======== ======== ========
Weighted average number of
common shares--diluted...... 8,658 8,699 8,688 8,669 8,585
======== ======== ======== ======== ========
Balance Sheet Data (at
December 31):
Working capital............ $ 3,642 $ 2,080 $ 2,638 $ 1,946 $ 6,344
Total assets............... 105,395 103,992 130,924 122,864 114,839
Long-term debt............. 43,410 47,305 42,192 33,462 36,513
Shareholders' equity....... 42,363 40,744 66,557 65,665 61,521
17
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
General
The Company's principal line of business is the production and sale of its
oil and natural gas reserves located in North America. Results of operations
are dependent upon the quantity of production and the price obtained for such
production. Prices received by the Company for the sale of its oil and natural
gas have fluctuated significantly from period to period. Such fluctuations
affect the Company's ability to maintain or increase its production from
existing oil and gas properties and to explore, develop or acquire new
properties.
The following table reflects certain operating data for the periods
presented:
For the Year Ended
December 31,
--------------------
1999 1998 1997
------ ------ ------
Production:
United States:
Oil (Mbbls).............................................. 324 422 580
Gas (Mmcf)............................................... 4,421 4,932 4,853
Gas equivalents (Mmcfe).................................. 6,365 7,464 8,333
Canada:
Oil (Mbbls).............................................. 138 143 142
Gas (Mmcf)............................................... 4,660 4,579 4,787
Gas equivalents (Mmcfe).................................. 5,488 5,437 5,639
Total:
Oil (Mbbls).............................................. 462 565 722
Gas (Mmcf)............................................... 9,081 9,511 9,640
Gas equivalents (Mmcfe).................................. 11,853 12,901 13,972
Average sales prices:
United States:
Oil (per Bbl)............................................ $17.33 $12.55 $19.57
Gas (per Mcf)............................................ 2.24 2.15 2.62
Canada:
Oil (per Bbl)............................................ 16.48 11.59 17.19
Gas (per Mcf)............................................ 1.58 1.32 1.46
Weighted average:
Oil (per Bbl)............................................ 17.08 12.31 19.10
Gas (per Mcf)............................................ 1.90 1.75 2.04
Selected data per Mcfe:
Average sales price....................................... $ 2.13 $ 1.83 $ 2.39
Production costs.......................................... 0.57 0.57 0.56
General and administrative expenses....................... 0.36 0.35 0.35
Oil and gas depreciation, depletion and amortization...... 0.69 1.16 1.10
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. The Management Agreement received shareholder approval on
October 28, 1999 and was effective November 1, 1999. The Company also entered
into an Interim Agreement with Kaiser-Francis to provide certain services
pending receipt of shareholder approval of the Management Agreement. As the
Management Agreement was effective November 1, 1999, the Interim Agreement
ceased as of October 31, 1999.
18
Under the terms of the Management Agreement, Kaiser-Francis is compensated
through a service fee, equal to administrative and overhead fees charged under
applicable operating agreements plus fixed fees for non-operated properties.
Additionally, Kaiser-Francis can earn overriding royalties or working interests
in certain circumstances.
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. Fifty-two employees were
terminated in 1999 with one employee terminated in 2000. As of December 31,
1999, $2,161,000 of the restructuring costs are included in accrued
liabilities.
Acquisitions
During the fourth quarter of 1999, the Company made two acquisitions. One is
located in the Midcontinent area of the United States and one is located in
Western Canada. Total net reserves acquired were 1,246,000 Mcfe. Future
discounted net revenues at 10% using SEC pricing are $1,678,000.
These acquisitions are the first in a continuing and intensified effort to
acquire oil and natural gas reserves in the Company's core areas of operation.
Results of Operations
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 stay pay costs.
19
Investment and Other 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%.
1998 Compared to 1997
Overview. Primarily resulting from a 36% decrease in oil prices and a 14%
decrease in gas prices, coupled with an 8% decrease in production volumes,
cash flow before changes in operating assets and liabilities decreased 44% to
$10.7 million during 1998. This compares to $19.1 million in 1997.
Under rules promulgated by the Securities and Exchange Commission (the SEC),
companies that follow the full cost accounting method are required to make
quarterly "ceiling test" calculations, by country, using product prices in
effect at that time. As a result of low U.S. product prices at December 31,
1998, the Company recorded a valuation adjustment to its U.S. oil and gas
property balances, resulting in a non-cash after-tax charge against earnings
of $21.2 million ($33.6 million pre-tax). Excluding the valuation adjustment,
the Company recorded a net loss of $3.2 million, or $0.37 per share, in 1998
compared to net income of $1.9 million, or $0.22 per share, recorded in the
prior year.
Revenues. Total revenues decreased 28% to $25.2 million in 1998 compared to
$35.1 million in 1997. Oil and gas revenues decreased 29% to $23.6 million in
1998 from $33.5 million in the prior year as a result of the lower oil and gas
prices, coupled with the lower production volumes.
The Company's oil production decreased 22% to 565 MBbls while its natural
gas production remained almost level at 9,511 MMcf for an overall decline in
production of 8% to 12,901 MMcfe from 13,972 MMcfe. The decreased oil
production reflects normal production declines at the Hunter Misener Unit
waterflood project located in northern Oklahoma and the Maynor Creek Field in
Mississippi. The Company had increases in gas production from the South Texas
Acquisition and new wells in the U.S. and Canada. However, these increases
were offset by lower gas volumes resulting from an unexpected mechanical
problem, which has since been remedied, in a significant gas well located in
South Louisiana, non-strategic property sales and natural production declines.
The Company's composite average oil price decreased 36% to $12.31 per barrel
in 1998 from $19.10 per barrel in 1997. The Company's average U.S. natural gas
price decreased 18% to $2.15 per Mcf in 1998 from $2.62 per Mcf in the prior
year, while the average Canadian natural gas price decreased 10% to $1.32 per
Mcf from $1.46 per Mcf.
Plant processing revenues increased 9% to $1.6 million in 1998 from $1.4
million in 1997 as a result of new third party gas processing fees received at
the Company's Hanlan-Robb gas processing plant in Canada, beginning in August
1998.
Production Costs. Production costs decreased 6% to $7.3 million in 1998
while production costs per Mcfe remained almost level at $0.57. The decrease
in absolute dollars reflects a reduction in production taxes and the Company's
continued effort to reduce operating costs.
20
Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 3% to
$16.6 million in 1998 from $17.1 million in 1997. This decrease reflects the
impact of lower production volumes partially offset by a 5% increase in the
oil and gas DD&A rate to $1.16 per Mcfe from $1.10 per Mcfe.
Oil and Gas Property Valuation Adjustment. The Company follows the full cost
method of accounting for its oil and gas properties. Under this method, all
productive and non-productive exploration and development costs incurred for
the purpose of finding oil and gas reserves are capitalized and may not exceed
a calculated ceiling computed on a country-by-country basis. The ceiling is
calculated on a quarterly basis as the sum of (i) the present value
(discounted at 10%) of future net revenues from estimated production of proved
oil and gas reserves plus (ii) the lower of cost or estimated fair market
value of the unproved properties, less (iii) the related income tax effects.
At December 31, 1998, as a result of low oil and gas prices, the Company's net
capitalized costs for its U.S. oil and gas properties exceeded the ceiling by
$21.2 million resulting in a pre-tax non-cash valuation adjustment of $33.6
million. The ceiling was calculated using a Koch WTI posting price of $9.50
per barrel of oil and a Henry Hub cash price of $2.14 per Mcf of natural gas
as benchmark prices.
General and Administrative Expenses. General and administrative expenses
decreased 8% to $4.5 million in 1998 from $4.8 million in 1997 as a result of
the Company's focus on reducing costs.
Investment and Other Income. Investment and other income increased
significantly to $1.2 million in 1998 from $558,000 in 1997. The Company
recorded an additional $762,000 in 1998 related to gas contract settlements
and other items.
Interest Expense. Interest expense increased 3% to $3.6 million in 1998 from
$3.5 million in the prior year, reflecting the impact of increased debt
associated with a producing property acquisition completed in July 1997.
Income Taxes. Reflecting the U.S. valuation adjustment, the Company recorded
a $15.1 million income tax benefit with an effective tax rate of 38% on a pre-
tax loss of $39.5 million in 1998. This compares to an income tax provision of
$136,000 with an effective tax rate of 7% on pre-tax income of $2.0 million in
1997. During 1997, the Company recorded an income tax provision for its
Canadian operations with an effective tax rate of 15% which was partially
offset by an income tax benefit for its U.S. operations with an effective tax
rate of 29%, resulting in an overall effective tax rate of 7%.
Liquidity and Capital Resources
The Company has historically funded its capital expenditures and working
capital requirements with its cash flow from operations, debt and equity
capital and participation by institutional investors. As of December 31, 1999,
the Company had working capital of $3.6 million as compared to $2.1 million at
December 31, 1998. Cash provided by operating activities before changes in
operating assets and liabilities were $8.7 million, $10.7 million and $19.1
million in 1999, 1998 and 1997, respectively.
The Company's total capital expenditures, including capitalized internal
costs, were $3.3 million, $19.4 million and $28.0 million for 1999, 1998 and
1997, respectively. In 1999, the Company spent $2.6 million related to
exploration and development and $.4 million related to acquisitions. During
1998, the Company spent $11.6 million related to exploration and development
and $4.8 million related to acquisitions. In 1997, the Company spent $16.4
million related to exploration and development and $11.0 million related to
acquisitions.
Sales of non-strategic oil and gas properties totaled nil, $2.8 million, and
$1.4 million in 1999, 1998 and 1997, respectively.
In March 1996, the Company sold its SW Oklahoma City Field gas gathering
system for $3.8 million. The Company's total gain on the sale was $3.1
million, with $1.0 million being recognized in the first
21
quarter of 1996 in "investment and other income" on the consolidated statement
of operations while the remaining $2.1 million of the gain was deferred. The
deferred revenue was recognized in subsequent periods as a component of gas
revenues by partially offsetting the gas gathering fees paid by the Company
over the productive life of the Company's SW Oklahoma City Field. During the
year ended December 31, 1999, $257,000 of "deferred revenue" was recognized.
In June 1997, the Company entered into a $50.0 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 6.9% during 1999.
In July 1993, PetroCorp issued $40.0 million in senior notes. The Note
Purchase Agreement established $10.0 million of Senior Adjustable Rate Notes
Series A, due June 30, 1999 (the Series A Notes), payable to a subsidiary of
USF&G Corporation (a 20% shareholder of the Company), and $30.0 million of
7.55% Senior Notes Series B, due June 30, 2008 (the Series B Notes), payable to
two wholly-owned subsidiaries of CIGNA Corporation (formerly an 18% shareholder
of the Company) and to four unaffiliated institutional investors in amounts
totaling $20.0 million and $10.0 million, respectively. Mandatory redemptions
commenced on December 31, 1994 for the Series A Notes and were completed in
1999. Mandatory redemptions commenced on December 31, 1995 for the Series B
Notes. As of December 31, 1999, the remaining principal balances for the Series
B Notes were $17.4 million, of which $3.3 million will mature in the next
twelve months. Interest on the Series B Notes is fixed at a rate of 7.55% and
is payable semiannually in arrears.
The Note Purchase Agreement contains provisions that limit the Company's debt
levels based on undiscounted and discounted oil and gas reserves using the
SEC's rules, including the use of year-end prices held constant over the life
of the remaining reserves.
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, 1999, the nonrecourse long-term notes payable
balance was $3.3 million, of which $1,027,000 was classified as "current."
The Company plans to finance its 2000 capital expenditures from expected
operating cash flow and working capital. However, if the Company increases its
capital expenditure level in the future, or operating cash flow is not as
expected, capital expenditures may require additional funding, obtained through
borrowings from commercial banks and other institutional sources, public
offerings of equity or debt securities and existing and future relationships
with institutional investment partners.
Year 2000 Issues
PetroCorp had no Year 2000 computer problems. Minimal costs were expended in
this area.
22
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
The Company's primary sources of market risk are from fluctuations in
commodity prices, interest rates and exchange rates.
Commodity Price Risk
The Company produces and sells natural gas, crude oil, condensate, natural
gas liquids and sulfur. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response
to changing market forces. The Company has previously utilized hedging
transactions to manage its exposure to price fluctuations on its sales of oil
and natural gas. In the first quarter of 2000, the Company entered into swap
transactions in an effort to lock in a portion of higher oil prices which
currently exist. These transactions apply to approximately 50 percent of the
Company's projected oil production from April 2000 through December 2000, at
prices ranging from $23.57 to $29.00. However, no hedge transactions were in
place in 1999, 1998 and 1997.
Interest Rate Risk
Total debt at December 31, 1999, included $20.7 million of fixed-rate debt
attributed to Series B Senior Notes and Nonrecourse Notes Payable, and $27
million of floating-rate debt attributed to the TD Bank Credit Agreement. As a
result, the Company's annual interest cost in 2000 will fluctuate based on
short-term interest rates. The impact on annual cash flow of a 100 basis point
change in the floating rate would be approximately $270,000.
At December 31, 1999, the Company's fixed rate Series B Senior Notes had a
book value of $17.4 million and a fair market value of $17.8 million. Due to
the nature of the Nonrecourse Notes Payable, the Company believes that it is
not practical to estimate the fair value. 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 27 through 52 of this
report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
There is no matter required to be disclosed in response to this item.
PART III
In accordance with paragraph (3) of General Instruction G to Form 10-K, Part
III of this Report is omitted because the Company will file with the Securities
and Exchange Commission not later than 120 days after the end of the fiscal
year ended December 31, 1999 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).
23
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...................................... 27
Consolidated Balance Sheets as of December 31, 1999 and December 31,
1998.................................................................. 28
Consolidated Statements of Operations for the Years Ended December 31,
1999, 1998 and 1997................................................... 29
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997...................................... 30
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 1998 and 1997................................................... 31
Notes to Consolidated Financial Statements............................. 32
2. Financial Statement Schedules
Not Applicable.
3. Exhibits
2.1* Plan of Merger and Combination Agreement, dated September 18, 1991, by
and among Park Avenue Exploration Corporation, PetroCorp, L.S. Holding
Company, PetroCorp Incorporated, PetroPartners Limited Partnership,
PetroCorp Acquisition Corporation and Management Shareholders, as amended
by the First Amendment, dated October 1, 1992, and by the Simplification
Agreement described in Exhibit 2.2 hereto. Incorporated by reference to
Exhibit 2.1 to the Company's Registration Statement on Form S-1
(Registration No. 33-36972) initially filed with the Securities and
Exchange Commission (SEC) on August 26, 1993 (Registration Statement).
2.2* Simplification Agreement, dated August 24, 1993, by and among Park Avenue
Exploration Corporation, L.S. Holding Company, PetroCorp, PetroCorp
Incorporated, PetroPartners Limited Partnership, PetroCorp Employees
Partnership, L.P., Lealon L. Sargent, W. Neil McBean, Don A. Turkleson,
Michael L. Lord, Antonio F. Pelletier, David G. Campbell, Fletcher S.
Hicks, Craig K. Townsend, Clifford G. Zwahlen, Charles L. Zorio, Rodney
Rother, Mark Meyer and Carl Campbell (Simplification Agreement).
Incorporated by reference to Exhibit 2.2 to the Registration Statement.
3.1* Amended and Restated Articles of Incorporation of PetroCorp Incorporated.
Incorporated by reference to Exhibit 3.2 to the Registration Statement.
3.2* Amended and Restated Bylaws of PetroCorp Incorporated. Incorporated by
reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 1996.
3.3* Statement of Designations, Preferences, Limitations and Relative Rights
of Its Series A Junior Participating Preferred Stock. Incorporated by
reference to Exhibit 3.1 to the Company's Form 8-K, dated November 20,
1998.
4.1* Rights Agreement dated as of November 12, 1998, between PetroCorp
Incorporated and First Union National Bank, as Rights Agent. Incorporated
by reference to Exhibit 4.1 to the Company's Form 8-K, dated November 20,
1998.
4.2* Form of Right Certificate. Incorporated by reference to Exhibit 4.2 to
the Company's Form 8-K, dated November 20, 1998.
24
4.3* Specimen certificate for shares of Common Stock. Incorporated by
reference to Exhibit 4.1 to the Registration Statement.
4.4* Note Purchase Agreement, dated July 29, 1993, among PetroCorp
Incorporated, United States Fidelity and Guaranty Company, Connecticut
General Life Insurance Company, Indiana Insurance Company, Security
Life of Denver Insurance Company, Southland Life Insurance Company,
Life Insurance Company of Georgia and Life Insurance Company of North
America. Incorporated by reference to Exhibit 4.2 to the Registration
Statement.
9.1* Voting Agreement, dated January 18, 1994, by and among USF&G
Corporation, Park Avenue Exploration Corporation, United States
Fidelity and Guaranty Company, CIGNA Corporation, L.S. Holding Company,
American Oil & Gas Investors, AmGO II, First Reserve Fund V, Limited
Partnership, First Reserve Fund V-2, Limited Partnership, First Reserve
Fund VI, Limited Partnership and First Reserve Corporation.
Incorporated by reference to Exhibit 9.2 to the Form 8-K.
10.1* Amended and Restated 1992 PetroCorp Stock Option Plan. Incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended September 30, 1996.
10.2* Hanlan-Robb Area Agreement of Purchase and Sale, effective August 1,
1991, between Gulf Canada Resources Limited and Petro-Canada and PCC
Energy Inc. Incorporated by reference to Exhibit 10.3 to the
Registration Statement.
10.3* Registration Rights Agreement, dated August 24, 1993, between L.S.
Holding Company (assigned to Kaiser-Francis Oil Company) and PetroCorp
Incorporated. Incorporated by reference to Exhibit 10.5 to the
Registration Statement.
10.4* Registration Rights Agreement, dated August 24, 1993, between Park
Avenue Exploration Corporation and PetroCorp Incorporated. Incorporated
by reference to Exhibit 10.6 to the Registration Statement.
10.5* Registration Rights Agreement, dated January 18, 1994, between
PetroCorp Incorporated and American Oil & Gas Investors, AmGO II, First
Reserve Fund V, Limited Partnership, First Reserve Fund V-2, Limited
Partnership, First Reserve Fund VI, Limited Partnership and First
Reserve Corporation (assigned to Kaiser-Francis Oil Company).
Incorporated by reference to Exhibit 10.1 to the Form 8-K.
10.6* Piggyback Registration Rights Agreement, dated October 27, 1993,
between Lealon L. Sargent and PetroCorp Incorporated. Incorporated by
reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993. This is a management
contract or compensatory plan or arrangement required to be filed as an
exhibit.
10.7* Separation Benefits Agreement, dated September 27, 1993, between Lealon
L. Sargent and PetroCorp Incorporated. Incorporated by reference to
Exhibit 10.8 to the Registration Statement. This is a management
contract or compensatory plan or arrangement required to be filed as an
exhibit.
10.8* Executive Management Annual Incentive Compensation Plan, effective
January 1, 1994. Incorporated by reference to Exhibit 10.8 to the
Company's Annual Report on Form 10-K for the fiscal year ended December
31, 1994 (1994 Form 10-K). This is a management contract or
compensatory plan or arrangement required to be filed as an exhibit.
10.9* Share Purchase Agreement, dated December 13, 1996, between 702056
Alberta Ltd. and shareholders of Millarville Oil & Gas Ltd.
Incorporated by reference to Exhibit 2 to the Company's Current Report
on Form 8-K, dated December 23, 1996.
10.10* Agreement for Purchase and Sale, dated June 5, 1997, between PetroCorp
Incorporated and Great River Oil and Gas Corporation. Incorporated by
reference to Exhibit 2.1 to the Company's current report on Form 8-K
dated July 1, 1997.
25
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.
21 List of material subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Huddleston & Co., Inc.
27 Financial Data Schedule.
99.1* Agreement to furnish document relating to subsidiary. Incorporated by
reference to Exhibit 99.1 to the 1994 Form 10-K.
- --------
* Incorporated by reference.
(b) Reports on Form 8-K
Not Applicable.
26
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
PetroCorp Incorporated
In our opinion, the 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, 1999 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principals
generally accepted in the United States. 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, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above.
/s/ PRICEWATERHOUSECOOPERS LLP
Tulsa, Oklahoma
March 24, 2000
27
PETROCORP INCORPORATED
CONSOLIDATED BALANCE SHEETS
December 31, 1999 and 1998
(in thousands, except share amounts)
1999 1998
ASSETS -------- --------
Current assets:
Cash and cash equivalents................................ $ 12,899 $ 7,786
Accounts receivable, net................................. 4,605 4,569
Other current assets..................................... 162 326
-------- --------
Total current assets................................... 17,666 12,681
-------- --------
Property, plant and equipment:
Proved oil and gas properties, at cost, full cost method,
net of accumulated depreciation, depletion and
amortization............................................ 63,998 64,179
Unproved oil and gas properties, not subject to
depletion............................................... 6,154 9,151
Plant and related facilities............................. 3,151 3,768
Other, net............................................... 403 1,144
-------- --------
73,706 78,242
-------- --------
Deferred income taxes...................................... 13,916 12,761
Other assets, net.......................................... 107 308
-------- --------
Total assets........................................... $105,395 $103,992
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable......................................... $ 6,138 $ 4,424
Accrued liabilities...................................... 3,609 3,467
Current portion of long-term debt........................ 4,277 2,710
-------- --------
Total current liabilities.............................. 14,024 10,601
-------- --------
Long-term debt............................................. 43,410 47,305
-------- --------
Deferred revenue........................................... 257
-------- --------
Deferred income taxes...................................... 5,598 5,085
-------- --------
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, (8,683,019 shares and 8,656,019 shares
outstanding at December 31, 1999 and 1998,
respectively)........................................... 87 87
Additional paid-in capital............................... 71,380 71,245
Retained earnings (accumulated deficit).................. (24,530) (24,324)
Accumulated other comprehensive loss..................... (4,574) (6,264)
-------- --------
Total shareholders' equity............................. 42,363 40,744
-------- --------
Total liabilities and shareholders' equity............. $105,395 $103,992
======== ========
The accompanying notes are an integral part of these financial statements.
28
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 1999, 1998 and 1997
(in thousands, except share amounts)
1999 1998 1997
------- -------- -------
Revenues:
Oil and gas....................................... $25,162 $ 23,621 $33,502
Plant processing.................................. 1,785 1,550 1,420
Other............................................. 179 36 172
------- -------- -------
27,126 25,207 35,094
------- -------- -------
Expenses:
Production costs.................................. 6,733 7,344 7,793
Depreciation, depletion and amortization.......... 9,906 16,568 17,065
Oil and gas property valuation adjustment......... 33,600
General and administrative........................ 4,311 4,482 4,846
Restructuring costs............................... 3,643
Other operating expenses.......................... 281 265 367
------- -------- -------
24,874 62,259 30,071
------- -------- -------
Income (loss) from operations....................... 2,252 (37,052) 5,023
------- -------- -------
Other income (expenses):
Investment and other income....................... 585 1,151 558
Interest expense.................................. (3,865) (3,622) (3,528)
Other income (expenses)........................... (132) 14 (47)
------- -------- -------
(3,412) (2,457) (3,017)
------- -------- -------
Income (loss) before income taxes................... (1,160) (39,509) 2,006
Income tax provision (benefit)...................... (954) (15,114) 136
------- -------- -------
Net income (loss)................................... $ (206) $(24,395) $ 1,870
======= ======== =======
Net income (loss) per common share--basic........... $ (0.02) $ (2.82) $ 0.22
======= ======== =======
Net income (loss) per common share--diluted......... $ (0.02) $ (2.82) $ 0.22
======= ======== =======
Weighted average number of common shares--basic..... 8,658 8,637 8,586
======= ======== =======
Weighted average number of common shares--diluted... 8,658 8,699 8,688
======= ======== =======
The accompanying notes are an integral part of these financial statements.
29
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
Retained Accumulated
Additional earnings other
Shares paid-in (accumulated comprehensive Treasury
issued Amount capital deficit) loss stock Total
------ ------ ---------- ------------ ------------- -------- -------
Balance, December 31,
1996................... 8,616 $86 $71,170 $ (1,799) $(3,475) $(317) $65,665
Net income............ 1,870 1,870
Additional paid-in
capital.............. (27) (27)
Accumulated other
comprehensive loss... (1,021) (1,021)
Treasury stock........ 70 70
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1997................... 8,616 86 71,143 71 (4,496) (247) 66,557
Net Loss.............. (24,395) (24,395)
Exercise of stock
options.............. 40 1 102 103
Accumulated other
comprehensive loss... (1,768) (1,768)
Treasury stock........ 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 loss... 1,690 1,690
----- --- ------- -------- ------- ----- -------
Balance, December 31,
1999................... 8,683 $87 $71,380 $(24,530) $(4,574) $ -- $42,363
===== === ======= ======== ======= ===== =======
The accompanying notes are an integral part of these financial statements.
30
PETROCORP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 1999, 1998 and 1997
(in thousands)
1999 1998 1997
------- -------- -------
Cash flows from operating activities:
Net income (loss)................................. $ (206) $(24,395) $ 1,870
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization......... 9,906 16,568 17,065
Deferred income tax provision (benefit).......... (954) (15,114) 136
Oil and gas property valuation adjustment........ 33,600
Other............................................ (112) (437) (710)
Changes in operating assets and liabilities:
Accounts receivable............................. (36) 2,039 1,506
Other current assets............................ 164 11 (25)
Accounts payable................................ 1,714 (1,743) 160
Accrued liabilities............................. 142 122 (224)
------- -------- -------
Net cash provided by operating activities...... 10,618 10,651 19,778
------- -------- -------
Cash flows from investing activities:
Proceeds from sale of oil and gas properties...... 2,812 1,408
Additions to oil and gas properties............... (3,089) (18,260) (27,425)
Additions to plant and related facilities......... (166) (919) (285)
Additions to other property, plant and equipment.. (71) (125)
Additions to other assets......................... (144) (211)
------- -------- -------
Net cash used in investing activities.......... (3,255) (16,582) (26,638)
------- -------- -------
Cash flows from financing activities:
Proceeds from long-term debt...................... 2,238 14,845 13,244
Repayment of long-term debt....................... (4,566) (10,876) (5,757)
Other............................................. 135 350 43
------- -------- -------
Net cash provided by (used in) financing
activities.................................... (2,193) 4,319 7,530
------- -------- -------
Effect of exchange rate changes on cash............ (57) 7 (138)
------- -------- -------
Net increase (decrease) in cash and cash
equivalents....................................... 5,113 (1,605) 532
Cash and cash equivalents at beginning of year..... 7,786 9,391 8,859
------- -------- -------
Cash and cash equivalents at end of year........... $12,899 $ 7,786 $ 9,391
======= ======== =======
Supplemental disclosure:
Interest paid..................................... $ 3,150 $ 3,573 $ 2,177
======= ======== =======
Income taxes paid................................. $ -- $ -- $ --
======= ======== =======
The accompanying notes are an integral part of these financial statements.
31
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
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. PetroCorp's wholly-owned subsidiary,
Fidelity Gas Systems, Inc. (FGS), was merged into PetroCorp in 1997.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
the Company and its wholly-owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires the Company to make estimates and assumptions
that affect the amounts reported in the financial statements and the
accompanying notes. Actual results may differ from such estimates.
Property, Plant and Equipment
The Company follows the full cost method of accounting for oil and gas
properties whereby all productive and nonproductive exploration and development
costs incurred for the purpose of finding oil and gas reserves are capitalized.
Such capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, drilling, completing and equipping oil and gas wells,
together with internal costs directly attributable to property acquisition,
exploration and development activities. No gains or losses are recognized upon
the sale or other disposition of oil and gas properties, except in unusually
significant transactions.
The costs of the Company's oil and gas properties, including estimated future
development and dismantlement costs, are depreciated on a country-by-country
basis using a composite unit-of-production rate. An additional valuation
adjustment is made on a country-by-country basis if net capitalized costs of
the Company's oil and gas properties exceed the capitalization ceiling, which
is calculated on a quarterly basis as the sum of (1) the present value (10%) of
future net revenues from estimated production of proved oil and gas reserves
plus (2) the lower of cost or estimated fair value of the unproved properties,
less (3) the related income tax effects. 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, 1999 and 1997.
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.
32
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
Revenue Recognition
Revenues from the sale of petroleum produced are recognized upon the passage
of title, net of royalties and net profits royalty interests.
Revenues from natural gas production are recorded using the sales method, net
of royalties and net profits interests, which may result in more or less the
Company's share of pro-rata production from certain wells. Based on the
Company's average natural gas price of $2.35 per mcf received, the Company
estimates its balancing position to be approximately $728,000 (310,000 mcf) on
underproduced properties and approximately $666,000 (283,000 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, 1999 and 1998, the Company included $40,000
(26,000 mcf) and $35,000 (28,000 mcf) respectively, in accrued liabilities with
respect to overproduced imbalances.
Revenues from plant processing are recognized at the time associated natural
gas is processed and sold at the plant tailgate. Other revenues include fees
associated with the field gathering of third-party natural gas from certain
properties in which the Company has an interest and revenues from the sale of
sulfur in Canada.
Accounts Receivable
Accounts receivable relate primarily to sales of oil and gas and amounts due
from joint-interest partners for expenditures made by the Company on behalf of
such partners. The Company reviews the financial condition of potential
purchasers and partners prior to signing sales or joint-interest agreements. At
December 31, 1999 and 1998, the Company's allowance for doubtful accounts
receivable, which is reflected in the consolidated balance sheet as a reduction
in accounts receivable, totaled $50,000.
Income Taxes
The Company utilizes the 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, 1999, 1998 and 1997, the Company recognized foreign currency
losses of $22,000, $2,000 and $36,000, respectively. At December 31, 1999, 1998
and 1997, the exchange rates were ($1 CAN = $U.S.) $0.6924, $0.6535 and
$0.6992, respectively, while the average exchange rates during such years were
$0.6748, $0.6721 and $0.7201, respectively.
33
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
Cash Equivalents
For purposes of the consolidated statement of cash flows, the Company
considers all highly liquid debt instruments purchased with a maturity date of
three months or less to be cash equivalents. Cash 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 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,
1999, 1998 and 1997, the Company had no such hedging or derivative
transactions.
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 by SFAS 137, is
effective for all fiscal quarters of all fiscal years beginning after June 15,
2000 for certain companies (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 nature of the Company's anticipated use of derivative
instruments in 2000, 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. The Management Agreement
received shareholder approval on October 28, 1999 and was effective November 1,
1999. The Company also entered into an Interim Agreement with Kaiser-Francis to
provide certain services pending receipt of shareholder approval of the
Management Agreement. As the Management Agreement was effective November 1,
1999, the Interim Agreement ceased as of October 31, 1999.
Under the terms of the Management Agreement, Kaiser-Francis is compensated
through a service fee, equal to administrative and overhead fees charged under
applicable operating agreements plus fixed fees for non-operated properties.
Additionally, Kaiser-Francis can earn overriding royalties or working interests
in certain circumstances.
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. Fifty-two employees were
terminated in 1999 with one employee terminated in 2000. As of December 31,
1999, $2,161,000 of the restructuring costs are included in accrued
liabilities.
34
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
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, 1999, 1998 and 1997 are as follows (amounts in thousands):
Years ended December
31,
------------------------
1999 1998 1997
------ -------- ------
Net income (loss)................................ $ (206) $(24,395) $1,870
Foreign currency translation..................... 1,690 (1,768) (1,021)
------ -------- ------
Comprehensive income (loss)...................... $1,484 $(26,163) $ 849
====== ======== ======
4. Property, Plant and Equipment
Investments in property, plant and equipment were as follows at December 31,
1999 and 1998 (amounts in thousands):
1999 1998
--------- ---------
Oil and gas properties:
Proved............................................ $ 216,991 $ 208,354
Unproved.......................................... 6,154 9,151
--------- ---------
223,145 217,505
Plant and related facilities........................ 9,806 9,094
Gas gathering facilities............................ 1,698 1,698
Furniture, fixtures and equipment................... 29 1,878
--------- ---------
234,678 230,175
Less--accumulated depreciation, depletion and
amortization....................................... (160,972) (151,933)
--------- ---------
$ 73,706 $ 78,242
========= =========
Depreciation, depletion and amortization for all property, plant and
equipment for the years ended December 31, 1999, 1998 and 1997 was $9,906,000,
$16,406,000 and $16,880,000, respectively. Oil and gas property depreciation,
depletion and amortization for the years ended December 31, 1999, 1998 and 1997
was $8,138,000, $14,961,000 and $15,383,000, 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, 1999, 1998 and 1997 was
$0.85, $1.62 and $1.51, respectively, for U.S. operations and $0.50, $0.53 and
$0.50, respectively, for Canadian operations. The total composite rates were
$0.69, $1.16 and $1.10 for the years ended December 31, 1999, 1998 and 1997,
respectively.
35
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
5. Long-Term Debt
The Company's total long-term debt is as follows (amounts in thousands):
1999 1998
------- -------
Series A & B Senior Notes............................... $17,350 $21,150
TD Bank Credit Agreement................................ 27,000 25,000
Nonrecourse Note Payable................................ 3,337 3,865
Less: Current portion of long-term debt................. (4,277) (2,710)
------- -------
Total long-term debt.................................. $43,410 $47,305
======= =======
Debt maturing in each of the years during the five-year period subsequent to
December 31, 1999 is as follows: $4,277,000 in 2000, $12,827,000 in 2001,
$12,527,000 in 2002, $11,406,000 in 2003, and $1,800,000 in 2004.
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.
The Series B notes are payable in annual installments ranging from $3,250,000
to $1,200,000 with the final payment in June 2008. Interest on the Series B
notes is fixed at a rate of 7.55% and is payable semiannually in arrears.
The Note Purchase Agreement imposes upon the Company certain financial
covenants and other restrictive covenants that have the effect of restricting
the amount of dividends on the common stock that may be paid by the Company.
Also, the Note Purchase Agreement contains provisions that limit the Company's
debt levels based on undiscounted and discounted oil and gas reserves using the
SEC's rules, including the use of year-end prices held constant over the life
of the remaining reserves, and it requires a minimum current ratio and minimum
tangible net worth.
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 ranges from 1 3/8% to 2% on Eurodollar
loans and 3/8% to 1% on Prime loans. At December 31, 1999 $3,850,000 was
available based on the current borrowing base, as defined, subject to certain
limitations.
The $50 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.
36
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
Nonrecourse Notes Payable
On December 12, 1991, the Company (through its Canadian subsidiary, PCC Inc.)
acquired an interest in certain oil and gas properties and related gas
processing facilities located in the Hanlan-Robb area in western Alberta,
Canada. The Company used the proceeds from the issuance of redeemable preferred
stock of PCC Inc. to partially fund the acquisition. The holders of the
preferred stock also separately and concurrently acquired an interest in the
same oil and gas properties as the Company.
On August 9, 1994, PCC Inc. entered into agreements whereby PCC Inc. redeemed
the remaining shares of its redeemable preferred stock for $7,034,000.
Simultaneously, PCC Inc. issued $7,034,000 in nonrecourse long-term notes
payable (the Nonrecourse Notes Payable) to the previous holders of the
preferred stock with financial terms similar to the redeemable preferred stock.
Consistent with the redeemable preferred stock, the Nonrecourse Notes Payable
are denominated in Canadian dollars.
In 1999, 1998 and 1997, the Company issued $238,000, $846,000 and $245,000 of
additional notes, respectively, as provided under the provisions of the
agreements.
Interest accrues and is payable on a quarterly basis at a rate of 15% per
annum. In addition, redemptions are required to be made quarterly, based on a
fixed schedule through December 31, 2002. Interest and redemption payments are
made only to the extent there are sufficient cash proceeds from production and
sale of oil and gas reserves related to the interest in the Hanlan-Robb assets
acquired by the holders of the Nonrecourse Notes Payable. To the extent
interest and redemptions exceed such cash proceeds, the excess amount is
carried forward to the next quarter.
6. Income Taxes
The components of income (loss) before income taxes for the years ended
December 31, 1999, 1998 and 1997 consisted of the following (amounts in
thousands):
1999 1998 1997
------- -------- -------
United States operations..................... $(4,191) $(40,630) $(1,269)
Canadian operations.......................... 3,031 1,121 3,275
------- -------- -------
$(1,160) $(39,509) $ 2,006
======= ======== =======
The provision (benefit) for income taxes consists of the following (amounts
in thousands):
1999 1998 1997
------- -------- -------
Deferred:
Federal.................................... $(1,090) $(14,348) $ (344)
State...................................... (65) (820) (20)
Canadian................................... 201 54 500
------- -------- -------
$ (954) $(15,114) $ 136
======= ======== =======
37
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
A reconciliation of the Company's United States income tax provision
(benefit) computed by applying the statutory United States federal income tax
rate to the Company's income (loss) before income taxes for the years ended
December 31, 1999, 1998 and 1997 is presented in the following table (amounts
in thousands):
1999 1998 1997
------- -------- -------
United States federal income taxes (benefit) at
statutory rate of 35%............................. $ (406) $(13,828) $ 702
Increases (reductions) resulting from:
Canadian earnings not subject to United States
taxes........................................... (1,061) (392) (1,146)
Canadian income taxes............................ 201 54 500
State income taxes............................... (65) (820) (20)
Other............................................ 377 (128) 100
------- -------- -------
$ (954) $(15,114) $ 136
======= ======== =======
Deferred tax assets and liabilities consist of the following at December 31,
1999 and 1998 (amounts in thousands):
1999 1998
-------- -------
Deferred tax assets:
Net operating loss carryforward--U.S...................... $ 17,786 $14,884
Net operating loss carryforward--Canada................... 1,708 2,775
-------- -------
Gross deferred tax asset.................................... 19,494 17,659
-------- -------
Deferred tax liabilities:
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--U.S............... (3,870) (2,123)
Excess of basis in oil and gas properties for financial
reporting purposes over the tax basis--Canada............ (7,306) (7,860)
-------- -------
Gross deferred tax liability................................ (11,176) (9,983)
-------- -------
$ 8,318 $ 7,676
======== =======
As of December 31, 1999, the Company has U.S. net operating loss (NOL)
carryforwards of $48,070,000 and $45,262,000 for regular tax and alternative
minimum tax purposes, respectively. Alternative minimum tax NOL carryforwards
begin to expire in 2008 and regular tax NOL carryforwards expire as follows:
NOL carryforwards expiring in
-----------------------------
2001............................................... $ 262,000
2002............................................... 412,000
2003............................................... 300,000
2004............................................... 432,000
2005............................................... 202,000
Thereafter......................................... 46,462,000
-----------
$48,070,000
===========
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
38
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
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 on the annual utilization of its net
operating loss carryforwards.
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,
-------------------------
1999 1998 1997
------- ------- -------
Tax computed at statutory rate of 44.62%....... $ 1,352 $ 500 $ 1,461
Nondeductible crown royalties.................. 1,602 973 1,160
Resource allowance............................. (2,666) (1,342) (1,948)
Alberta royalty tax credit..................... (87) (77) (173)
------- ------- -------
$ 201 $ 54 $ 500
======= ======= =======
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
and outstanding. The following table summarizes these options:
Exercise
Options Price
------- ------------
Outstanding at December 31, 1996.................... 870,740 $5.00-$10.00
Granted...........................................
Forfeited.........................................
Exercised......................................... (5,000) $5.00
-------
Outstanding at December 31, 1997.................... 865,740 $5.00-$10.00
Granted...........................................
Forfeited......................................... (81,740) $10.00
Exercised......................................... (64,500) $5.00-$6.38
-------
Outstanding at December 31, 1998.................... 719,500 $5.00-$10.00
Granted...........................................
Forfeited......................................... (20,000) $6.38
Exercised......................................... (27,000) $5.00
-------
Outstanding at December 31, 1999.................... 672,500 $5.00-$10.00
=======
The weighted average exercise prices for options under the Option Plan
outstanding at December 31, 1999, 1998 and 1997 were $8.04, $7.87 and $7.86,
respectively.
In October 1996, all granted stock options under the Option Plan were fully
vested and exercisable as a change in control, defined in the Option Plan as
the change in ownership of more than 30% of the outstanding common shares of
the Company, occurred after Kaiser-Francis Oil Company purchased the common
shares owned by investment funds managed by First Reserve Corporation and the
common shares owned by a subsidiary of CIGNA Corporation.
39
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
In 1997, the Company established the 1997 PetroCorp Non-Employee Director
Stock Option Plan (the Director Option Plan) for the benefit of the Company's
Board of Directors. This plan allows up to 75,000 option shares to be granted
and outstanding. The following table summarizes these options:
Exercise
Options Price
------- -----------
Outstanding at December 31, 1996
Granted............................................. 25,000 $8.63
Forfeited...........................................
Exercised...........................................
------
Outstanding at December 31, 1997...................... 25,000 $8.63
Granted............................................. 6,000 $8.25
Forfeited...........................................
Exercised...........................................
------
Outstanding at December 31, 1998...................... 31,000 $8.25-$8.63
Granted............................................. 6,000 $6.75
Forfeited...........................................
Exercised...........................................
------
Outstanding at December 31, 1999...................... 37,000 $6.75-$8.63
======
The Director Options were fully vested at the date of grant.
Stock options under both plans expire ten years from the date of grant.
The Company adopted SFAS No. 123, "Accounting for Stock Based Compensation,"
effective July 1, 1996. While SFAS No. 123 encourages entities to adopt the
fair value based method of accounting for their stock-based compensation plans,
the Company has elected to continue to utilize the intrinsic value method under
Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued
to Employees." Accordingly, no compensation expense has been recognized for
these stock-based compensation plans. Had compensation cost for the Option Plan
and the Director Option Plan been determined based upon the fair value at the
grant date for awards under the plans consistent with the methodology
prescribed under SFAS No. 123, the Company's 1999, 1998 and 1997 net income and
earnings per share would have been reduced by approximately $17,000, $16,000
and $79,000, or nil, nil and $0.01 per share, respectively. The fair value of
the options granted during 1999 is estimated as $27,000 on the date of grant
using the Black-Scholes option-pricing model with the following assumptions:
dividend yield of 0%, volatility of 46%, risk-free interest rate of 6.1% and an
expected life of ten years.
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 $198,000,
$192,000 and $188,000 in 1999, 1998 and 1997, respectively.
40
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
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.
Per share
Income Shares amount
-------- ------ ---------
Year ended December 31, 1999:
Basic EPS:
Net loss..................................... $ (206) 8,658 $(0.02)
Effect of dilutive securities:
Options...................................... 27
-------- ----- ------
Diluted EPS:
Net loss..................................... $ (206) 8,685 $(0.02)
======== ===== ======
Year ended December 31, 1998:
Basic EPS:
Net loss..................................... $(24,395) 8,637 $(2.82)
Effect of dilutive securities:
Options...................................... 62
-------- ----- ------
Diluted EPS:
Net income................................... $(24,395) 8,699 $(2.82)
======== ===== ======
Year ended December 31, 1997:
Basic EPS:
Net income................................... $ 1,870 8,586 $ 0.22
Effect of dilutive securities:
Options...................................... 102
-------- ----- ------
Diluted EPS:
Net income................................... $ 1,870 8,688 $ 0.22
======== ===== ======
The 1999 and 1998 loss per share and the 1997 net income per share amounts do
not include the effect of potentially dilutive securities of 709,500, 750,500
and 445,740, respectively, as the impact on these outstanding options was
antidilutive.
41
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
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
-------- ------- --------- -------
1999:
Revenues.......................... $ 15,565 $11,561 $ $27,126
Income (loss) from operations..... 5,045 5,607 (8,400)(A) 2,252
Depreciation, depletion and
amortization..................... 5,746 3,714 446 9,906
Capital expenditures.............. 1,043 2,212 3,255
Identifiable assets at December
31............................... 81,264 24,010 121 105,395
1998:
Revenues.......................... $ 15,911 $ 9,296 $ $25,207
Income (loss) from operations..... (35,593)(B) 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
Identifiable assets at December
31............................... 64,408 38,930 654 103,992
1997:
Revenues.......................... $ 24,068 $11,026 $ $35,094
Income (loss) from operations..... 4,902 5,748 (5,627) 5,023
Depreciation, depletion and
amortization..................... 12,925 3,565 575 17,065
Capital expenditures.............. 20,565 7,172 309 28,046
Identifiable assets at December
31............................... 88,132 41,803 989 130,924
- --------
(A) Includes $3,643 of restructuring costs.
(B) Includes a $33,600 oil & gas property valuation adjustment.
The following table reflects purchasers which accounted for more than 10% of
the Company's oil and gas revenues:
1999 1998 1997
---- ---- ----
Pan-Alberta Gas Ltd........................................ 18% 23% 21%
EOTT Energy Operating Limited Partnership.................. 11% 10% 26%
Conoco Inc................................................. 10%
Engage Energy LP........................................... 17%
During 1998 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
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.
42
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
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
1998:
Long-term debt:
Series B, 7.55% senior notes.......................... 20,275 26,505
1997:
Long-term debt:
Series B, 7.55% senior notes.......................... 23,300 23,772
The carrying amounts approximate fair value for the Company's cash and cash
equivalents, accounts receivable, accounts payable, the Series A, senior
adjustable rate notes and bank debt. Due to the nature and terms of the
Nonrecourse Notes Payable, the Company believes that it is not practicable to
estimate the fair value. The Company estimates the fair value of the Series B,
7.55% senior notes using discounted cash flow analysis based on 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
$552,000, $510,000, $479,000 and nil for the years ending December 31, 2000,
2001, 2002 and 2003, respectively. Future minimum sublease income with
noncancelable terms in excess of one year for office space are $36,000,
$44,000, $29,000 and nil for the years ending December 31, 2000, 2001, 2002 and
2003. There was no sublease income recorded in 1999. Total rental expense for
office space for the years ended December 31, 1999, 1998 and 1997 was $583,000,
$560,000 and $648,000, respectively. Accrued restructuring costs include
$797,000 of office lease discontinuance costs at December 31, 1999.
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 1999, 1998 and 1997, the consulting company procured $45,000,
$236,000 and $148,000 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.
43
PETROCORP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, 1998 and 1997
The Company is a joint-interest owner in a project operated by Kaiser-Francis
Oil Company, a shareholder. During 1999, 1998 and 1997, the Company remitted
$95,000, $181,000 and $914,000, respectively, to Kaiser-Francis as payment of
the Company's share of the joint operation. During 1999, the Company remitted
$339,000 to Kaiser-Francis for management fees and cost reimbursements under
the Management Agreement (see Note 2). Amounts payable to Kaiser-Francis at
December 31, 1999 and 1998 were $100,000 and $5,000, respectively.
44
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
December 31, 1999, 1998 and 1997
(unaudited)
Costs Incurred in Oil and Gas Producing Activities
Presented below are costs incurred in petroleum property acquisition,
exploration and development activities (amounts in thousands):
U.S. Canada Total
------- ------ -------
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
======= ====== =======
1997:
Acquisition of properties:
Proved properties...................................... $ 9,993 $ 954 $10,947
Unproved properties.................................... 1,671 537 2,208
Exploration Costs....................................... 4,827 3,757 8,584
Development costs....................................... 4,047 1,639 5,686
------- ------ -------
Total................................................ $20,538 $6,887 $27,425
======= ====== =======
Included in the above amounts for the years ended December 31, 1999, 1998 and
1997 were $1,188,000, $1,811,000 and $1,897,000, respectively, of capitalized
internal costs related to property acquisition, exploration and development.
45
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents total capitalized costs of proved and unproved
properties and accumulated depreciation, depletion and amortization related to
petroleum producing operations (amounts in thousands):
U.S. Canada Total
--------- -------- ---------
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
========= ======== =========
1997:
Proved properties............................ $ 157,370 $ 37,900 $ 195,270
Unproved properties.......................... 7,877 1,715 9,592
--------- -------- ---------
165,247 39,615 204,862
Accumulated depreciation, depletion and
amortization................................ (88,226) (8,006) (96,232)
--------- -------- ---------
$ 77,021 $ 31,609 $ 108,630
========= ======== =========
Of the unproved properties capitalized cost at December 31, 1999,
approximately $292,000 and $1,627,000 were incurred in 1999 and 1998,
respectively. The Company anticipates evaluating these properties during
subsequent years.
46
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
Results of Operations From Petroleum Producing Activities
The results of operations from petroleum producing activities, which do not
include revenues associated with the production and sale of sulfur, are as
follows (amounts in thousands):
U.S. Canada Total
-------- ------ --------
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)
======== ====== ========
1997:
Revenues......................................... $ 24,068 $9,434 $ 33,502
Production costs................................. (6,080) (1,713) (7,793)
Depreciation, depletion and amortization......... (12,589) (2,794) (15,383)
Income tax benefit (expense)..................... (1,998) (739) (2,737)
-------- ------ --------
Results of operations from petroleum producing
activities (excluding corporate overhead and
interest costs)................................. $ 3,401 $4,188 $ 7,589
======== ====== ========
Reserve Quantities
Estimates of proved reserves of the Company and the related standardized
measure of discounted future net cash flow information are based on the reports
of independent petroleum engineers. These estimates represent the Company's
interest in the reserves associated with properties held directly and its
proportionate share of reserves held indirectly through partnerships or joint
ventures.
47
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
The Company's estimates of its proved reserves and proved developed reserves
of oil and gas as of December 31, 1999, 1998 and 1997 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)
------- ------ ------ ------ ------ ------
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
===== ====== ===== ====== ===== ======
1997:
Proved reserves:
Beginning of year............ 4,108 26,620 1,124 54,153 5,232 80,773
Production................... (580) (4,853) (142) (4,787) (722) (9,640)
Purchase of minerals-in-
place....................... 228 5,830 21 408 249 6,238
Extensions and discoveries... 72 1,553 248 12,795 320 14,348
Sales of minerals-in-place... (19) (840) (19) (840)
Revision to previous
estimates................... (355) (1,871) 330 (1,704) (25) (3,575)
----- ------ ----- ------ ----- ------
End of year.................. 3,473 27,279 1,562 60,025 5,035 87,304
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year............ 2,414 22,517 941 46,125 3,355 68,642
===== ====== ===== ====== ===== ======
End of year.................. 3,385 24,011 1,469 55,204 4,854 79,215
===== ====== ===== ====== ===== ======
48
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows was calculated
by applying current prices to estimated future production, less future
expenditures (based on current costs) to be incurred in developing and
producing such proved reserves and the estimated effect of future income taxes
based on the current tax law. The resulting future net cash flows were
discounted using a rate of 10% per annum.
The standardized measure of discounted future net cash flow amounts contained
in the following tabulation do not purport to represent the fair market value
of oil and gas properties. No value has been given to unproved properties.
There are significant uncertainties inherent in estimating quantities of proved
reserves and in projecting rates of production and the timing and amount of
future costs. Future realization of oil and gas prices over the remaining
reserve lives may vary significantly from current prices. In addition, the
method of valuation utilized, based on current prices and costs and the use of
a 10% discount rate, is not necessarily appropriate for determining fair value.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (amounts in thousands):
U.S. Canada Total
-------- -------- --------
1999:
Future gross revenues.............................. $128,792 $129,892 $258,684
Less--future costs:
Production........................................ 35,640 23,544 59,184
Development and dismantlement..................... 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
======== ======== ========
1998:
Future gross revenues.............................. $ 73,407 $107,803 $181,210
Less--future costs:
Production........................................ 27,841 17,501 45,342
Development and dismantlement..................... 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
======== ======== ========
49
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
U.S. Canada Total
-------- -------- --------
1997:
Future gross revenues.............................. $131,220 $112,021 $243,241
Less--future costs:
Production........................................ 28,274 36,584 64,858
Development and dismantlement..................... 3,519 3,735 7,254
-------- -------- --------
Future net cash flows before income taxes.......... 99,427 71,702 171,129
Less--10% annual discount for estimated timing of
cash flows........................................ 30,800 29,517 60,317
-------- -------- --------
Present value of future net cash flows before
income tax........................................ 68,627 42,185 110,812
Less--present value of future income taxes......... 7,388 11,137 18,525
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 61,239 $ 31,048 $ 92,287
======== ======== ========
50
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
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
-------- ------- --------
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, discoveries and improved recovery... 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 and dismantlement
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
======== ======= ========
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 and dismantlement
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
======== ======= ========
1997:
Standardized measure--beginning of period....... $ 79,969 $51,410 $131,379
Sales of oil and gas produced, net of production
costs.......................................... (17,988) (7,721) (25,709)
Purchases of minerals-in-place.................. 14,138 382 14,520
Extensions and discoveries...................... 2,371 7,296 9,667
Sales of minerals-in-place...................... (582) (582)
Net changes in prices and productions costs..... (35,621) (35,279) (70,900)
Development costs incurred and changes in
estimated future development and dismantlement
costs.......................................... 2,086 1,367 3,453
Revisions to previous quantity estimates........ (5,479) 175 (5,304)
Accretion of discount........................... 10,315 7,361 17,676
Changes in timing of production and other....... (5,052) (4,775) (9,827)
Net changes in income taxes..................... 16,500 11,414 27,914
-------- ------- --------
Standardized measure--end of period............. $ 61,239 $31,048 $ 92,287
======== ======= ========
51
PETROCORP INCORPORATED
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA--(Continued)
December 31, 1999, 1998 and 1997
(unaudited)
The standardized measure amounts are based on current prices at each year end
and reflect overall weighted average prices of:
U.S. Canada Total
------ ------ ------
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
1997:
Oil (per BBL)............................................ $17.31 $15.18 $16.65
Gas (per Mcf)............................................ 2.61 1.46 1.84
Information relating to sulfur in Canada which has not been included in the
standardized measure is summarized as follows:
1999 1998 1997
---------- -------- ----------
Revenues for year ended December 31............. $ 120,000 $ 55,000 $ 183,000
Production (long tons) for the year ended
December 31.................................... 15,000 15,000 15,546
Estimated proved reserves (long tons) as of
December 31.................................... 202,000 221,000 202,000
Present value (10%), before income taxes, of
future net revenues............................ 1,630,000 468,000 1,080,000
Price per long ton, net of transportation costs,
used to determine future revenues at December
31............................................. $ 14.28 $ 3.90 $ 9.36
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, 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)
Year ended December 31, 1998:
Revenues....................... $ 6,506 $ 6,086 $6,173 $ 6,442 $ 25,207
Gross profit(1)................ 728 157 20 (33,475) (32,570)
Income from operations......... (405) (998) (1,106) (34,498) (37,007)
Net loss....................... (636) (1,029) (764) (21,966) (24,395)
Net loss per share--basic...... $ (0.07) $ (0.12) $(0.09) $ (2.54) $ (2.82)
- --------
(1) Revenues less operating expenses other than general and administrative.
52
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 29, 2000
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 29, 2000
______________________________________ Officer (Principal
Gary R. Christopher Executive Officer) and
Director
/s/ Steven R. Berlin Vice President--Finance, March 29, 2000
______________________________________ Secretary & Treasurer
Steven R. Berlin (Principal Financial
Officer and Principal
Accounting Officer)
/s/ Steven E. Amos Controller March 29, 2000
______________________________________
Steven E. Amos
/s/ Lealon L. Sargent Chairman of the Board of March 29, 2000
______________________________________ Directors
Lealon L. Sargent
/s/ Thomas N. Amonett Director March 29, 2000
______________________________________
Thomas N. Amonett
/s/ G. Jay Erbe, Jr. Director March 29, 2000
______________________________________
G. Jay Erbe, Jr.
/s/ W. Neil McBean Director March 29, 2000
______________________________________
W. Neil McBean
/s/ Stephen M. McGrath Director March 29, 2000
______________________________________
Steven M. McGrath
/s/ Robert C. Thomas Director March 29, 2000
______________________________________
Robert C. Thomas
53
EXHIBIT INDEX
No. Item
--- ----
21 --List of material subsidiaries
23.1 --Consent of PricewaterhouseCoopers LLP
23.2 --Consent of Huddleston & Co., Inc.
27 --Financial Data Schedule
54