SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
---------- ----------
COMMISSION FILE NUMBER: 333-52263*
MICHAEL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS
(State or Other Jurisdiction of Incorporation or Organization)
76-0510239
(I.R.S. Employer Identification No.)
13101 NORTHWEST FREEWAY, SUITE 320,
HOUSTON, TEXAS 77040
(Address of principal executive offices including zip code)
(713) 895-0909
(Registrant's telephone number including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
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. Yes: X No:
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K 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
---
As of March 29, 1999, there were 10,000 shares of Michael Petroleum
Corporation Common Stock, $0.10 par value, issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
* The Commission File Number refers to a Form S-4 Registration
Statement filed by the Registrant under the Securities Act of 1933 which was
declared effective on July 22, 1998.
TABLE OF CONTENTS
PAGE
----
Item 1. Business
The Company...................................................... 3
Developments in 1998............................................. 3
Market Factors................................................... 6
Competition...................................................... 6
Governmental Regulation.......................................... 7
Abandonment Costs................................................ 10
Operating Hazards and Insurance.................................. 10
Employees........................................................ 10
Item 2. Properties......................................................... 10
Oil and Natural Gas Reserves..................................... 10
Item 3. Legal Proceedings.................................................. 15
Item 4. Submission of Matters to a Vote of Security Holders................ 15
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.............................................. 15
Item 6. Selected Consolidated Financial Data............................... 15
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition.......................................... 16
General........................................................ 16
Results of Operations.......................................... 16
Liquidity and Capital Resources................................ 18
Item 7A Quantitative and Qualitative Disclosures About Market Risk......... 29
Item 8. Financial Statements............................................... 30
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure....................................... 50
Item 10. Directors and Executive Officers of the Registrant................. 50
Item 11. Executive Compensation............................................. 51
Item 12. Security Ownership of Certain Beneficial Owners and Management..... 53
Item 13. Certain Relationships and Related Transactions..................... 53
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.... 54
PRELIMINARY NOTE: The statements regarding future financial performance and
results and oil and natural gas prices and the other statements which are not
historical facts contained in this report are forward-looking statements. The
words "expect," "project," "estimate," "believe," "anticipate," "intend,"
"budget," "predict" and similar expressions are also intended to identify
forward-looking statements. Such statements involve risks and uncertainties,
including, but not limited to, market factors, market prices of natural gas
and oil, results for future drilling and marketing activity, the need for and
availability of capital, future production and costs and other factors
detailed herein and in the Company's other Securities and Exchange Commission
filings. Should one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual outcomes may vary
materially from those indicated. See Item 7. "Management's Discussion and
Analysis of Results of Operations--Cautionary Statements Regarding
Forward-Looking Information."
PART I
ITEM 1. BUSINESS
THE COMPANY
Michael Petroleum Corporation (the "Company" or "Michael") is
engaged in the acquisition, exploitation and development of oil and natural
gas properties, principally in the Lobo Trend of South Texas (the "Lobo
Trend"). The Company has significantly expanded its production and reserve
base in recent years through development drilling and exploitation activities
and by acquiring producing and undeveloped properties. On March 31, 1998 and
April 2, 1998, the Company closed separate acquisitions of Lobo Trend
properties with Enron Oil and Gas Company ("Enron") (the "Enron Acquisition")
and Conoco Inc. ("Conoco") (the "Conoco Acquisition") (collectively, the
"Transactions"), pursuant to which the Company acquired interests in 170
gross (98 net) wells covering approximately 46,900 gross acres. In April
1998, the Company acquired leasehold interests in undeveloped acreage (the
"Lobo Lease") from Mobil Producing Texas and New Mexico Inc. ("Mobil"),
covering approximately 39,636 gross acres in the Lobo Trend. The interests in
properties acquired included acreage that was geographically close and
geologically similar to the Company's other properties. The Company applied
approximately $78.3 million in net proceeds from the sale of its 11 1/2%
Senior Notes due 2005, Series A in connection with the closing of the
Transactions and the Lobo Lease. See "--Developments in 1998" below and Item
7. "Management's Discussion and Analysis of Results of Operations and
Financial Condition".
The Lobo Trend, which is located in Webb and Zapata counties in
South Texas, covers in excess of one million gross acres and contains
multi-pay reservoirs of oil and natural gas. Since 1991, Webb and Zapata
counties collectively have constituted one of the largest onshore natural gas
producing regions in the United States. Although over 3,500 wells have been
drilled and cumulative production from the Lobo Trend since its discovery in
1973 exceeds 6.3 trillion cubic feet of natural gas equivalents, the Lobo
Trend is believed to be only partially exploited, with existing wells
producing from only approximately 125,000 acres. The primary geologic target
in the Lobo Trend is the Lobo sand series of the lower Wilcox formation,
which contains three primary objectives. Two secondary objectives also exist,
one above the three Lobo sands and one below. The Company believes that the
existence of these multi-pay reservoirs reduces drilling risk and enhances
the profitability of invested capital.
The Company began its operations in 1983 and focused on developing
prospects in South Texas. Since the early 1990s, the Company has become an
increasingly active participant in development drilling in the Lobo Trend. In
1996, the Company acquired interests in approximately 21,000 developed and
undeveloped gross acres in the Lobo Trend (the "1996 Acquisition"). The
Company uses 3-D seismic imaging and other advanced technologies in the
development and exploitation of its properties. As of December 31, 1998, 3-D
seismic data had been obtained over approximately 90% of the Company's
properties. See generally, Item 2. "Properties--Glossary of Certain Industry
Terms."
DEVELOPMENTS IN 1998
SALE AND EXCHANGE OF SENIOR NOTES
On April 2, 1998, the Company completed a debt offering in a private
placement exempt from registration under the Securities Act of 1933, of $135
million of 11 1/2% Senior Notes, due 2005, Series A (the "Series A Notes").
A portion of the net proceeds from the sale were used to repay outstanding
borrowings under a previous credit agreement (the "T.E.P. Financing") of
approximately $28 million. Under the T.E.P. Financing, a 30% net profits
interest in all of the Company's oil and natural gas properties had been
granted to the lender, along with a warrant to purchase up to 5% of the
Company's common stock. On April 2, 1998, the T.E.P. Financing Agreement was
terminated, and the unamortized balance of the notes payable discount, the
deferred debt issuance costs and certain fees incurred at closing were
written off and reflected in the income statement as an extraordinary loss,
net of taxes.
On July 22, 1998, the Securities and Exchange Commission ("SEC")
declared the Company's Registration Statement on Form S-4 effective pursuant
to Section 8(a) of the Securities Act. The Registration Statement had been
filed to cover offers of exchange of the Company's 11 1/2% Senior Notes Due
2005, Series B (the "Series B Notes") for the Series A Notes.
As of September 4, 1998, all of the $135 million original principal amount of
the Series A Notes had been exchanged for Series B Notes, the terms of which
are substantially identical to the terms of the Series A Notes. The effective
interest rate under the Series B Notes for the year ended December 31, 1998
was 12.04%.
CREDIT FACILITY
In May 1998, the Company entered into a four-year credit facility
(the "Credit Facility") with Christiania Bank og KreditKasse ("Christiania")
which provides maximum loan amounts totaling $50.0 million, subject to
borrowing base limitations. The borrowing base will be redetermined
semiannually by Christiania based on the Company's proved oil and natural gas
reserves beginning at March 31, 1999. Although the initial borrowing base was
$30 million, and effective November 9, 1998, the borrowing base was increased
by $5 million, the new borrowing base, effective April 1, 1999, was reduced
to $23 million. The maturity date of all indebtedness under the Credit
Facility is May 28, 2002. The effective interest rate under the Credit
Facility for the year ended December 31, 1998 was 6.8%. At December 31, 1998,
the Company was in default of certain financial covenants under the Credit
Facility but has obtained waivers of such defaults from Christiania and
amended the Credit Facility. See Item 7. "Management's Discussion and
Analysis of Results of Operation and Financial Condition--Financing
Arrangements" and "--Cautionary Statements Regarding Forward-Looking
Information-Future Need For and Availability of Capital," "--Restrictions
Imposed by Lenders" and "--Incurrence of Substantial Indebtedness."
ENRON ACQUISITION
The Enron Acquisition was consummated on March 31, 1998. Pursuant to
a Purchase and Sale Agreement, Enron conveyed to the Company (i) interests
in certain oil and natural gas leases covering approximately 7,500 gross
acres in Hidalgo County and Zapata County, Texas, (ii) certain interests in
leases covering approximately 37,500 gross acres located in Webb County,
Texas (the "Ranch Lands") covering the interval between the surface and 100
feet below the stratigraphic equivalent of the base of the Lobo 6 Sand, (iii)
all of Enron's interests in and to a 2.67% non-participating term royalty
interest in and to the Ranch Lands limited in depth to the interval covered
by the lease granted on the Ranch Lands and terminating simultaneously
therewith and (iv) all seismic data owned by Enron covering these properties
described in (i) and (ii) above.
The purchase price for the Enron Acquisition was $45.8 million, net
of closing and post-closing adjustments, and the conveyance by the Company to
Enron of certain oil and natural gas properties in Webb County, Texas. The
dollar portion of the purchase price was paid in the form of a promissory
note issued by the Company in the original principal amount of $45.8 million
which was repaid on April 2, 1998, the closing date of the sale of the Series
A Notes and the Conoco Acquisition. In addition, the Company granted to Enron
a non-exclusive license to use the seismic data it conveyed to the Company.
Under the Enron Purchase and Sale Agreement, the Company acquired
the properties on an "as is" basis. The Purchase and Sale Agreement also
provided for limited environmental indemnities. The Company must indemnify
Enron for certain environmental liabilities incurred by Enron, including
claims arising in whole or in part from the sole or concurrent negligence or
gross negligence of Enron.
4
CONOCO ACQUISITION
The Conoco Acquisition was consummated on April 2, 1998, with Conoco
conveying to the Company a leasehold interest in all of Conoco's interests in
approximately 39,000 gross acres located in Webb County, Texas, covering the
same interval covered by the Enron leases. The Company paid $22.5 million,
which reflected certain closing adjustments. The Company used a portion of
the net proceeds from the sale of the Series A Notes to pay the purchase
price of the Conoco Acquisition.
Under the Conoco Purchase and Sale Agreement, the Company acquired
the properties on an "as is" basis. The Purchase and Sale Agreement also
provided for limited environmental indemnities. The Company must indemnify
Conoco for certain environmental liabilities incurred by Conoco, including
claims arising in whole or in part from the sole or concurrent negligence,
gross negligence or strict liability of Conoco.
LOBO LEASE TRANSACTION
By agreement dated April 20, 1998, the Company acquired from Mobil
certain leasehold interests in undeveloped acreage in the Lobo Trend in Webb
County, Texas. Under this agreement, Mobil assigned to the Company its
interests in two existing leases and granted by lease interests in additional
undeveloped acreage under an oil and gas lease having a primary term of seven
years. The lease, which has an effective date of January 1, 1998, covers
39,636 gross acres and covers the same interval covered by the Enron and
Conoco leases. Excluded from the lease grant were existing productive wells
and certain drilling units on the subject properties. The lease contains
provisions obligating the Company to indemnify Mobil for certain liabilities
incurred by Mobil as a result of the Company's operations on the Lobo Lease
properties, including liabilities for violations of environmental laws. The
Company and Mobil also agreed that effective May 1, 1998, Michael would be
appointed operator with respect to the properties covered by the Lobo Lease
pursuant to a joint operating agreement between them.
As part of the consideration for the Lobo Lease and related matters,
the Company agreed to make future deliveries to Mobil of 4.0 Bcf of natural
gas. On April 23, 1998, the Company entered into a contract to secure
delivery of this volume of natural gas from a third party for $9.98 million.
OTHER ACQUISITIONS
On July 31, 1998, the Company acquired all of the common stock of
two companies owning non-operating working interests in 132 wells
on approximately 17,000 gross (500 net) acres, primarily in the Lobo Trend
located in Webb and Zapata Counties in Texas for $2.6 million. The working
interest percentages range from 0.5% to 15%, with an average working interest
of approximately 2.5% and an average net revenue interest of approximately
2.0%.
In December 1998, the Company loaned $1.5 million to a joint venture
between a Mexican construction company and a Texas limited liability company
to participate in the drilling of 38 natural gas wells for Petroleos
Mexicanos ("Pemex") in the Burgos Basin of Northern Mexico. The Mexican
construction company has a 51% ownership interest in the joint venture and
the Texas limited liability company has a 49% ownership interest. The note is
due December 1999 and bears interest at 12% per annum. The Company has an
option to convert the note receivable to a 50% equity interest in the Texas
limited liability company holding the 49% interest in the venture.
5
MARKET FACTORS
The revenues generated by the Company's operations are highly
dependent upon the prices of and demand for oil and natural gas. The price
received by the Company for its oil and natural gas production depends on
numerous factors beyond the Company's control. Historically, the markets for
oil and natural gas have been volatile and are likely to continue to be
volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply and demand
for oil and natural gas, market uncertainty and a variety of additional
factors. These factors include the level of consumer product demand, weather
conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions in the Middle East,
the actions of the Organization of Petroleum Exporting Countries, the foreign
supply of oil and natural gas and overall economic conditions. It is
impossible to predict future oil and natural gas price movements with any
certainty. Declines in oil and natural gas prices may adversely affect the
Company's financial condition, liquidity and results of operations. Crude oil
prices are generally determined by global supply and demand. After sinking to
a five-year low at the end of 1993, oil prices reached their highest levels
since the 1990 Persian Gulf War during fourth quarter 1996 and January 1997.
Posted crude oil prices ranged from $17 to $20 during most of 1997, then
declined to a $16 average in December 1997. Crude oil prices continued to
decline throughout 1998, dropping to a West Texas Intermediate price of $8.00
per barrel in December 1998, the lowest level since 1978. This decline has
been caused by low demand, as well as the failure of OPEC, at its November
1998 meeting, to further reduce production quotas. Low demand has been caused
by warmer than normal winter temperatures and a slow recovery in Asian
economies.
Natural gas prices are influenced by national and regional supply
and demand, which is often dependent upon weather conditions. Natural gas
competes with alternative energy sources as a fuel for heating and the
generation of electricity. Generally because of colder weather, storage
concerns and U.S. economic growth, prices remained relatively high during
most of 1996 and 1997. Gas prices declined, however, in December 1997 and
have remained lower throughout 1998, primarily because the winters of
1997-1998 and 1998-1999 were abnormally mild in the central and eastern U.S.
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
The Company currently markets all of its natural gas through
Upstream Energy Services, L.L.C. ("Upstream") pursuant to the terms of an
agreement dated effective as of November 1, 1998 (the "Sales Agreement"). The
Company and the predecessor to Upstream had similar marketing arrangements in
effect from 1991 to October 1998. Under the Sales Agreement, the Company has
agreed to sell, and Upstream has agreed to market all of the natural gas
produced from properties owned or operated by the Company at the price
realized by Upstream from the sale of such natural gas production less (i)
the costs incurred by Upstream in the transportation, treating and handling
of the gas prior to resale and (ii) marketing compensation ranging from $0.03
to $0.01 per Mmbtu sold, as measured at the point of delivery. The marketing
compensation is calculated as follows:
VOLUMETRIC TIER (MMBTU/DAY) MARKETING FEE
--------------------------- -------------
First 20,000 $0.03/MMbtu
20,001 to 40,000 $0.02/MMbtu
All volumes over 40,000 $0.01/MMbtu
The Sales Agreement is effective for a one-year period and is
renewable quarterly thereafter, subject to either party giving 60 days
written notice of termination. Until August 1997, the Company's Chief
Executive Officer owned an aggregate of approximately 20% of the capital
stock of Upstream. See Item 13. "Certain Relationships and Related
Transactions."
In conjunction with the 1996 Acquisition, Conoco (as the successor
in interest to the seller) and the Company entered into a Gas Exchange
Agreement whereby such parties agreed that the Company would deliver to
Conoco all of the natural gas produced from the leases acquired in the 1996
Acquisition at the point(s) at which such gas enters the transmission
pipelines owned by Lobo Pipeline Company ("Lobo Pipeline") (the "delivery
point") in exchange for natural gas in the same quantity and quality
delivered by Conoco at the Agua Dulce hub near Corpus Christi, Texas. The
parties' obligations under the Gas Exchange Agreement are subject to the
natural gas delivered and the pipeline meeting certain specifications. The
title to the Company's gas vests in Conoco at the delivery point, except to
the extent such amount exceeds the amount of redelivered gas at the
redelivery point, in which case the Company retains title and ownership of
such excess, which is then transported by Lobo Pipeline pursuant to an
Interruptible Gas Transportation Agreement. The consideration received by
Lobo Pipeline is $0.17 per Mcf for compression, transportation and
dehydration.
COMPETITION
The oil and natural gas industry is highly competitive, and the
Company encounters competition from other oil and natural gas companies in
all areas of its operations, including the acquisition of seismic, lease
options, exploratory prospects and proven properties. The Company's
competitors in the Lobo Trend area include major integrated oil and natural
gas companies, including Chevron Corporation, Conoco, Enron Corp. and Sonat
Exploration Company, and numerous independent oil and natural gas companies,
individuals and drilling and income programs. Many of the Company's
competitors, including those with whom it competes in the Lobo Trend, are
large, well-established companies with substantially larger operating staffs
and significantly greater capital resources than those of the Company and
which, in many instances, have been engaged in the oil and natural gas
business for a much longer time than the Company. Such companies may be able
to pay more for exploratory
6
prospects and productive oil and natural gas properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and
prospects than could the Company, given its limited financial and human
resources. In addition, such companies may be able to expend greater
resources on the existing and changing technologies that the Company believes
are and will be increasingly important to the current and future success of
oil and natural gas companies.
The Company's ability to acquire additional properties in the future
will be dependent upon its ability to evaluate and select suitable properties
and to consummate transactions in this highly competitive market. The Company
believes that the technological expertise and experience of its management in
exploiting the Lobo Trend, as well as the Company's relationships with
landowners in the area, generally enable it to compete effectively in the
Lobo Trend. However, the business of developing or acquiring reserves is
capital intensive, especially in the Lobo Trend area where the land blocks
typically range between 5,000 and 50,000 acres. The Company will require
additional financing or participation of industry partners to effect future
acquisitions in this area. Such additional financing may take the form of
equity securities, debt securities or some combination thereof, and there can
be no assurance that such financing will be available on terms that are
acceptable to the Company, if at all. Failure to secure such financing or to
locate industry partners would adversely affect the Company's ability to
compete with these other companies for lease acreage as it may become
available. See Item 7. "Management's Discussion and Analysis of Results of
Operations and Financial Condition." In addition, to the extent that the
Company engages in oil and natural gas exploration and production activities
on properties in geographic areas other than the Lobo Trend area, the Company
may be subject to additional competitive disadvantages due to its lack of
experience in and familiarity with prospect characteristics of those areas.
GOVERNMENTAL REGULATION
Various aspects of the Company's oil and natural gas operations are
subject to extensive and continually changing regulation, as legislation
affecting the oil and natural gas industry is under constant review for
amendment or expansion. Numerous departments and agencies, both federal and
state, are authorized by statute to issue, and have issued, rules and
regulations binding upon the oil and natural gas industry and its individual
members. The Federal Energy Regulatory Commission (the "FERC") regulates the
transportation and sale for resale of natural gas in interstate commerce
pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas
Policy Act of 1978 (the "NGPA"). In the past, the federal government has
regulated the prices at which oil and natural gas could be sold. While sales
by producers of natural gas and all sales of crude oil, condensate and
natural gas liquids can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future. Deregulation of wellhead
sales in the natural gas industry began with the enactment of the NGPA in
1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act"). The Decontrol Act removed all remaining NGA and NGPA price
and nonprice controls affecting wellhead sales of natural gas effective
January 1, 1993.
The Company's operations currently are located primarily in Texas.
Thus, the Company's business is subject to environmental regulation on the
state level primarily by the Railroad Commission of Texas and the Texas
Natural Resource Conservation Commission. The Railroad Commission of Texas
regulations may require the Company to obtain permits and drilling bonds for
the drilling of wells. Additionally, the Railroad Commission of Texas
regulates the spacing of wells, plugging and abandonment of such wells and
the remediation of contamination caused by most types of exploration and
production wastes. The Railroad Commission requirements for remediation of
contamination are, for the most part, administered on a case-by-case basis.
The Company expects that such regulations will be formalized in the future
and will in all likelihood become more stringent.
REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS
The Company's sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to pipeline
transportation are subject to extensive regulation. In recent years, the FERC
has undertaken various initiatives to increase competition within the natural
gas industry. As a result of initiatives like FERC Order No. 636, issued in
April 1992, the interstate natural gas transportation and marketing system
has been substantially restructured to remove various barriers and practices
that historically limited nonpipeline natural gas sellers, including
producers, from effectively competing with interstate pipelines for sales to
local distribution companies and large industrial and commercial customers.
The most significant provisions of Order No. 636 require that interstate
pipelines provide firm and interruptible transportation service on an open
access basis that is equal for all natural gas suppliers. In many instances,
the results of Order No. 636 and related initiatives have been to
substantially reduce or eliminate the interstate pipelines' traditional role
as wholesalers of natural gas in favor of providing only storage and
transportation services. While the United States Court of Appeals upheld most
of Order
7
No. 636 in 1997, certain related FERC orders, including the individual pipeline
restructuring proceedings, are still subject to judicial review and may be
reversed or remanded in whole or in part. While the outcome of these
proceedings cannot be predicted with certainty, the Company does not believe
that it will be affected materially differently than its competitors.
The FERC has also announced several important transportation-related
policy statements and proposed rule changes, including a statement of policy
and a request for comments concerning alternatives to its traditional
cost-of-service ratemaking methodology to establish the rates interstate
pipelines may charge for their services. A number of pipelines have obtained
FERC authorization to charge negotiated rates as one such alternative. Both
the policy statement and individual pipeline negotiated rate authorizations
are currently subject to appeal before the U.S. Court of Appeals for the D.C.
Circuit. In February 1997, the FERC announced a broad inquiry into issues
facing the natural gas industry to assist the FERC in establishing regulatory
goals and priorities in the post-Order No. 636 environment. In October 1997,
the United States Court of Appeals for the Fifth Circuit vacated a FERC
decision and remanded it to the agency with directions to reconsider the
criteria FERC used to distinguish nonjurisdictional gathering from
jurisdictional transportation on offshore pipeline systems. The final outcome
of these and other issues being considered by the FERC, and their effect on
the Company and its competitors cannot be predicted with certainty.
Additional proposals and proceedings that might affect the natural
gas industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will continue.
OIL PRICE CONTROLS AND TRANSPORTATION RATES
Sales of crude oil, condensate and natural gas liquids by the
Company are not currently regulated and are made at market prices. The price
the Company receives from the sale of these products may be affected by the
cost of transporting the products to market.
ENVIRONMENTAL
Extensive federal, state and local laws regulating the discharge of
materials into the environment or otherwise relating to the protection of the
environment affect the Company's oil and natural gas operations. Numerous
governmental departments issue rules and regulations to implement and enforce
such laws, which are often difficult and costly to comply with and which
carry substantial civil and even criminal penalties for failure to comply.
Some laws, rules and regulations relating to protection of the environment
may, in certain circumstances, impose strict liability for environmental
contamination, rendering a person or entity liable for environmental damages
and cleanup costs without regard to negligence or fault on the part of such
person or entity. Other laws, rules and regulations may restrict the rate of
oil and natural gas production below the rate that would otherwise exist or
even prohibit exploration and production activities in sensitive areas. In
addition, state laws often require various forms of remedial action to
prevent pollution, such as closure of inactive pits and plugging of abandoned
wells. The regulatory burden on the oil and gas industry increases the
Company's cost of doing business and consequently affects the Company's
profitability. The Company believes that it 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's operations. However, environmental laws and regulations have
been subject to frequent changes over the years, and the imposition of more
stringent requirements could have a material adverse effect upon the capital
expenditures or competitive position of the Company.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") imposes liability, without regard to fault or the legality of
the original act, on certain classes of persons that are considered to be
responsible for the release of a "hazardous substance" into the environment.
These persons include the current or former owner or operator of the disposal
site or sites where the release occurred and companies that disposed or
arranged for the disposal of hazardous substances at the disposal site. Under
CERCLA such persons may be subject to joint and several liability for the
costs of investigating and cleaning up hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of certain health studies. Comparable state statutes also impose
liability on the owner or operator of a property for remediation of
environmental contamination existing on such property. In addition, companies
that incur liability frequently confront third party claims because it is not
uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by hazardous
substances or other pollutants released into the environment from a polluted
site.
8
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that have been used for the exploration and
production of oil and natural gas and for other uses associated with the oil
and gas industry. Although the Company has followed operating and disposal
practices that it considered appropriate under applicable laws and
regulations, hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by the Company or on or
under other locations where such wastes were taken for disposal. In addition,
the Company owns or leases properties that have been operated by third
parties in the past. The Company could incur liability under CERCLA or
comparable state statutes for contamination caused by wastes it generated or
for contamination existing on properties it owns or leases, even if the
contamination was caused by the waste disposal practices of the prior owners
or operators of the properties.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and other wastes associated with the
exploration, development or production of oil and natural gas from regulation
as "hazardous waste." A similar exemption is contained in many of the state
counterparts to RCRA. Disposal of such nonhazardous oil and natural gas
exploration, development and production wastes usually is regulated by state
law. Other wastes handled at exploration and production sites or used in the
course of providing well services may not fall within this exclusion.
Moreover, stricter standards for waste handling and disposal may be imposed
on the oil and gas industry in the future. From time to time legislation has
been proposed in Congress that would revoke or alter the current exclusion of
exploration, development and production wastes from the RCRA definition of
"hazardous wastes" thereby potentially subjecting such wastes to more
stringent handling and disposal requirements. If such legislation were
enacted, or if changes to applicable state regulations required the wastes to
be managed as hazardous wastes, it could have a significant impact on the
operating costs of the Company, as well as the oil and gas industry in
general.
The Company's operations are also subject to the Clean Air Act (the
"CAA") and comparable state and local requirements. Amendments to the CAA
were adopted in 1990 and contain provisions that may result in the gradual
imposition of certain pollution control requirements with respect to air
emissions from operations of the Company. The Company may be required to
incur certain capital expenditures in the next several years for air
pollution control equipment in connection with obtaining and maintaining
operating permits and approvals for air emissions. However, the Company
believes its operations will not be materially adversely affected by any such
requirements, and the requirements are not expected to be any more burdensome
to the Company than to other similarly situated companies involved in oil and
natural gas exploration and production activities.
The Federal Water Pollution Control Act of 1972 (the "FWPCA")
imposes restrictions and strict controls regarding the discharge of wastes,
including produced waters and other oil and natural gas wastes, into
navigable waters. These controls have become more stringent over the years,
and it is probable that additional restrictions will be imposed in the
future. Permits must be obtained to discharge pollutants into state and
federal waters. The FWPCA provides for civil, criminal and administrative
penalties for unauthorized discharges of oil and other hazardous substances
and imposes substantial potential liability for the costs of removal or
remediation. State laws governing discharges to water also provide varying
civil, criminal and administrative penalties and impose liabilities in the
case of a discharge of petroleum or its derivatives, or other hazardous
substances, into state waters. In addition, the Environmental Protection
Agency has promulgated regulations that require many oil and natural gas
production sites, as well as other facilities, to obtain permits to discharge
storm water runoff. The Company believes that compliance with existing
requirements under the FWPCA and comparable state statutes will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows of the Company.
The Company maintains insurance against "sudden and accidental"
occurrences which may cover some, but not all, of the environmental risks
described above. Most significantly, the insurance maintained by the Company
may not cover the risks described above that are not attributable to a
single, abrupt event. Further, there can be no assurance that such insurance
will continue to be available to cover all such costs or that such insurance
will be available at premium levels that justify its purchase. The occurrence
of a significant event not fully insured or indemnified against could have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.
REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION
9
Exploration and production operations of the Company are subject to
various types of regulation at the federal, state and local levels. Such
regulations include requiring permits and drilling bonds for the drilling of
wells, regulating the location of wells, the method of drilling and casing
wells, and the surface use and restoration of properties upon which wells are
drilled. Many states also have statutes or regulations addressing
conservation matters, including provisions for the unitization or pooling of
oil and gas properties, the establishment of maximum rates of production from
oil and gas wells and the regulation of spacing, plugging and abandonment of
such wells. Some state statutes limit the rate at which oil and gas can be
produced from the Company's properties. See "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations."
ABANDONMENT COSTS
The Company is responsible for payment of plugging and abandonment
costs on oil and natural gas properties pro rata to its working interest.
Historically, the ultimate aggregate salvage value of lease and well
equipment located on the Company's properties has not exceeded the costs of
abandoning such properties. There can be no assurance, however, that this
historical trend will continue or that the Company will be successful in
avoiding additional expenses in connection with the abandonment of any of its
properties. In addition, abandonment costs and their timing may vary due to
many factors including actual production results, inflation rates and changes
in environmental laws and regulations.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating
risks, including the risk of fire, explosion, blowout, pipe failure, casing
collapse, unusual or unexpected formation pressures and environmental hazards
such as oil spills, gas leaks, ruptures and 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,
cleanup responsibilities, regulatory investigation and penalties and
suspension of operations.
In accordance with customary industry practice, the Company
maintains insurance against some, but not all, of the operating risks
described above. The Company's insurance does not cover business interruption
or protect against loss of revenues. There can be no assurance that any
insurance obtained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of
insurance or the availability of insurance at economic rates. The occurrence
of a significant event against which it is not fully insured or indemnified
could have a material adverse effect on the Company's financial condition,
results of operations or cash flows.
EMPLOYEES
At December 31, 1998, the Company employed 27 full-time employees,
and numerous independent contractors. The Company believes that its
relationships with its employees are satisfactory. None of the Company's
employees are covered by a collective bargaining agreement. From time to
time, the Company utilizes the services of independent consultants and
contractors to perform various professional services, particularly in the
areas of construction, design, well site surveillance, permitting and
environmental assessment.
ITEM 2. PROPERTIES
LOBO TREND
The Company owns interests in developed and undeveloped properties
in South Texas, primarily in the Lobo Trend and undeveloped acreage in South
Texas. The Company's Lobo Trend properties represented substantially all of
its reserves and PV-10 Value, as of December 31, 1998. The Company is the
operator of over 65% of the wells in which it has an interest.
The Lobo Trend in Webb and Zapata Counties in South Texas is one of
the largest onshore natural gas producing regions in the United States. The
primary geologic target in the Lobo Trend is the Lobo sand series of the
Lower Wilcox formation, which contains multiple pay sands. The primary
objectives in the Lobo Trend are the Lobo 1 and Lobo 6 sands. Other pay sands
exist at shallower and deeper horizons in certain areas of the trend.
Extensive faulting has trapped hydrocarbons in the Lobo Trend producing
horizons and has created a complex geological environment. Until recently,
2-D seismic and subsurface well control were the primary means for developing
the field. The introduction of 3-D seismic to the area in the early 1990s has
improved drilling success rates, and the Company has similarly experienced an
overall increase in its drilling success rates in the Lobo Trend as
technology has evolved.
The Company's Lobo Trend production is from reservoirs at depths
between 6,000 to 14,000 feet. Most of the production horizons are of low
permeability and must be fracture stimulated to improve rates of production.
As a result, a typical well has a high initial production rate which declines
rapidly and is followed by a long period of production at a lower rate with a
gradual decline.
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated net proved natural gas and
oil and condensate reserves of the Company and the present value of estimated
future net cash flows related to such reserves as of December 31, 1996, 1997
and 1998. The reserve data and present values presented have been estimated
by Huddleston & Co., Inc. For further information concerning the present
value of future net revenue from these proved reserves, see Note 11 of Notes
to Consolidated Financial Statements of the Company. See also "Item 7.
Management's Discussion and Analysis of Results of Operations and Financial
Condition".
AS OF DECEMBER 31,
-------------------------------------------
1996 1997 1998
---- ---- ----
Estimated proved reserves:
Oil and condensate (MBbls) 239 265 4,923
Natural gas (Mmcf) 49,246 51,165 189,753
10
Natural gas equivalents (Mmcfe) 50,678 52,754 219,291
Proved developed reserves as a percentage of proved reserves 34% 45% 27.2%
PV-10 Value (dollars in thousands)(1) $60,727 $51,487 $132,638
(1) PV-10 Value represents the present value of estimated future net
revenues before income tax discounted at 10% using prices in effect at
the end of the respective periods presented and including the effects of
hedging activities. In accordance with applicable requirements of the SEC,
estimates of the Company's proved reserves and future net revenues are
made using oil and natural gas sales prices estimated to be in effect as
of the date of such reserve estimates and are held constant throughout the
life of the properties (except to the extent a contract specifically
provides for escalation). The average prices used in calculating historical
PV-10 Value as of December 31, 1998 were $9.17 per Bbl of oil and $1.85 per
Mcf of natural gas, compared to $15.91 per Bbl of oil and $2.42 per Mcf
of natural gas as of December 31, 1997, and $23.86 per Bbl of oil and
$2.76 per Mcf of natural gas as of December 31, 1996.
There are numerous uncertainties inherent in estimating quantities
of proved oil and natural gas reserves and in projecting future rates of
production and timing of development expenditures, including many factors
beyond the control of the producer. The reserve data set forth herein
represents estimates only. Reserve engineering is a subjective process of
estimating underground accumulations of 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. As a result, estimates made by different
engineers often vary. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revision of such
estimates, and such revisions may be material. Accordingly, reserve estimates
are generally different from the quantities of oil and natural gas that are
ultimately recovered. Furthermore, the estimated future net revenues from
proved reserves and the present value thereof are based upon certain
assumptions, including future prices, production levels and costs, that may
not prove correct.
No estimates of proved reserves comparable to those included herein
have been included in reports to any federal agency.
PRODUCTION, PRICES AND EXPENSES
The following table presents certain information with respect to oil
and natural gas production, prices and expenses attributable to oil and
natural gas property interests owned by the Company for the years ended
December 31, 1996, 1997, and 1998.
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1997 1998
---- ---- ----
Production volumes:
Oil and condensate (MBbls) 37 21 79
Natural gas (Mmcf) 1,324 3,685 10,510
Total (Mmcfe) 1,546 3,811 10,984
Average realized prices:
Oil, condensate and natural gas liquids (per Bbl) $20.05 $18.95 $11.19
Natural gas (per Mcf) 2.15 2.33 2.07
Natural gas equivalents (per Mcfe) (1) 2.32 2.35 2.06
Expenses (per MCFE):
Production costs 1.25 0.49 0.37
Depreciation, depletion and amortization 0.66 0.96 1.14
Impairment of oil and gas properties 0.10 0.06 0.49
General and administrative, net 0.27 0.26 0.16
(1) Includes effects of hedging transactions.
PRODUCTIVE WELLS
The following table sets forth the number of productive wells in
which the Company owned an interest as of December 31, 1997 and 1998:
1997 1998
-------------- -------------
GROSS NET GROSS NET
Oil -- -- 7 --
Natural gas 78 43 438 184
---- ---- ---- ----
11
Total 78 43 445 184
==== ==== ==== ====
Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connection. Wells
that are completed in more than one producing horizon are counted as one well.
ACREAGE
The following table sets forth the Company's developed and undeveloped gross
and net leasehold acreage as of December 31, 1997 and 1998.
1997
------------------------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
------------------ --------------- ----------------
GROSS NET GROSS NET GROSS NET
Lobo Trend 20,676 11,554 8,206 5,516 28,882 17,070
Other 640 640 -- -- 640 640
------ ------ ----- ----- ------ ------
Total 21,316 12,194 8,206 5,516 29,522 17,710
====== ====== ===== ===== ====== ======
1998
------------------------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
------------------ --------------- ----------------
GROSS NET GROSS NET GROSS NET
Lobo Trend 30,360 18,467 60,413 44,184 90,773 62,651
Other 2,585 394 -- -- 2,585 394
------ ------ ------ ------ ------ ------
Total 32,945 18,861 60,413 44,184 93,358 63,045
====== ====== ====== ====== ====== ======
Undeveloped acreage includes leased acres on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of oil and natural gas, regardless of whether or not
such acreage contains proved reserves. A gross acre is an acre in which an
interest is owned. A net acre is deemed to exist when the sum of fractional
ownership interests in gross acres equals one. The number of net acres is the
sum of the fractional interests owned in gross acres expressed as whole
numbers and fractions thereof.
DRILLING ACTIVITIES
The table below sets forth the drilling activities of the Company on
its properties for the years ended December 31, 1996, 1997 and 1998.
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1996 1997 1998
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Development wells
Productive Natural Gas 2 1.2 15 9.2 26 17.6
Productive Oil 0 0.0 0 0.0 0 0.0
Dry 0 0.0 4 2.5 6 4.7
Exploratory Wells
Productive Natural Gas 0 0.0 0 0.0 0 0.0
Productive Oil 0 0.0 0 0.0 0 0.0
Dry 0 0.0 0 0.0 0 0.0
--- --- --- ---- --- ----
Total 2 1.2 19 11.7 32 22.3
=== === === ==== === ====
Wells in progress at
end of period 1 0.5 1 0.7 6 3.8
The information contained in the foregoing table should not be
considered indicative of future performance, nor should it be assumed that
there is any correlation between the number of productive wells drilled and
the oil and natural gas reserves generated therefrom.
PRESENT ACTIVITIES
From January 1, 1999 to March 15, 1999, the Company participated in
drilling activities on a total of 7 gross (6 net) wells, 2 of which have been
completed as productive wells, 3 of which were not completed and 2 of which
were dry holes.
A dry well (hole) is an exploratory or development well found to be
incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil and gas well. A productive well is an exploratory or
development well that is not a dry hole.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its
producing properties in accordance with standards generally accepted in the
oil and natural gas industry. The Company's properties are subject to
customary royalty interests, liens incident to operating agreements, liens
for current taxes and other burdens that the Company believes
12
do not materially interfere with the use of or affect the value of such
properties. Many of the Company's oil and natural gas properties are held in
the form of mineral leases. The indebtedness under the Credit Facility is
secured by substantially all of the Company's oil and natural gas properties.
See Item 7 - "Management's Discussion and Analysis of Results of Operation
and Financial Condition - Liquidity and Capital Resources" and "Financing
Arrangements."
As is customary in the oil and natural gas industry, a preliminary
investigation of title is made at the time of acquisition of undeveloped
properties. Title investigations, including a title opinion of local counsel,
are generally completed, however, before commencement of drilling operations
or the acquisition of producing properties. The Company believes that its
methods of investigating title to, and acquiring, its oil and natural gas
properties are consistent with practices customary in the industry and that
it has generally satisfactory title to the leases covering its proved
reserves.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms
as used in this Annual Report on Form 10-K. All volumes of natural gas
referred to herein are stated at the legal pressure base of the state or area
where the reserves exist and at 60 degrees Fahrenheit and in most instances
are rounded to the nearest major multiple.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
BBLS/D. Stock tank barrels per day.
BCF. Billion cubic feet.
BCFE. Billion cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
BTU. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
CAPITAL ASSET. Under Section 1221 of the Internal Revenue Code of
1986, as amended, a capital asset is defined as any type of property held by
a taxpayer, but does not include, among other things; (1) stock in trade,
property includible in inventory or property held primarily for sale to
customers in the ordinary course of business; or (2) depreciable property
used in a trade or business.
DEVELOPED ACREAGE. The number of acres which are allocated or
assignable to producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
EXPLORATORY WELL. A well drilled to find and produce oil or natural
gas reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or natural gas in another reservoir
or to extend a known reservoir.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case
may be, in which a working interest is owned.
MBBLS. One thousand barrels of crude oil or other liquid
hydrocarbons.
MBBLS/D. One thousand barrels of crude oil or other liquid
hydrocarbons per day.
MCF. One thousand cubic feet.
MCFE. One thousand cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
MMBTU. One million Btus.
13
MMCF. One million cubic feet.
MMCF/D. One million cubic feet per day.
MMCFE. One million cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids, which approximates the relative energy content of crude oil,
condensate and natural gas liquids as compared to natural gas. Prices have
historically been higher or substantially higher for crude oil than natural
gas on an energy equivalent basis.
NET ACRES OR NET WELLS. The sum of the fractional working interests
owned in gross acres or gross wells.
PRESENT VALUE. When used with respect to oil and natural gas
reserves, the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated future gross revenue to be
generated from the production of proved reserves, net of estimated production
and future development costs, using prices and costs in effect as of the date
indicated, without giving effect to nonproperty-related expenses such as
general and administrative expenses, debt service and future income tax
expense or to depreciation, depletion and amortization, discounted using an
annual discount rate of 10%.
PROVED DEVELOPED RESERVES. Proved reserves that can be expected to
be recovered from existing wells with existing equipment and operating
methods.
PROVED RESERVES. The estimated quantities of crude oil, natural gas
and natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED LOCATION. A site on which a development well can
be drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion; proved reserves
for other undrilled units are claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation.
PV-10 VALUE. When used with respect to oil and natural gas reserves,
the estimated future gross revenue to be generated from the production of
proved reserves, net of estimated production and future development costs,
using prices and costs in effect as of the date indicated, without giving
effect to nonproperty-related expenses such as general and administrative
expenses, debt service and future income tax expense or to depreciation,
depletion and amortization, discounted using an annual discount rate of 10%.
RECOMPLETION. The completion for production of an existing well bore
in another formation from that in which the well has been previously
completed.
RESERVOIR. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
ROYALTY INTEREST. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of costs
of production.
3-D SEISMIC. Advanced technology method of detecting geological
structures susceptible to accumulations of hydrocarbons identified through a
three-dimensional picture of the subsurface created by the collection and
measurement of the intensity and timing of sound waves transmitted into the
earth as they reflect back to the surface.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of whether such
acreage contains proved reserves.
WORKING INTEREST. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and
a share of production.
14
WORKOVER. Operations on a producing well to restore or increase
production.
ITEM 3. LEGAL PROCEEDINGS.
From time to time the Company is a party to various legal
proceedings arising in the ordinary course of business, but is not currently
a party to litigation that it believes would have a material adverse effect
on the consolidated financial condition, results of operations or cash flows
of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during
the fourth quarter of 1998.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Michael Petroleum Corporation is a wholly owned subsidiary of
Michael Holdings, Inc. ("MHI"). As of March 15, 1999, substantially all of
common stock of MHI is owned by management, directors and employees of
Michael Petroleum Corporation and thus no organized trading market exists for
either the Company's or MHI's common stock. No dividends have been declared
by the Company in the years ended December 31, 1997 and 1998. It is not
anticipated by management of the Company that dividends will be declared in
subsequent years. See "Item 12. Security Ownership of Certain Beneficial
Owners and Management." The terms of the Indenture governing the Series B
Notes and the Credit Facility restrict the Company's ability to declare and
pay cash dividends.
ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth selected consolidated financial data as
of the end of each of the years in the five-year period ended December 31,
1998. The financial data for each of the years ended, and as of, December 31,
1994, 1995, 1996, 1997 and 1998 have been derived from the audited
consolidated financial statements of the Company. This information should be
read in conjunction with the Company's consolidated financial statements and
Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations." The Company's results of operations and financial
condition have been affected by acquisitions of oil and natural gas
properties during certain of the periods presented below. See Note 2 of Notes
to Consolidated Financial Statements.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
1994 1995 1996 1997 1998
------- ------- ------- ------- -------
(IN THOUSANDS)
Income Statement Data:
Operating revenues $ 3,592 $ 2,937 $ 3,776 $ 9,139 $22,718
Operating expenses 4,275 4,113 3,581 7,072 24,049
------- ------- ------- ------- -------
Operating income (loss) (683) (1,176) 195 2,067 (1,331)
Loss from continuing operations (853) (2,114) (2,479) (7) (8,710)
Discontinued operations (719) 2,087 - - -
Extraordinary item - - - - (531)
Net loss $(1,572) $ (27) $(2,479) $ (7) $(9,241)
15
AS OF DECEMBER 31,
-------------------------------------------------------
1994 1995 1996 1997 1998
------- ------- ------- ------- -------
(DOLLARS IN THOUSANDS)
Balance Sheet Data:
Current assets $ 1,611 $1,241 $ 4,375 $ 5,255 $ 8,951
Oil and gas properties, net 9,176 7,890 16,208 28,011 130,878
Total assets 11,461 9,145 21,001 33,617 147,282
Long-term debt 6,694 6,372 11,784 19,885 144,842
Shareholder's equity (deficit) 1,111 423 (1,908) (1,915) (11,156)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The following discussion is intended to assist in an understanding
of the Company's consolidated financial position and results of operations
for each year during the three-year period ended December 31, 1998. The
Company's consolidated financial statements and the notes thereto that follow
contain detailed information that should be referred to in conjunction with
the following discussion.
GENERAL
The Company is an independent energy company engaged in the
acquisition, exploitation and development of oil and natural gas properties,
principally in the Lobo Trend of South Texas. The Company began operations in
1983. In August 1996, the Company acquired interests in approximately 21,000
developed and undeveloped gross acres in the Lobo Trend for approximately
$15.3 million. In 1998, the Company acquired interests in approximately
46,900 developed and undeveloped gross acres in the Lobo Trend for
approximately $78.3 million. In 1998, the Company participated in the
drilling of 32 gross and 22.3 net natural gas wells, completing 26 gross and
17.6 net wells capable of commercial production, respectively.
Through the periods presented, the Company's results of operations
reflect two tax structures (S corporation and C corporation) which have
influenced, among other things, the historical levels of its owners'
compensation. Effective July 1, 1996, the Company changed its tax filing
status from an S corporation to a C corporation. Due to this change, the
Company recognized a one-time charge of approximately $2.0 million to reflect
deferred income taxes payable as of June 30, 1996.
The Company utilizes the "successful efforts" method of accounting
for its oil and natural gas activities as described in Note 1 of Notes to
Consolidated Financial Statements. From time to time, the Company has
utilized hedging transactions with respect to a portion of its oil and
natural gas production to achieve a more predictable cash flow, as well as to
reduce its exposure to price fluctuations. See "Liquidity and Capital
Resources."
RESULTS OF OPERATIONS
The following table summarizes production volumes, average sales
prices and operating revenues for the Company's oil and natural gas
operations for the years ended December 31, 1996, 1997 and 1998:
YEAR ENDED DECEMBER 31
-----------------------------
1996 1997 1998
------ ------ -------
(DOLLARS IN THOUSANDS,
EXCEPT PER UNIT DATA)
Production volumes:
Oil and condensate (MBbls) 37 21 79
Natural gas (Mmcf) 1,324 3,685 10,510
Average sales prices:
Oil and condensate (per Bbl) $20.05 $18.95 $11.19
Natural gas (per Mcf) 2.15 2.33 2.07
Operating revenues:
Oil and condensate $742 $565 $888
Natural gas(1) 2,852 8,574 21,780
------ ------ -------
Total $3,594 $9,139 $22,668
====== ====== =======
(1) Net of hedging gains or losses.
COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997
16
Oil and natural gas revenues for the year ended December 31, 1998
increased 149% to $22.7 million from $9.1 million for the year ended December
31, 1997. Production volumes for natural gas for the year ended December 31,
1998 increased 185% to 10,510 Mmcf from 3,685 Mmcf for the year ended 1997.
Average natural gas prices (including the effect of hedging transactions)
decreased 12% to $2.07 per Mcf for 1998 from $2.33 per Mcf for 1997. The
increase in natural gas production in 1998 was due to the Company's 1998
acquisitions and the new wells placed on line resulting from the Company's
drilling activities.
Oil and natural gas production costs for the year ended December 31,
1998 increased 116% to $4.1 million from $1.9 million for the year ended
December 31, 1997, primarily due to the increase in production. However,
actual production costs per equivalent unit decreased to $.37 per Mcfe for
the year ended December 31, 1998 from $.57 per Mcfe for the year ended
December 31, 1997. The decrease on an equivalent basis was due primarily to
increased production volumes during 1998.
Depletion, depreciation, and amortization ("DD&A") expense for the
year ended December 31, 1998 increased 240% to $12.6 million from $3.7
million for the same period in 1997. The increase in DD&A expense was due to
higher production volumes and an increase in the depletion rate per Mcfe
from $.96 for 1997 to $1.14 for 1998. The increase in rate was primarily due
to acquisitions completed in 1998 and a reduction in estimated proved
reserves. In addition, total impairment charges increased to $5.4 million for
the year ended December 31, 1998 compared to $238,000 for the year ended
December 31, 1997. The impairment charges in 1998 were primarily due to lower
oil and natural gas prices and development dry holes drilled on certain oil
and gas leases that resulted in a reduction in the estimated proved reserves.
General and administrative expense increased 83% to $1.80 million in
1998 from $980,000 for the same period in 1997 due to the addition of several
new employees and their related benefits, plus increases in office expenses
and legal and professional fees in connection with the Series A and Series B
Notes offerings.
Interest expense and loan amortization costs, net of capitalized
interest, for the year ended December 31, 1998 increased 486% to $12.3
million compared to $2.1 million for 1997. The increase was due to the higher
levels of outstanding debt during 1998, primarily as a result of the Series A
and Series B Notes offerings, as compared to 1997.
The income tax benefit was $4.95 million for the year ended December
31, 1998 compared to an income tax expense of $11,000 for the same period in
1997. The Company has a net operating loss carryforward of $19.5 million at
December 31, 1998 which was generated beginning in fiscal year 1997. The net
operating loss will begin to expire in 2017. Thus, future taxable income of
at least $19.5 million will need to be generated by 2017 in order for the
Company to realize the net operating loss at December 31, 1998. Based on
estimates of future taxable income, management believes it is more likely
than not that the net operating loss will be fully utilized prior to
expiration. In order to achieve sufficient taxable income, certain tax
planning strategies (primarily the capitalization of intangible drilling
costs for tax purposes) were implemented in fiscal year 1998. Specific
differences between pre-tax loss and taxable income pertain to developmental
dry holes, intangible drilling costs, capitalized interest and depletion and
depreciation of oil and gas and other properties. Differences in these items
begin reversing in fiscal year 1999 and thereafter. Estimates of future
taxable income are significantly affected by changes in oil and natural gas
prices, estimates of future production, and estimated operating and capital
costs. The deferred tax asset could be reduced in the near term if
management's estimates of taxable income during the carryforward period are
significantly reduced or if alternative tax strategies are no longer viable.
If the Company is not able to generate sufficient taxable income in the
future through operating results, a valuation allowance will be recorded
through a charge to expense.
The extraordinary loss of $531,000 (net of income tax benefit of
$285,000) for the year ended December 31, 1998 was due to the writeoff of the
remaining loan costs relating to the Company's credit agreement under the
T.E.P. Financing, which terminated on April 2, 1998. No extraordinary charges
or similar items occurred in 1997.
The net loss for the year ended December 31, 1998 was $9.2 million
compared to a loss of $7,000 for the year ended December 31, 1997, primarily
as a result of the factors discussed above.
COMPARISON OF YEARS ENDED DECEMBER 31, 1997 AND 1996
Oil and natural gas revenues for the year ended December 31, 1997
increased 153% to $9.1 million compared to $3.6 million for 1996. Production
volumes for natural gas during the year ended December 31, 1997 increased
178% to 3,685 Mmcf from 1,324 Mmcf for 1996. Average gas prices increased
8.3% to $2.33 per Mcf for 1997 from $2.15 per Mcf for 1996. The increase in
natural gas production was due to the 1996 acquisitions and the Company's
workover and drilling program with respect to the properties acquired and
existing properties.
Oil and natural gas production costs for the year ended December 31,
1997 decreased 3% to $1.87 million from $1.93 million for 1996 primarily due
to the sale of the Company's Hull Field oil properties in August 1996 that
historically had incurred much higher lease operating costs than the
Company's average Lobo Trend natural gas wells. Accordingly, production costs
per equivalent unit decreased to $0.49 per Mcfe for 1997 from $1.25 per Mcfe
for 1996. The per unit cost decreased as a result of increased production of
natural gas, which has lower per unit operating costs, and the Company's
disposition in August 1996 of oil producing properties having higher
operating costs.
17
DD&A expense for the year ended December 31, 1997 increased 208% to
$3.7 million from $1.2 million for the same period in 1996. This increase was
due to the increased production during 1997.
Exploration expense increased from $46,000 in 1996 to $333,000 in
1997, due primarily to the expiration of the terms of certain leases that had
not been developed.
General and administrative expense for the year ended December 31,
1997 increased 131% to $980,000 from $424,000 for 1996, primarily as a result
of increases in the number of employees and related benefits, plus increased
legal and professional fees.
Interest expense, net of capitalized interest, for the year ended
December 31, 1997 increased 127% to $2.1 million, compared to $924,000 for
1996. This increase in interest expense was due to increased debt levels in
the second half of 1996 and in 1997 resulting from funds borrowed to acquire
and develop the Lobo Trend properties.
The net loss for the year ended December 31, 1997 decreased to
$7,000, compared to a net loss of $2.5 million for 1996, as a result of the
factors described above and the $2.0 million income tax charge related to the
Company's conversion from an S corporation to a C corporation in 1996.
LIQUIDITY AND CAPITAL RESOURCES
Cash flows provided by operating activities from the Company's
operations were $848,000, $3.5 million and $5.3 million for the years ended
December 31, 1996, 1997 and 1998, respectively. The increases in 1997 and
1998 were primarily attributable to increased production resulting from the
acquisitions and the new wells placed on line as a result of the Company's
drilling activities. Cash and working capital in 1999 is expected to be
provided through internally generated cash flows and borrowings. See
"--Financing Arrangements" below.
Cash flows used in investing activities by the Company were $14.8
million, $15.0 million and $116.3 million in 1996, 1997 and 1998,
respectively. Property additions through acquisition, exploration and
development activities were the primary reasons for the use of funds in
investing activities. Cash flows used in investing activities by the Company
for 1996, 1997 and 1998 resulted primarily from the acquisition and
development of the Lobo Trend properties.
Cash flows provided by the Company's financing activities were $14.8
million, $11.1 million and $110.7 in 1996, 1997 and 1998, respectively. In
1996 and 1997, the cash flows from financing activities resulted from
borrowings under the T.E.P. Financing. In 1998, the financing cash flows were
primarily from proceeds from the Series A Notes and borrowings from the Credit
Facility.
The Company's primary sources of liquidity have historically been
provided from funds generated by operations and from borrowings. The Company
completed the sale of its $135.0 million Series A Notes in April 1998.
Approximately $28.0 million of the net proceeds from the sale of the Series A
Notes was used to repay the indebtedness outstanding under the T.E.P.
Financing. Approximately $89.3 million of the net proceeds were used to fund
acquisitions and the remaining balance for working capital and general
corporate purposes. During May 1998, the Company entered into the Credit
Facility, as described below under "--Financing Arrangements."
The Company's revenues, profitability, future growth and ability to
borrow funds and obtain additional capital, and the carrying value of its
properties, are substantially dependent on prevailing prices of oil and
natural gas. It is impossible to predict future oil and natural gas price
movements with certainty. Declines in prices received for oil and natural gas
would have an adverse effect on the Company's financial condition, liquidity,
ability to finance capital expenditures and results of operations. Lower
prices would also impact the amount of reserves that can be produced
economically by the Company.
During 1998, the Company recorded an impairment provision on
producing properties of $5.4 million before income tax. This impairment
provision was determined based on an assessment of recoverability of net
property costs from estimated future net cash flows from those properties.
Estimated future net cash flows are based on management's best estimate of
projected oil and gas reserves and prices. If oil and gas prices remain at
lower levels or decline further, the Company may be required to record
further impairment provisions in the future, which may be material.
The Company has experienced and expects to continue to experience
substantial working capital requirements primarily due to the Company's
development program. Capital expenditures for 1999 are currently estimated to
be approximately $27.0 million. Substantially all of the capital expenditures
will be used to fund drilling activities, property acquisitions and 3-D
seismic surveys in the Company's project areas. The Company's plan
anticipates drilling 32 gross (28 net) wells in 1999. However, the Company's
borrowing base under its Credit Facility was reduced, effective April 1,
1999, from $35 million to $23 million. The remaining amount of borrowing
capacity under the Credit Facility was drawn as of April 1, 1999 to make the
required interest payments on the Series B Notes. See "--Financing
Arrangements" below. While the current estimates of capital expenditures for
fiscal 1999 set forth above do not take into account this lower borrowing
base, the Company believes that alternate sources of funding to finance the
incremental capital expenditures that would otherwise be funded by the Credit
Facility should be available to the Company. However, no assurances can be
given that any such financing alternatives will be available, and if so, on
terms considered advantageous to the Company. If suitable alternative
financing or other alternative capital resources are not available to the
Company, its currently planned capital expenditures would be reduced and
could be significantly reduced. See "--Cautionary Statements Regarding
Forward-Looking Information-Future Need For and Availability of Capital,"
"--Restrictions Imposed by Lenders" and "--Incurrence of Substantial
Indebtedness."
Assuming additional debt financing was available to fund the
Company's 1999 estimated capital expenditures level, the Company believes
that additional financing, preferably public or private equity financing,
will be necessary in the future in order for the Company to continue to
increase its reserve base and make additional acquisitions in accordance with
its long-range development plan. Should recent prevailing equity market
conditions for oil and natural gas independent exploration and development
companies continue, the Company does not foresee an infusion of funds from
public sales of its equity for the foreseeable future. An inability to obtain
sufficient capital to achieve these purposes could cause the Company to
curtail its planned property acquisition and development activities, which
could adversely affect its future financial condition, cash flows and results
of operations.
18
FINANCING ARRANGEMENTS
In August 1996, the Company entered into the T.E.P. Financing, which
provided for an aggregate term loan amount of $42.2 million, available for
oil and natural gas property acquisitions and development drilling, subject
in each case to borrowing base limitations. The Company used approximately
$28.0 million of the net proceeds from the sale of the Series A Notes to
repay all of the outstanding indebtedness under the T.E.P. Financing in April
1998.
In August 1996, the Company also granted Cambrian Capital Partners,
L.P., an affiliate of the T.E.P. Financing lender ("Cambrian"), a 30% Net
Profits Interest (as defined in the Net Profits Interest Conveyance dated
August 12, 1996), net to the Company's interest, in all of the Company's
properties, including those acquired in the 1996 Acquisition. As part of the
T.E.P. Financing, the Company also granted to Cambrian a warrant to purchase
up to 5% of the Company's common stock until August 12, 2001. The value
assigned to the Net Profits Interest and warrant was recorded as a discount
to the loan proceeds. The Company used approximately $11.0 million of the net
proceeds from the sale of the Series A Notes to acquire the Net Profits
Interest. In addition, the warrant to purchase the Company's common stock was
cancelled, and MHI issued to Cambrian a warrant to acquire 38,671 shares of
its Common Stock at an exercise price of $8.00 per share.
In May 1998, the Company entered into its Credit Facility with
Christiania as lender and administrative agent, pursuant to the terms of the
Credit Facility. The Credit Facility provided for loans in an outstanding
principal amount not to exceed $50.0 million at any one time, subject to a
borrowing base to be determined semi-annually (each April and October) by the
administrative agent (the initial borrowing base was $30.0 million), and the
issuance of letters of credit in an outstanding face amount not to exceed
$6.0 million at any one time with the face amount of all outstanding letters
of credit reducing, dollar-for-dollar, the availability of loans under the
Credit Facility. Although the initial borrowing base was $30 million, and
effective November 9, 1998, the borrowing base was increased by $5 million to
a total of $35 million, the new borrowing base effective April 1, 1999, was
reduced to $23 million. See "--Liquidity and Capital Resources" above.
Under the Credit Facility, the principal balance outstanding is due
and payable on May 28, 2002, and each letter of credit shall be reimbursable
by the Company when drawn, or if not then otherwise reimbursed, paid pursuant
to a loan under the Credit Facility. Commencing on October 31, 1999, and
continuing until its stated maturity, the maximum amount available for
borrowings and letters of credit under the Credit Facility will not only be
adjusted (increased or decreased, as applicable) by the semi-annual borrowing
base determination, but also (i) decreased by monthly mandatory reductions in
the borrowing base of $1.5 million per month and (ii) adjusted for sales of
collateral having an aggregate value exceeding the lesser of $4.0 million per
year or 5% of the Company's total proved reserve values. At March 31, 1999,
the Company had drawn all of the $23 million then available under Credit
Facility. Both the Company and Christiania may also initiate two unscheduled
redeterminations of the borrowing base during any consecutive twelve-month
period. If the sum of the outstanding principal balance and amount of
outstanding letters of credit (both drawn and undrawn) exceeds the borrowing
base, the Company shall, within 30 days, either repay such excess in full or
provide additional collateral acceptable to Christiania.
The Credit Agreement contains certain covenants by the Company,
including (i) limitations on additional indebtedness and on guaranties by the
Company except as permitted under the Credit Agreement, (ii) limitations on
additional investments except those permitted under the Credit Agreement and
(iii) restrictions on dividends or distributions or on repurchases or
redemptions of capital stock by the Company except for those involving
repurchases of MHI capital stock which may not exceed $500,000 in any fiscal
year. In addition, the Credit Agreement requires the Company to maintain and
comply with certain financial covenants and ratios, including a minimum
interest coverage ratio, a minimum current ratio and a covenant requiring
that the Company's general and administrative expenses may not exceed 12.5%
of the Company's gross revenues in any calendar year. As of December 31,
1998, the Company was in violation of certain administrative covenants and a
financial covenant under the Credit Facility. The Company has obtained a
waiver with respect to these violations from Christiania, which agreed not to
assert any default based upon such violations. The Company and the lender
have entered into a First Amendment to the Credit Facility to amend those
covenants and the interest rate under the Credit Facility.
As amended, the interest rate for each borrowing under the Credit
Facility will be calculated at either (i) the ABR rate (as described below),
or (ii) the Eurodollar Rate (as described below) plus 2.25%, at the election
of the Company. Interest on the borrowings under the Credit Facility will be
due (i) with respect to loans bearing interest at the ABR rate, quarterly in
arrears and at maturity, and (ii) with respect to loans bearing interest at
the Eurodollar Rate, on the last day of each relevant interest period and, in
the case of any interest period longer than three months, on a quarterly
basis. The Company's obligations under the Credit Facility are secured by
substantially all of the oil and natural gas assets of the Company, including
accounts receivable and material contracts, equipment and gathering systems.
The proceeds of the Credit Facility may be used to finance working capital
needs and for general corporate purposes of the Company in the ordinary
course of its business.
Under the Credit Facility, "ABR" means the highest of (i) the
interest rate announced publicly by Christiania as its prime rate plus 0.5%
in effect in its principal office in New York, (ii) the secondary market rate
for three-month certificates of deposit (adjusted for statutory reserve
requirements) plus 1.5% and (iii) the federal funds effective rate from time
to time plus 1.0%. "Eurodollar Rate" means the rate (adjusted for statutory
reserve requirements of eurocurrency
19
liabilities) at which eurodollar deposits for one, two, three or six (or, if
available and acceptable to the Credit Facility lenders, nine or twelve)
months (as selected by the Company) are offered to Christiania in the
Interbank eurodollar market.
See "--Cautionary Statements Regarding Forward-Looking Information-
Future Need For and Availability of Capital," "--Restrictions Imposed by
Lenders" and "--Incurrence of Substantial Indebtedness."
TERMS AND FINANCIAL COVENANTS OF 11 1/2% SENIOR NOTES DUE 2005
The indenture governing the Series B Notes (the "Indenture") contains
certain covenants that, among other things, limit the ability of the Company
to incur additional indebtedness, pay dividends, repurchase equity interests
or make other Restricted Payments (as defined in the Indenture), create
liens, enter into transactions with affiliates, sell assets or enter into
certain mergers and consolidations. The Company is allowed to incur
additional indebtedness if it meets an EBITDA/Interest ratio and an
ACNTA/Debt ratio computed based on the last four quarters immediately
proceeding the incurrence of the indebtedness on a pro forma basis. In the
event of certain asset dispositions, the Company is required under certain
circumstances to use the excess proceeds from such a disposition to offer to
repurchase the Series B Notes (and other Senior Indebtedness for which an offer
to repurchase is required to be concurrently made) having an aggregate
principal amount equal to the excess proceeds at a purchase price equal to
100% of the principal amount of the Series B Notes, together with accrued and
unpaid interest and Liquidated Damages (as defined in the Indenture), if any,
to the date of repurchase (a "Net Proceeds Offer").
CAPITAL EXPENDITURES AND OUTLOOK
The following table sets forth the Company's capital expenditures
for the three years ended December 31, 1998 (in thousands):
YEAR ENDED DECEMBER 31
-----------------------------------
1996 1997 1998
-------- -------- --------
Property acquisition:
Unproved $ 2,929 $ 355 $ 15,183
Proved 9,554 2,425 78,458
Development 2,757 12,074 25,295
Interest capitalized 217 574 1,440
-------- -------- --------
Total costs incurred $ 15,457 $ 15,428 $120,376
======== ======== ========
The Company currently has budgeted capital expenditures of
approximately $27.0 million for 1999. See "--Liquidity and Capital Resources"
above. Substantially all of the capital expenditures will be used to fund
drilling activities, property acquisitions and 3-D seismic surveys in the
Company's project areas. The Company intends to drill approximately 32 gross
(28 net) wells in 1999. The Company will require capital from sources in
addition to that funded under the Credit Facility in order for the Company to
fully implement its development drilling strategy in 1999 and for the
foreseeable future. In the event that additional capital is not available to
the Company, capital expenditures are expected to be reduced and could be
significantly reduced.
NATURAL GAS BALANCING
The Company incurs certain natural gas production volume imbalances
in the ordinary course of business and utilizes the sales method to account
for such imbalances. Under this method, income is recorded based on the
Company's net revenue interest in production taken for delivery. Management
does not believe that the Company had any material imbalances as of December
31, 1996, 1997, or 1998.
EFFECTS OF INFLATION AND CHANGES IN PRICE
20
The Company's results of operations and cash flows are affected by
changes in oil and natural gas prices. If the price of oil and natural gas
increases (decreases), there could be a corresponding increase (decrease) in
the operating cost that the Company is required to bear for operations, as
well as an increase (decrease) in revenues. Inflation has had only a minimal
effect on the Company.
YEAR 2000
Many computer systems have been designed using software that
processes transactions using two digits to represent the year. This type of
software will generally require modifications to function properly with dates
after December 31, 1999. The same issue applies to microprocessors embedded
in machinery and equipment, such as gas compressors and pipeline meters. The
impact of failing to identify and correct this problem could be significant
to the Company's ability to operate and report results, as well as
potentially exposing the Company to third party liability.
The Company has begun making necessary modifications to its internal
information computer systems in preparation for the Year 2000. The Company
currently estimates that its Year 2000 project will be completed by June
1999, and believes that the total related costs will be approximately
$30,000, funded by cash from operations or short term borrowings. Actual
costs to date have been less than $10,000.
The Company began reviewing the Year 2000 compliance status of field
equipment, including compressor stations, gas control systems and data
logging equipment, during the fourth quarter of 1998 and expects to complete
this review by June 1999.
The Company has identified significant third parties whose Year 2000
compliance could affect the Company and is in the process of formally
inquiring about their Year 2000 status. The Company has received responses to
less than 10% of its inquiries. Despite its efforts to assure that such
third parties are Year 2000 compliant, the Company cannot provide assurance
that all significant third parties will achieve compliance in a timely
manner. A third party's failure to achieve Year 2000 compliance could have a
material adverse effect on the Company's operations and cash flow. The
potential effect of Year 2000 non-compliance by third parties is currently
unknown.
Project costs and the timetable for Year 2000 compliance are based
on management's best estimates. In developing these estimates, assumptions
were made regarding future events including, among other things, the
availability of certain resources and the continued cooperation of the
Company's customers and suppliers. Actual costs and timing may differ from
management's estimates due to unexpected difficulties in obtaining trained
personnel, locating and correcting relevant computer code and other factors.
Management does not expect the costs of the Company's Year 2000 project to
have a material adverse effect on the Company's financial position, results
of operations or cash flows. Presently, based on information available, the
Company cannot conclude that any failure of the Company or third parties to
achieve Year 2000 compliance will not adversely effect the Company.
The Company has designated personnel responsible to not only
identify and respond to these issues, but also to develop a contingency plan
in the event that a problem arises after the turn of the century.The Company
is currently identifying appropriate contingency plans in the event of
potential problems resulting from failure of the Company's or significant
third party computer systems on January 1, 2000. The Company has not
completed any contingency plans to date. Specific contingency plans will be
developed in response to the results of testing scheduled to be complete by
October 1999, as well as the assessed probability and risk of system or
equipment failure. These contingency plans may include installing backup
computer systems or equipment, temporarily replacing systems or equipment
with manual processes, and identifying alternative suppliers, service
companies and purchasers. The Company expects these plans to be complete by
December 1999.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
Certain information contained in this Annual Report on Form 10-K (as
well as certain other written or oral statements made by or on behalf of the
Company) may be deemed to be forward-looking statements which can be
identified by the use of forward-looking terminology such as "believes,"
"expects," "may," "will," "should" or "anticipates" or the negative thereof
or comparable terminology, or by discussions of strategy that involve risks
and uncertainties. In addition, all statements other than statements of
historical facts included in this Annual Report on Form 10-K, including,
without limitation, statements regarding the the levels of capital
expenditures for 1999 and succeeding periods, the availability of sources of
capital to fund these capital expenditures and the Company's other working
capital and operational requirements, the Company's business strategy,
worldwide prices for crude oil and natural gas, the Company's ability to
raise additional long-term capital, the Company's success in dealing with its
lenders, future governmental regulation, future oil and natural gas reserves,
future drilling and development opportunities and operations, future
acquisitions, future production of oil and natural gas (and the prices
thereof and costs therefor), anticipated results of hedging activities,
future capital expenditures and future net cash flows, are forward-looking
statements and may contain information concerning financial results, economic
conditions, trends and known uncertainties. Such statements reflect the
Company's current views with respect to future events and financial
performance, and involve risks and uncertainties. Actual results could differ
materially from those projected in the forward-looking statements as a result
of these various risks and uncertainties, including, without limitation, (i)
factors discussed below such as natural gas price fluctuations and markets,
uncertainties of estimates of reserves and future net revenues, the success
of the Company's drilling programs, competition in the oil and natural gas
industry, operating risks, risks associated with acquisitions, future need
for and availability of capital, and regulatory and environmental risks, (ii)
adverse changes to the properties acquired in the Transactions and the
interests subject to the Lobo Lease or the failure of the Company to achieve
the anticipated benefits of the Transactions and the interests subject to the
Lobo Lease, (iii) adverse changes in the market for the Company's oil and
natural gas production and (iv) those additional factors discussed
immediately below and under Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations," Item 1. "Business" and Item 2.
"Properties" and elsewhere in this Annual Report on Form 10-K.
INCURRENCE OF SUBSTANTIAL INDEBTEDNESS
As of December 31, 1998, the Company had $147.1 million ($144.8
million, net of unamortized discount) of indebtedness outstanding (including
current maturities of long-term indebtedness) as compared to a shareholder's
deficit of $11.2 million. The indenture limits the amounts of borrowings
under bank facilities, including borrowings under the Credit Facility. In
addition, as of March 31, 1999, due to borrowing base reductions, the Company
has no borrowing capacity remaining under the Credit Facility. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" and "--Financing Arrangements".
This level of indebtedness may pose substantial risks to the
Company, including, but not limited to, the following: (i) the Company's
ability to obtain additional financing in the future, whether for working
capital, capital expenditures, acquisitions or other purposes, may be
impaired; (ii) a portion of the Company's cash flow from operations is
required to be dedicated to the payment of interest on its debt, thereby
reducing funds available to the Company for other purposes; (iii) the Company
may not generate sufficient cash flow to pay the principal of and interest on
the Series B Notes; (iv) the Company's flexibility in planning for or
reacting to changes in market conditions may be limited; and (v) the Company
may be more vulnerable given current prevailing industry conditions. In
addition, the Company's earnings have been insufficient to meet its fixed
charges.
The ability of the Company to meet its debt service obligations,
including with respect to the Series B Notes, will depend on the future
operating performance and financial results of the Company, which will be
subject in part to factors beyond the control of the Company. Further, if the
Company is unsuccessful in increasing its proved reserves, the future net
revenues from existing proved reserves may not be sufficient to pay the
principal of and interest on the
21
Series B Notes in accordance with their terms. There can be no assurance that
the Company will continue to generate earnings in the future sufficient to
cover its fixed charges. If the Company is unable to generate earnings in the
future sufficient to cover its fixed charges and is unable to borrow
sufficient funds to cover such charges, it may be required to refinance all
or a portion of its debt or to sell all or a portion of its assets. There can
be no assurance that a refinancing would be possible, nor can there be any
assurance as to the timing of any asset sales or the proceeds that the
Company could realize therefrom. In addition, the Credit Agreement contains
certain covenants by the Company, including (i) limitations on additional
indebtedness and on guaranties by the Company except as permitted under the
Credit Agreement, (ii) limitations on additional investments except those
permitted under the Credit Agreement and (iii) restrictions on dividends or
distributions on or repurchases or redemptions of capital stock by the
Company, except for those involving repurchases of MHI capital stock which
may not exceed $500,000 in any fiscal year. Also, the Credit Agreement
requires the Company to maintain and comply with certain financial covenants
and ratios, including a minimum interest coverage ratio, a minimum current
ratio and a covenant requiring that the Company's general and administrative
expenses may not exceed 12.5% of the Company's gross revenues in any calendar
year. See "--Restrictions Imposed by Lenders," "--Future Need for and
Availability of Capital" and Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Financing Arrangements."
EFFECTIVE SUBORDINATION OF THE SERIES B NOTES
The Series B Notes are senior unsecured obligations of the Company
and rank in parity with all existing and future Senior Indebtedness of the
Company, including any indebtedness incurred under the Credit Facility, and
senior in right of payment to all future Subordinated Indebtedness of the
Company. Holders of secured Indebtedness of the Company, including under the
Credit Facility, will have claims with respect to assets constituting
collateral for such Indebtedness that are prior to the claims of the Holders
of the Series B Notes. In the event of a default on the Series B Notes, or a
bankruptcy, liquidation or reorganization of the Company, such assets will be
available to satisfy obligations with respect to the indebtedness secured
thereby before any payment therefrom could be made on the Series B Notes.
Accordingly, the Series B Notes will be effectively subordinated to claims of
secured creditors of the Company to the extent of such pledged collateral. As
of March 31, 1999, the Company had $23.0 million of secured indebtedness.
RESTRICTIONS IMPOSED BY LENDERS
The Indenture and the Credit Agreement governing the terms of the
Credit Facility impose significant operating and financial restrictions on
the Company. Such restrictions will affect, and in many respects
significantly limit or prohibit, among other things, the ability of the
Company to incur additional indebtedness, make certain capital expenditures,
pay dividends, repay or repurchase indebtedness prior to its stated maturity
or engage in mergers or acquisitions. These restrictions could also limit the
ability of the Company to effect future financings, make needed capital
expenditures, withstand a future downturn in the Company's business or the
economy in general, or otherwise conduct necessary corporate activities. Any
failure by the Company to comply with these restrictions could lead to a
default under the terms of such indebtedness and the Series B Notes. In the
event of default, the holders of such indebtedness could elect to declare all
of the funds borrowed pursuant thereto to be due and payable together with
accrued and unpaid interest. In such event, there can be no assurance that
the Company would be able to make such payments or borrow sufficient funds
from alternative sources to make any such payment. Even if additional
financing could be obtained, there can be no assurance that it would be on
terms that are favorable or acceptable to the Company. In addition, the
Company's indebtedness under the Credit Facility is secured by a substantial
oprtion of the assets and properties of the Company. The pledge of such
collateral to the Company's secured lenders could impair the Company's
ability to obtain additional financing on favorable terms. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" and "--Financing Arrangements."
FUTURE NEED FOR AND AVAILABILITY OF CAPITAL
The Company anticipates that it will require additional financing to
effect both future property acquisitions and continue its development
programs. The Company or MHI may seek funds through the sale of debt or
equity securities, which could significantly dilute the ownership of the
Company's or MHI's existing shareholders. In addition, if necessary (and
permitted under the terms of the indenture), the Company or MHI may seek
funds from project financing, strategic alliances or other sources, all of
which may dilute the interest of the Company in the specific project
financed. The Company's ability to access additional capital is dependent
upon the Company's outstanding commitments and financial condition, and the
financial strength of the capital markets at such time. There can be no
assurance that such additional financing can be obtained
22
or, if so, obtained on terms acceptable to the Company.
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 natural gas and the Company's success in locating and
producing new reserves. If revenues were to decrease as a result of lower oil
and natural gas prices, decreased production or otherwise, the Company could
have limited ability to replace its reserves or to maintain production at
current levels, resulting in a decrease in production and revenues over time.
The Company has budgeted approximately $27.0 million for capital expenditures
in 1999, exclusive of acquisitions. The Company expects to use cash flow from
operations and from borrowings or other capital sources to fund these
expenditures. However, the Company's borrowing base under the Credit Facility
has been reduced from $35 million to $23 million, substantially all of which
is currently drawn. If the Company's cash flow from operations and
availability of funds from other capital sources are not sufficient to
satisfy its capital expenditure requirements capital expenditures may be
reduced. There can be no assurance that additional debt or equity financing
will be available. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources."
VOLATILITY OF NATURAL GAS AND OIL PRICES
The revenues generated by the Company's operations are highly
dependent upon the prices of, and demand for, natural gas and, to a lesser
extent, the price of oil. Historically, the prices of oil and natural gas
have been volatile and are likely to continue to be volatile in the future
and are dependent upon numerous factors such as weather, domestic and foreign
political and economic conditions, the overall level of international and
domestic demand for oil and natural gas, domestic and international
regulatory developments, domestic and international severance and excise
taxes, competition from other sources of energy and the availability of
pipeline capacity. The Company is affected more by fluctuations in natural
gas prices than oil prices, because the majority of its production is natural
gas. The volatile nature of the energy markets and the unpredictability of
actions of OPEC members make it impossible to predict future prices of
natural gas and oil with any certainty. Prices of natural gas and oil are
subject to wide fluctuations in response to relatively minor changes in
circumstances, and there can be no assurance that future prolonged decreases
in such prices will not occur. All of these factors are beyond the control of
the Company. Any significant decline in natural gas and oil prices would have
a material adverse effect on the Company's results of operations and
financial condition, its ability to fund operations and capital expenditures,
the book value of its natural gas and oil properties and its ability to meet
its debt service requirements. Although the Company may enter into hedging
arrangements from time to time to reduce its exposure to price risks in the
sale of its natural gas and oil, substantially all of the Company's
production will remain subject to natural gas and oil price fluctuations.
DEPENDENCE ON DISTRIBUTION AND PROCESSING SYSTEMS
The marketability of the Company's natural gas and oil production
depends upon the availability and capacity of natural gas gathering systems,
pipelines and processing facilities which are not owned by the Company. The
unavailability or lack of capacity thereof could result in the shut-in of
producing wells or the delay or discontinuance of development plans for
properties. Moreover, substantially all of the Company's properties rely on
the same gathering systems, transportation lines and processing plants. In
addition, federal and state regulation of oil and natural gas production and
transportation, general economic conditions and changes in supply and demand
could adversely affect the Company's ability to produce and market its
natural gas and oil on a profitable basis. Any significant change in the
Company's ability to market its production could have a material adverse
effect on the Company's financial condition and results of operations.
CONCENTRATION OF PRODUCING PROPERTIES
The Company's production of natural gas and oil is concentrated
within an approximate 120 square mile area in the Lobo Trend. Any impairment
or material reduction in the expected size of the reserves attributable to
the Company's wells, any material harm to the producing reservoirs from which
these wells produce or any significant governmental regulation with respect
to any of these wells, including curtailment of production or interruption of
transportation of production, could have a material adverse effect on the
Company's financial condition and results of operations.
DRILLING RISKS
The Company's revenues, operating results and future rate of growth
will be dependent upon the success of its drilling program. Oil and natural
gas drilling involves numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be encountered. The timing and
cost of drilling, completing and operating wells is often uncertain, and
drilling
23
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities
in formations, equipment failures or accidents, adverse weather conditions,
compliance with governmental requirements and shortages or delays in the
availability of drilling rigs and the delivery of equipment. Oil and natural
gas drilling remains a speculative activity notwithstanding the Company's use
of 3-D seismic data. Even when fully utilized and properly interpreted, 3-D
seismic data and other advanced technologies only assist geoscientists in
identifying subsurface structures and do not enable the interpreter to know
whether hydrocarbons are in fact present in such structures. In addition, the
use of 3-D seismic data and other advanced technologies requires greater
predrilling expenditures than traditional drilling strategies and the Company
could incur losses as a result of such expenditures. Furthermore, completion
of a well does not assure a profit on the investment or a recovery of any
portion of drilling, completion or operating costs.
Unsuccessful drilling activities could have a material adverse
effect on the Company's results of operations and financial condition. There
can be no assurance that the Company's overall drilling success rate or its
drilling success rate within a particular project area will not decline. The
Company may choose not to acquire option and lease rights prior to acquiring
seismic data and, in many cases, the Company may identify a prospect or
drilling location before seeking option or lease rights in the prospect or
location. Although the Company has identified or budgeted for numerous
drilling prospects, there can be no assurance that such prospects will ever
be leased or drilled (or drilled within the scheduled or budgeted time frame)
or that oil or natural gas will be produced from any such prospects or any
other prospects. In addition, prospects may initially be identified through a
number of methods, some of which do not include interpretation of 3-D or
other seismic data. Actual drilling and results are likely to vary from such
statistical results and such variance may be material. Similarly, the
Company's drilling schedule may vary from its capital budget because of
future uncertainties, including those described above. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
ABILITY AND NEED TO REPLACE RESERVES
The Company's future success depends upon its ability to find,
develop or acquire additional oil and natural gas reserves that are
economically recoverable. Unless the Company successfully replaces the
reserves that it produces through successful development, exploration or
acquisition, the Company's proved reserves will decline. Further,
substantially all of the Company's estimated proved reserves at December 31,
1998 were located in the Lobo Trend, where wells are characterized by high
initial production followed by rapid initial decline rates and a relative
flattening of production thereafter. Additionally, approximately 61.3% of the
PV-10 Value of the Company's total estimated proved undeveloped reserves as
of December 31, 1998 was attributable to undeveloped reserves. Recovery of
such reserves will require significant capital expenditures and successful
drilling operations, and there can be no certainty regarding the results of
developing these reserves. The Company's business strategy is to add reserves
by pursuing an active development drilling program on its properties
(including the properties acquired in the Transactions) and on additional
properties that it may acquire in the future. There can be no assurance that
the Company will drill the number of wells currently projected or that the
production from these new wells will be sufficient to replace production from
existing wells during such period. To the extent the Company is unsuccessful
in replacing or expanding its estimated proved reserves, the Company may be
unable to pay the principal of and interest on the Series B Notes in
accordance with their terms, or otherwise to satisfy certain of its covenants
contained in the Indenture.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
The proved developed and undeveloped oil and natural gas reserve
data presented in this Report are estimates based on reserve reports
prepared by independent petroleum engineers, as well as internally generated
reports by the Company. The estimation of reserves requires substantial
judgment on the part of the petroleum engineers, resulting in imprecise
determinations, particularly with respect to new discoveries. Estimates of
economically recoverable oil and natural gas reserves and of future net
revenues necessarily depend upon a number of variable factors and
assumptions, such as assumed production, which is based in part on an
assessment of historical production from the area compared with production
from other producing areas, the assumed effects of regulations by
governmental agencies and assumptions concerning future oil and natural gas
prices, future operating costs, severance and excise taxes, capital
expenditures and workover and remedial costs, all of which may in fact vary
considerably from actual results. Estimates of reserves and of future net
revenues prepared by different petroleum engineers may vary substantially,
depending, in part, on the assumptions made (including assumptions required
by the SEC), as to oil and natural gas prices, drilling, workover, remedial
and operating expenses, capital expenditures, severance and ad valorem taxes
and availability of funds, and may be subject to material adjustment.
Estimates of proved undeveloped reserve quantities, which comprise 73% of the
Company's total proved reserves as of December 31, 1998, are, by their nature,
24
much less certain than proved developed reserves. The accuracy of any reserve
estimate depends on the quality of available data as well as engineering and
geological interpretation and judgment. Results of drilling, testing and
production or price changes subsequent to the date of the estimate may result
in changes to such estimates. Any significant variance in the assumptions
could materially affect estimates of economically recoverable quantities of
oil and natural gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of
the future net revenues expected therefrom. The estimates of future net
revenues contained herein reflect oil and natural gas prices and production
costs as of the date of estimation, without escalation, except where changes
in prices were fixed under existing contracts. There can be no assurance that
such prices will be realized, estimated production volumes will be produced
or proved undeveloped reserves will be developed during the period specified
in such reports. Either inaccuracies in estimates of proved undeveloped
reserves or the inability to fund development could result in substantially
reduced reserves. In addition, the timing of receipt of estimated future net
revenues from proved undeveloped reserves will be dependent upon the timing
and implementation of drilling and development activities estimated by the
Company for purposes of the reserve report. See "Item 2. Properties--Oil and
Natural Gas Reserves." The estimated reserves and future net revenues may be
subject to material downward or upward revision based upon production
history, results of future development, prevailing oil and natural gas prices
and other factors. A material decrease in estimated reserves or future net
revenues could have a material adverse effect on the Company's financial
condition and results of operations.
In addition, the PV-10 Value of the Company's proved oil and natural
gas reserves does not necessarily represent the current or fair market value
of such proved reserves, and the 10% discount rate required by the SEC may
not reflect current interest rates, the Company's cost of capital or any
risks associated with the development and production of the Company's proved
oil and natural gas reserves. In accordance with applicable SEC requirements,
proved reserves and the future net revenues from which PV-10 Value is derived
are estimated using prices and costs at the date of the estimate held
constant throughout the life of the properties (except to the extent a
contract specifically provides otherwise). The Company emphasizes with
respect to such estimates that the discounted future net cash flows should
not be construed as representative of the fair market value of the proved oil
and natural gas properties belonging to the Company, because discounted
future net cash flows are based upon projected cash flows that do not provide
for changes in oil and natural gas prices or for escalation of expenses and
capital costs. The meaningfulness of such estimates is highly dependent upon
the accuracy of the assumptions upon which they were based. Actual results
may differ materially from the results estimated. The estimated future net
revenues attributable to the Company's proved oil and natural gas reserves
are based on prices in effect at December 31, 1998 ($1.85 per Mcf of natural
gas and $9.17 per Bbl of oil), which may be materially different than actual
future prices. See "Item 2. Properties--Oil and Natural Gas Reserves."
RISKS ASSOCIATED WITH ACQUISITIONS
The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and natural gas prices,
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact. In connection with its
assessment of a potential acquisition, the Company performs a review of the
subject properties that it believes to be generally consistent with industry
practices, including examination of contingencies associated with the
properties. Such a review, however, will not reveal all existing or potential
problems nor will it permit a buyer to become sufficiently familiar with the
properties to fully assess the deficiencies and capabilities of such
properties. Inspections may not always be performed on every well, and
structural and environmental problems are not necessarily observable even
when an inspection is undertaken. Even when problems are identified, the
seller may be unwilling or unable to provide effective contractual protection
against all or part of such problems. There can be no assurance that the
Company will be able to identify attractive acquisition opportunities, obtain
financing for acquisitions on satisfactory terms or successfully acquire
identified targets. Furthermore, there can be no assurance that competition
for acquisition opportunities in these industries will not escalate, thereby
increasing the cost to the Company of making further acquisitions or causing
the Company to refrain from making further acquisitions. In addition, there
can be no assurance that any acquisition of property interests by the Company
will be successful and, if unsuccessful, that such failure will not have a
material adverse effect on the Company's future results of operations and
financial condition. The Company's current inability to borrow to fund its
capital expenditures will, for so long as it continues, adverse affect its
ability to fund its acquisition strategy.
25
OPERATIONAL HAZARDS AND UNINSURED RISKS
Oil and natural gas drilling activities are subject to numerous
risks, many of which are beyond the Company's control, including the risk
that no commercially productive oil or natural gas reservoirs will be
encountered. The cost of drilling, completing and operating wells is often
uncertain, and drilling operations may be curtailed, delayed or canceled as a
result of a variety of factors, including unexpected drilling conditions,
pressure irregularities information, equipment failures or accidents, adverse
weather conditions, title problems and shortages or delays in the delivery of
equipment. The Company's future drilling activities may not be successful
and, if unsuccessful, such failure will have an adverse effect on future
results of operations and financial condition.
In addition, oil and natural gas operations involve hazards such as
fire, explosion, blowout, pipe failure, casing collapse, unusual or
unexpected formation pressures and environmental hazards such as oil spills,
gas leaks, ruptures and discharges of toxic gases, the occurrence of any one
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, cleanup
responsibilities, regulatory investigation and penalties and suspension of
operations. Although the Company maintains insurance against certain risks
that it believes are customarily insured against by companies in the industry
of comparable size and scope of operations, such insurance does not cover all
of the risks and hazards involved in oil and natural gas exploration,
drilling and production because insurance is unavailable at economic rates,
there are limitations in the Company's insurance policies or for other
reasons. Even if coverage does exist, it may not be sufficient to pay the
full amount of liabilities incurred, and there can be no assurance that such
insurance will continue to be available on terms acceptable to the Company.
Any uninsured loss could have a material adverse effect on the Company's
financial condition and results of operations.
COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY
The Company encounters competition from other oil and natural gas
companies in all areas of its operations, including the acquisition of
exploratory prospects and proven properties. Properties within the Lobo Trend
are characterized by large tracts (typically 5,000 to 50,000 acres) that have
been owned by the same families for generations. Securing leases or necessary
permits and approvals for 3-D seismic shoots depends heavily on developing
and maintaining favorable relationships with the surface owners. The
Company's competitors, particularly in the Lobo Trend, include major
integrated oil and natural gas companies and independent oil and natural gas
companies, individuals and drilling and income programs. Most of its
competitors are large, well-established companies with substantially larger
operating staffs and significantly greater capital resources than those of
the Company and which, in many instances, have been engaged in the oil and
natural gas business for a much longer time than the Company. Such companies
may be able to pay more for exploratory prospects and productive oil and
natural gas properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than could the Company,
given its limited financial and human resources. There can be no assurance
that the Company will be able to secure the necessary financing or industry
partners or evaluate and select suitable properties and consummate
transactions in this highly competitive environment. See "Item 1. Business--
Competition."
PROPERTY IMPAIRMENT CHARGES
Effective January 1, 1996, the Company adopted Statement of
Financial Accounting Standards ("SFAS") No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
which requires that long-lived assets held and used by an entity be reviewed
for impairment whenever events or changes indicate that the net book value of
an asset may not be recoverable. The net book value of an asset is reduced to
fair value if the sum of expected undiscounted future net cash flows from the
use of the asset is less than the net book value of the asset. Under SFAS No.
121 the Company evaluates impairment of oil and natural gas properties on a
field basis. Applying SFAS No. 121, the Company recognized non-cash property
impairment charges of $5.4 million, $238,000 and $156,000 as of December 31,
1998, 1997 and 1996, respectively. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations--Results of
Operations." Significant declines in oil or natural gas prices or downward
revisions of reserve estimates could adversely impact the Company's estimates
of future net revenues from its proved reserves and consequently could result
in future non-cash impairment charges against the Company's results of
operations.
DEPENDENCE OF KEY PERSONNEL
The Company is dependent upon the efforts and skills of key
executives of the Company, including Glenn D. Hart, Chairman of the Board and
Chief Executive Officer, Michael G. Farmar, President and Chief Operating
Officer,
26
and Jerry F. Holditch, Vice President-Exploration. The loss of any of these
officers or other key personnel could have a material adverse effect on the
Company. Further, as the Company grows its asset base and scope of operations
as a result of the Transactions and other future acquisitions, its future
profitability will depend upon the Company's ability to attract and retain
additional qualified personnel.
CONTROL BY CERTAIN SHAREHOLDERS
The Company is a wholly-owned subsidiary of MHI, which in turn is
principally owned by the management of the Company and MHI. Four of the
Company's directors, three of whom are also executive officers of the
Company, beneficially owned 701,550 shares of common stock of MHI (the
"Common Stock") representing, in the aggregate, approximately 91% of the
outstanding Common Stock. Such owners, should they act together, would have
sufficient voting power to (i) elect the entire Boards of Directors of the
Company and MHI, (ii) exercise control over the business, policies and
affairs of the Company and MHI and (iii) in general, determine the outcome of
any corporate transaction or other matters submitted to the stockholders for
approval such as (a) any amendment to the Company's Articles of
Incorporation, (b) the authorization of additional shares of capital stock
and (c) any merger, consolidation or sale of all or substantially all of the
assets of the Company which could prevent or cause a change of control of the
Company.
REGULATORY AND ENVIRONMENTAL RISKS
Oil and natural gas operations are subject to various federal, state
and local governmental regulations which may be changed from time to time in
response to economic or political conditions. From time to time, regulatory
agencies have imposed price controls and limitations on production in order
to conserve supplies of oil and natural gas. In addition, the production,
handling, storage, transportation and disposal of oil and natural gas,
byproducts thereof and other substances and materials produced or used in
connection with oil and natural gas operations are subject to regulation
under federal, state and local laws and regulations.
The Company's operations currently are located primarily in Texas.
Thus, the Company's business is subject to environmental regulation on the
state level primarily by the Railroad Commission of Texas and the Texas
Natural Resource Conservation Commission. The Railroad Commission of Texas
regulations may require on the Company to obtain permits and drilling bonds
for the drilling of wells. Additionally, the Railroad Commission of Texas
regulates the spacing of wells, plugging and abandonment of such wells and
the remediation of contamination caused by most types of exploration and
production wastes. The Railroad Commission requirements for remediation of
contamination are, for the most part, administered on a case-by-case basis.
The Company expects that such regulations will be formalized in the future
and will in all likelihood become more stringent.
Currently, federal regulations provide that drilling fluids,
produced waters and other wastes associated with the exploration, development
or production of oil and natural gas are exempt from regulation as "hazardous
waste." To the extent that the Company's operations produce wastes that do
not fall within this exemption, the storage, handling and disposal of those
wastes are regulated on the state level by the Texas Natural Resource
Conservation Commission. From time to time, legislation has been proposed to
eliminate or modify this exemption. Should the exemption be modified or
eliminated, wastes associated with oil and natural gas exploration and
production would be subject to more stringent regulation. On the federal
level, the Company's operations may be subject to various federal statutes,
including the Natural Gas Act, the Comprehensive Environmental Response,
Compensation the Liability Act, the Solid Waste Disposal Act, as amended by
the Resource Conservation and Recovery Act, the Clean Air Act, the Federal
Water Pollution Control Act and the Oil Pollution Act, as well as by
regulations promulgated pursuant to these actions.
These regulations subject the Company to increased operating costs
and potential liability associated with the use and disposal of hazardous
materials. Although these laws and regulations have not had a material
adverse effect on the Company's financial condition or results of operations,
there can be no assurance that the Company will not be required to make
material expenditures in the future. Moreover, the Company anticipates that
such laws and regulations will become increasingly stringent in the future,
which could lead to material costs for environmental compliance and
remediation by the Company.
Any failure by the Company to obtain required permits for, control
the use of, or adequately restrict the discharge of hazardous substances
under present or future regulations could subject the Company to substantial
27
liability or could cause its operations to be suspended. Such liability or
suspension of operations could have a material adverse effect on the
Company's business, financial condition and results of operations.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1998, the FASB issued SFAS No. 133, ACCOUNTING FOR
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, which is effective for fiscal
years beginning after June 15, 1999. SFAS No. 133 establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It also
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those items at
fair value. If certain conditions are met, a derivative may be specifically
designated as (a) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (b) a hedge
of the exposure to variable cash flows of a forecasted transaction, or (c) a
hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security,
or a foreign-currency-denominated forecasted transaction. As discussed in
Note 5 to the Financial Statements, the Company has historically hedged a
portion of its future gas production using gas swap contracts. These
contracts are a hedge of the Company's exposure to the variability of future
cash flows due to potential decreases in gas prices. For a derivative
designated as hedging the exposure to variable cash flows of a forecasted
transaction (referred to as a cash flow hedge), the effective portion of the
derivative gain or loss is initially reported as a component of other
comprehensive income (outside earnings) and subsequently reclassified into
earnings when the forecasted transaction affects earnings. The ineffective
portion of the gain or loss is reported in earnings immediately. The extent
of the impact of adopting SFAS No. 133 on the Company's consolidated
financial position, results of operations, or cash flows will be a function
of the open derivative contracts at the date of adoption. As of December 31,
1998, the Company can not estimate the impact of SFAS 133 on the consolidated
financial position, results of operations or cash flows.
28
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEDGING ACTIVITIES
From time to time, the Company has utilized hedging transactions
including swaps, put options and costless collars, with respect to a portion
of its oil and natural gas production to achieve a more predictable cash
flow, as well as to reduce exposure to price fluctuations. While the use of
these hedging arrangements limits the downside risk of adverse price
movements, they may also limit future revenues from favorable price
movements. The use of hedging transactions also involves risk that the
counterparties will be unable to meet the financial terms of such
transactions. All of the Company's hedging transactions to date were carried
out in the over-the-counter market and the obligations of the counterparties
have been guaranteed by entities with at lest an investment grade rating or
secured by letters of credit. The Company accounts for these transactions as
hedging activities and, accordingly, gains or losses are included in oil and
gas revenues when the hedged production is delivered. Neither the hedging
contracts nor the unrealized gains or losses on these contracts are
recognized in the financial statements. In addition, if the Company's
reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, or otherwise, the Company would be required to
satisfy its obligations under potentially unfavorable terms. The Company may
be at a risk for basis differential, which is the difference in the quoted
financial price for contract settlement and the actual physical point of
delivery price. Substantial variations between the assumptions and estimates
used by the Company in its hedging activities and actual results experienced
could materially adversely affect the Company's financial condition and its
ability to manage risk associated with fluctuations in oil and natural gas
prices.
The annual average oil and natural gas prices received by the
Company have fluctuated significantly over the past three years.
Approximately 54%, 72% and 48% of the Company's production was hedged during
the years ended December 31, 1996, 1997 and 1998, respectively. The Company's
weighted average natural gas price received per Mcf (including the effects of
hedging transactions) was $2.15, $2.33 and $2.07 during the years ended
December 31, 1996, 1997 and 1998, respectively. Hedging transactions resulted
in a ($0.24), ($0.32) and $0.01 (reduction) increase in the Company's
weighted average natural gas price received per Mcf in 1996, 1997 and 1998,
respectively. The fair value of these hedging contracts was $(1.1 million),
$(1.1 million) and $2.1 million as of December 31, 1996, 1997, and 1998,
respectively.
As of December 31, 1998, the Company had entered into commodity
price hedging contracts with respect to its gas production for 1999 and 2000
as follows:
PRICE PER MMbtu
------------------------------------------------
COLLAR
VOLUME IN -------------------------------
PERIOD MMbtu FLOOR CEILING STRIKE PRICE
- ------------------------- --------- ------------- ------------- ------------
Jan 1999 - Dec 1999
Put option 600,000 $2.25
Costless collar 1,800,000 $2.25 $2.99
Costless collar 1,800,000 $2.00 $2.22
Costless collar 2,400,000 $2.15 $2.38
Costless collar 1,800,000 $1.98 $2.22
Costless collar 1,200,000 $2.15 $2.36
Jan 2000 - April 2000
Costless collar 600,000 $2.00 $2.22
Costless collar 1,200,000 $2.15 $2.38
Costless collar 600,000 $1.98 $2.22
Costless collar 600,000 $2.15 $2.36
These hedging transactions are settled based on settlement prices
relative to a Houston Ship Channel Index. With respect to any particular
costless collar transaction, the counterparty is required to make a payment
to the Company if the settlement price for any settlement period is below the
floor price for such transaction, and the Company is required to make payment
to the counterparty if the settlement price for any settlement period is
above the ceiling price for such transaction. For put options, the
counterparty is required to make payment to the Company if the settlement
price for any settlement period is below the strike price for such
transaction. The Company is not required to make any payment in connection
with the settlement of put options. The premium paid by the Company for the
put option was approximately $229,500. As of December 31, 1998, approximately
$76,500 remains unamortized.
The borrowings under the Credit Facility and the value of the $135 million
Series B Notes are subject to market fluctuations as influenced by certain
economic factors and events. The interest rate for borrowings under the
Credit Facility are determined at one of two floating interest rates (ABR
rate or Eurodollar rate) plus 0.5% to 2.25% at the election of the Company.
Thus, the fair value of the Credit Facility approximates its market value.
The fair value of the $135 million Series B Notes was approximately $120
million at December 31, 1998 and the effective interest rate was 12.04%.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Accountants.......................................... 31
Consolidated Balance Sheets................................................ 32
Consolidated Statement of Operations....................................... 33
Consolidated Statement of Stockholder's Deficit............................ 34
Consolidated Statement of Cash Flows....................................... 35
Notes to Consolidated Financial Statements................................. 36
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Michael Petroleum Corporation:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, stockholder's deficit, and cash flows
present fairly, in all material respects, the financial position of Michael
Petroleum Corporation at December 31, 1998 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 31, 1999
31
MICHAEL PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands of dollars, except share data)
DECEMBER 31,
----------------------
1997 1998
------- --------
ASSETS
Current assets:
Cash and cash equivalents $ 782 $ 430
Receivables:
Accrued oil and gas sales 3,991 5,362
Joint interest and other 481 1,004
Note receivable -- 1,500
Prepaid expenses and other 1 655
------- --------
Total current assets 5,255 8,951
Oil and gas properties (successful efforts method), at cost 34,977 155,867
Less: accumulated depletion, depreciation and amortization (6,966) (24,989)
------- --------
28,011 130,878
Deferred income taxes 1,876
Other assets 351 5,577
------- --------
Total assets $33,617 $147,282
======= ========
LIABILITIES AND STOCKHOLDER'S DEFICIT
Current liabilities:
Accounts payable:
Trade $ 3,746 $ 7,202
Revenue distribution 1,756 1,723
Accrued interest 263 4,076
Accrued liabilities 35 554
Current portion of long-term debt 8,056 41
------- --------
Total current liabilities 13,856 13,596
Long-term debt 19,885 144,842
Deferred income taxes 1,791 --
------- --------
Total liabilities 35,532 158,438
Commitments and contingencies (Note 10)
Stockholder's deficit:
Preferred stock ($.10 par value, 50,000,000 shares authorized,
no shares issued)
Common stock ($.10 par value, 100,000,000 shares authorized,
10,000 shares issued and outstanding) 1 1
Additional paid-in capital 610 610
Accumulated deficit (2,526) (11,767)
------- --------
Total stockholder's deficit (1,915) (11,156)
------- --------
Total liabilities and stockholder's deficit $33,617 $147,282
======= ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
32
MICHAEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands of dollars)
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1997 1998
------- ------- --------
Revenues:
Oil and natural gas sales $ 3,594 $ 9,139 $ 22,668
Gain on sale of oil and natural gas properties 182 - 50
------- ------- --------
3,776 9,139 22,718
------- ------- --------
Operating expenses:
Production costs 1,931 1,870 4,118
Depletion, depreciation and amortization 1,024 3,651 12,620
Impairment of oil and natural gas properties 156 238 5,424
Exploration 46 333 85
General and administrative 424 980 1,802
------- ------- --------
3,581 7,072 24,049
------- ------- --------
Operating income (loss) 195 2,067 (1,331)
------- ------- --------
Other income (expense):
Interest income and other 30 46 235
Interest expense and other (924) (2,109) (12,281)
------- ------- --------
(894) (2,063) (12,046)
(Loss) income before income taxes and extraordinary item (699) 4 (13,377)
Provision (benefit) for income taxes 1,780 11 (4,667)
------- ------- --------
Loss before extraordinary item (2,479) (7) (8,710)
Extraordinary item - extinguishment of T.E.P. Financing,
net of tax of $285 - - (531)
------- ------- --------
Net loss $(2,479) $ (7) $ (9,241)
======= ======= ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
33
MICHAEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDER'S DEFICIT
For the years ended December 31, 1996, 1997 and 1998
(In thousands of dollars, except per share data)
COMMON STOCK
----------------- ADDITIONAL
PAID-IN ACCUMULATED
SHARES AMOUNT CAPITAL DEFICIT TOTAL
------ ------ ---------- ----------- --------
Balance, December 31, 1995 10 $1 $455 $ (31) $ 425
Dividend to MHI (9) (9)
Issuance of warrants in conjunction with T.E.P.
Financing 155 155
Net loss (2,479) (2,479)
---- --- ---- -------- --------
Balance, December 31, 1996 10 $1 610 (2,519) (1,908)
Net loss (7) (7)
---- --- ---- -------- --------
Balance, December 31, 1997 10 $1 610 (2,526) (1,915)
Net loss (9,241) (9,241)
---- --- ---- -------- --------
Balance December 31, 1998 10 $1 $610 $(11,767) $(11,156)
==== === ==== ======== ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
34
MICHAEL PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands of dollars)
YEAR ENDED DECEMBER 31,
------------------------------------
1996 1997 1998
-------- -------- ---------
Cash flows from operating activities:
Net loss $ (2,479) $ (7) $ (9,241)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depletion, depreciation and amortization 1,024 3,651 12,620
Impairment of oil and natural gas properties 156 238 5,424
Deferred income taxes 1,780 11 (4,952)
Extraordinary item - extinguishment of T.E.P.
Financing, net of taxes -- -- 470
Gain on sale of oil and gas properties (182) -- (50)
Abandonment of oil and gas properties -- 249 35
Amortization of debt and bond issuance costs -- -- 619
Amortization of deferred loss on early termination of
commodity swap agreement -- -- 712
Amortization of discount on debt 43 131 205
Changes in assets and liabilities:
Accounts receivable - accrued oil and gas sales (1,189) (2,333) (1,370)
Accounts receivable - joint interest and other (682) 562 (514)
Prepaid expenses and other 2 72 (1,236)
Accounts payable - trade 1,350 710 (1,769)
Accounts payable - revenue distribution 846 296 (32)
Accrued interest 73 (121) 3,813
Accrued liabilities 106 7 518
-------- -------- ---------
Net cash provided by operating activities 848 3,466 5,252
-------- -------- ---------
Cash flows from investing activities:
Additions to oil and gas properties (14,981) (14,963) (114,978)
Proceeds from sale of oil and gas properties 228 -- 150
Issuance of note receivable -- -- (1,500)
-------- -------- ---------
Net cash used in investing activities (14,753) (14,963) (116,328)
-------- -------- ---------
Cash flows from financing activities:
Proceeds from long-term debt 17,329 14,238 145,603
Payments on long-term debt (2,130) (3,114) (29,314)
Dividend to MHI (9) -- --
Additions to deferred loan costs (440) (26) (5,565)
-------- -------- ---------
Net cash provided by financing activities 14,750 11,098 110,724
Net increase (decrease) in cash and cash equivalents 845 (399) (352)
Cash and cash equivalents, beginning of period 336 1,181 782
-------- -------- ---------
Cash and cash equivalents, end of period $ 1,181 $ 782 $ 430
======== ======== =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
35
MICHAEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Michael Petroleum Corporation and Subsidiaries (the "Company" or "MPC") is
engaged in the acquisition, exploration and development of oil and natural
gas properties principally located in the Lobo Trend of South Texas. The
Company was incorporated in June 1982. The Company, which was owned by the
stockholders of Michael Holdings, Inc. ("MHI"), became a wholly-owned
subsidiary of MHI on July 1, 1996 in a transaction accounted for at
historical cost as a reorganization of entities under common control.
On March 25, 1998, the Company was merged with and into Michael Gas
Production Company ("MGPC"), which was also a wholly-owned subsidiary of
MHI. Following the merger, MGPC changed its name to MPC. This transaction
was accounted for at historical cost as a reorganization of entities under
common control. The consolidated financial statements reflect the financial
position, results of operations and cash flows of the combined companies
for all periods presented as if the merger had occurred on December 31,
1995. The consolidated financial statements contain the accounts of the
Company after elimination of all significant intercompany balances and
transactions.
As an independent oil and gas producer, the Company's revenue,
profitability and future rate of growth are substantially dependent upon
prevailing prices for natural gas, oil and condensate, which are
dependent upon numerous factors beyond the Company's control, such as
economic, political and regulatory developments and competition from
other sources of energy. The energy markets have historically been very
volatile, as evidenced by the recent volatility of oil and gas prices,
and there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future. A substantial or extended
decline in oil and gas prices could have a material adverse effect on
the Company's consolidated financial position, results of operations,
cash flows, quantities of oil and gas reserves that may be economically
produced and access to capital. Natural gas approximates 87% and 97% of
the Company's proved reserves at December 31, 1998 and 1997,
respectively.
CASH AND CASH EQUIVALENTS
Cash equivalents consist of short-term highly liquid investments that have
an original maturity of three months or less. The Company maintains its
cash with two financial institutions. The Company periodically assesses the
financial condition of the institutions and believes that any possible
credit risk is minimal.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are
capitalized when incurred, pending determination of whether the well has
found proved reserves. If an exploratory well has not found proved
reserves, the costs of drilling the well are charged to expense. The costs
of development wells are capitalized whether productive or nonproductive.
Geological and geophysical costs on exploratory prospects and the costs of
carrying and retaining unproved properties are expensed as incurred. An
impairment allowance is provided to the extent that capitalized costs of
unproved properties, on a property-by-property basis, are considered to be
not realizable.
Depletion, depreciation and amortization ("DD&A") of development costs and
acquisition costs of proved oil and gas properties is provided using the
units-of-production method based on proved developed reserves and proved
reserves, respectively. The computation of DD&A takes into consideration
restoration, dismantlement and abandonment costs and the anticipated
proceeds from equipment salvage. The estimated restoration, dismantlement
and abandonment costs are expected to be offset by the estimated residual
value of lease and well equipment.
Gains and losses are recognized on sales of entire interests in proved and
unproved properties. Sales of partial interests are generally treated as
recoveries of costs.
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
IMPAIRMENT OF OIL AND GAS PROPERTIES
The net book value of an asset is reduced to fair value if the sum of
expected undiscounted future net cash flows from the use of the asset is
less than the net book value of the asset. The Company evaluates impairment
of its oil and gas properties on a field basis. The Company makes a
determination of any market changes or performs a periodic review of all
fields each year.
NATURAL GAS BALANCING
The Company incurs natural gas production volume imbalances in the ordinary
course of business on jointly owned properties. The Company follows the
sales method to account for such imbalances. Under this method, revenue is
recorded based on the Company's net revenue interest in production taken
for delivery. The Company records a liability if its sales of gas volumes
in excess of its entitlements from a jointly owned reservoir exceed its
interest in the remaining estimated natural gas reserves of such reservoir.
Volumetric production is monitored to minimize imbalances, and such
imbalances were not significant at December 31, 1997 and 1998.
OTHER ASSETS
Other assets include loan origination costs which are amortized on a
straight-line basis over the term of the related obligation.
INCOME TAXES
Through June 30, 1996, the Company was taxed under the provisions of
"Subchapter S" of the Internal Revenue Code, which provides that the
individual shareholders are liable for federal income taxes on the
Company's taxable income. Accordingly, no provision for federal income
taxes is reflected in the consolidated statement of operations for
periods ending prior to June 30, 1996. Effective July 1, 1996, the
Company began filing a consolidated federal income tax return with MHI.
Deferred income taxes are provided to reflect the tax consequences in
future years of differences between the financial statement and tax bases
of assets and liabilities. Tax credits are accounted for under the
flow-through method, which reduces the provision for income taxes in the
year the tax credits are earned. A valuation allowance is established to
reduce deferred tax assets if it is more likely than not that the related
tax benefits will not be realized. The Company calculates current and
deferred taxes on an individual company basis.
STOCK-BASED COMPENSATION
Statement of Financial Accounting Standards No. 123, ACCOUNTING FOR
STOCK-BASED COMPENSATION, encourages, but does not require companies to
record compensation cost for stock-based employee compensation plans at
fair value. The Company has chosen to continue to apply Accounting
Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES,
and related interpretations to account for stock-based compensation.
Accordingly, compensation cost for stock options is measured as the excess,
if any, of the quoted market price of the Company's stock at the date of
the grant over the amount an employee must pay to acquire the stock.
PRICE RISK MANAGEMENT ACTIVITIES
The Company periodically uses swaps, put options and costless collars to
hedge or otherwise reduce the impact of natural gas price fluctuations.
Gains and losses resulting from changes in the market value of the
financial instruments utilized as hedges are deferred and recognized in
the statement of operations, together with the gain or loss on the hedged
transaction, as the physical production is sold under the relevant
contracts. Cash flows resulting from the Company's risk management
activities are classified in the accompanying statement of cash flows
in the same category as the item being hedged.
These instruments are measured for effectiveness on an enterprise basis
both at the inception of the contract and on an ongoing basis. If these
instruments are terminated prior to maturity, resulting gains or losses
continue to be deferred until the hedged item is recognized in income.
In connection with these hedging transactions, the Company may be exposed
to nonperformance by other parties to such agreements, thereby subjecting
the Company to current natural gas prices. However, the Company only enters
into hedging contracts with large financial institutions and does not
anticipate nonperformance.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's receivables are within the oil and gas
industry, primarily from purchasers of oil and gas and joint venture
participants. Collectibility is dependent upon the general economic
conditions of the purchasers and the oil and gas industry. The receivables
are not collateralized and to date, the Company has had minimal bad debts.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts reported in the balance sheet for cash and cash
equivalents, receivables, and accounts payable approximate their fair
value. The fair value of the Company's long-term debt and derivative
financial instruments are estimated using current market quotes.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities
and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. The Company's most significant estimates
relate to the assessment of impairment of proved and unproved oil and
gas properties, depreciation, depletion, and amortization expense,
proved oil and gas reserves and utilization of deferred tax assets.
Actual results could differ from these estimates.
2. OIL AND GAS PROPERTY TRANSACTIONS:
In August 1996, the Company acquired certain oil and natural gas
properties in Webb County and Zapata County, Texas (the "1996
Acquisition") for approximately $11.8 million. As a result, unaudited
pro forma revenues and income from continuing operations for the year
ended December 31, 1996 were $8,730,000 (unaudited) and $2,497,000
(unaudited), respectively.
In March 1998, the Company completed the acquisition of interests in
certain oil and natural gas properties in Webb County, Hildago County
and Zapata County, Texas, and certain related seismic data from Enron
Oil & Gas Company (the "Enron Acquisition") for $45.8 million.
In April 1998, the Company completed the acquisition of certain oil and
natural gas leases in Webb County, Texas, from Conoco Inc. (the "Conoco
Acquisition") for $22.5 million.
In April 1998, the Company entered into a lease with Mobil effective as of
January 1, 1998 in the Lobo Trend (the "Lobo Lease"). Consideration for the
Lobo Lease is in the form of future deliveries of 4 Bcf of gas, which
commenced May 1, 1998 and terminated December 31, 1998. On April 23, 1998,
the Company entered into a contract to secure delivery of this volume of
gas for consideration of $9.98 million.
The following pro forma data presents the results of the Company for the
years ended December 31, 1997 and 1998, as if the acquisitions of the Lobo
Lease, the Conoco Acquisition and the Enron Acquisition had occurred on
January 1, 1997. The pro forma results of operations are presented for
comparative purposes only and are not necessarily indicative of results
which would have been obtained had the acquisitions been consummated as
presented. The following data reflect pro forma adjustments for oil and
natural gas revenues, production costs, depreciation, and depletion related
to the properties acquired, interest on borrowed funds, and related income
tax effects (in thousands):
YEAR ENDED DECEMBER 31,
-------------------------
1997 1998
------- -------
(UNAUDITED)
Pro forma:
Revenues $31,209 $26,563
Loss from continuing operations (1,465) (9,375)
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. LONG-TERM DEBT:
Long-term debt consisted of the following (in thousands):
DECEMBER 31,
---------------------------
1997 1998
-------- --------
11 1/2% Senior Notes due 2005 - $135,000
Credit Facility - 12,000
Notes payable under the comprehensive credit agreement $ 28,266 -
Installment notes to financial institutions, payable monthly, interest at rates
ranging from 3.9% to 11.26%, due April 1996 to September 2001, collateralized
by vehicles and office equipment 139 65
Note payable to an individual, payable monthly, interest at 8%, due February 2000,
unsecured 17 9
-------- --------
28,422 147,074
-------- --------
Unamortized original issue discount on Senior Notes (2,191)
Unamortized discount on note payable under comprehensive credit agreement (481) -
-------- --------
Total long-term debt 27,941 144,883
-------- --------
Less: current portion (8,056) (41)
-------- --------
Long-term debt $19,885 $144,842
======== ========
Estimated annual principal payments at December 31, 1998 are as follows
(in thousands):
1999 $ 41
2000 25
2001 8
2002 12,000
2003 -
Thereafter 135,000
--------
$147,074
========
SENIOR NOTES
On April 2, 1998, the Company issued $135 million of Senior Notes at a
discount of 1.751%. The Senior Notes mature in April 2005 and bear
interest at a rate of approximately 11.5% per annum, payable
semi-annually in April and October of each year, commencing October
1998. The effective interest rate under the Senior Notes for the year
ended December 31, 1998 was 12.04%. Bond discount costs are amortized on
the interest method over the term of the Senior Notes. The Senior Notes
are redeemable at the option of the Company, in whole or in part, at any
time after April 2003, at specified redemption prices plus accrued and
unpaid interest and liquidated damages, as defined. In the event of
certain asset dispositions, the Company is required under certain
circumstances to use the excess proceeds from such a disposition to
offer to repurchase the Senior Notes (and other Senior Indebtedness for
which an offer to repurchase is required to be concurrently made). The
Company is required to comply with certain covenants, which limit, among
other things, the ability of the Company to incur additional
indebtedness, pay dividends, repurchase equity interests, sell assets or
enter into mergers and consolidations. The fair value of the Senior
Notes was $120 million at December 31, 1998.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
T.E.P. FINANCING
On August 13, 1996, the Company entered into a comprehensive credit
agreement (the "T.E.P. Financing") with a limited partnership. Under the
T.E.P. Financing, total available credit amounted to approximately $42.2
million, of which $16.3 million was available for oil and gas property
acquisitions and $25.9 million for development costs.
The Company utilized loan proceeds of approximately $14.9 million to
acquire proved oil and gas properties located in South Texas the 1996
Acquisition. Through 1997, loan proceeds of approximately $11.8 million
had been used to develop those properties. In conjunction with entering
into the T.E.P. Financing, the Company conveyed to an affiliate of the
lender a net profits interest in all of the Company's oil and gas
properties, including the acquired properties ("Net Profits Interest").
The Net Profits Interest granted the affiliate 30% of the net profits,
as defined, beginning the earlier of August 12, 2001, or the date of
repayment of all amounts due and owing pursuant to the T.E.P. Financing.
The Net Profits Interest decreased to 15% of the net profits, as
defined, after payment of $10 million. As part of the T.E.P. Financing,
the Company also granted to the lender a warrant to purchase up to five
percent of MHI's common stock at an exercise price of $8 per share until
August 12, 2001. The value assigned to the Net Profits Interest and
warrant was recorded as a discount to the loan proceeds.
Under the terms of the T.E.P. Financing, principal was payable as a
percentage of net revenue, as defined. As of December 31, 1997, the
Company had repaid approximately $2.9 million of principal under the
T.E.P. Financing. Interest was payable monthly and accrued at a
combination of LIBOR plus 4.5% and New York prime plus certain basis
points based on the specific borrowing. At December 31, 1997, the
blended effective interest rate accruing on the loans was 15% per annum.
The loan was collateralized by the oil and gas properties and the stock
of the Company.
The T.E.P. Financing contained financial covenants, the most restrictive of
which pertained to the payment of dividends, distributions to shareholders
and the Company's working capital ratio. The T.E.P. Financing also
contained administrative covenants. Except for violations of certain
administrative covenants during the year ended December 31, 1997, the
Company was in compliance with the covenants of the T.E.P. Financing.
Regarding the violations of such administrative covenants, the Company
obtained a waiver from the lender of the T.E.P. Financing which agreed not
to assert any default based upon such violations unless they existed after
April 15, 1998.
On April 2, 1998, a portion of the proceeds from the sale of the Senior
Notes was used to pay outstanding borrowings under the T.E.P. Financing
amounting to approximately $28 million and repurchase the Net Profits
Interest for $11 million. On April 2, 1998, the T.E.P. Financing was
extinguished, and the unamortized balance of the notes payable discount,
the deferred debt issuance costs and certain fees incurred at closing were
written off and reflected in the income statement as an extraordinary loss,
net of taxes. The effective interest rate accruing on the loans through the
date of extinguishment in 1998 was 12.8%.
CREDIT FACILITY
In May 1998, the Company entered into a four-year credit facility with
Christiania Bank og KreditKasse ("Christiania") as lender and
administrative agent, pursuant to the terms of that certain Credit
Agreement dated effective as of May 15, 1998 (the "Credit Facility").
The Credit Facility provides for loans in an outstanding principal
amount not to exceed $50.0 million at any one time, subject to a
borrowing base to be determined semi-annually by the administrative
agent (the initial borrowing base was $30.0 million), and the issuance
of letters of credit in an outstanding face amount not to exceed $6.0
million at any one time with the face amount of all outstanding letters
of credit reducing, dollar-for-dollar, the availability of loans under
the Credit Facility. The initial borrowing base was increased by $5
million to a total of $35 million. However, effective April 1, 1999, the
borrowing base was reduced to $23 million. Under the Credit Facility,
the principal balance outstanding is due and payable on May 28, 2002,
and each letter of credit shall be reimbursable by the Company when
drawn, or if not then otherwise reimbursed, paid pursuant to a loan
under the Credit Facility. Commencing on October 31, 1999, and
continuing until its stated maturity, the maximum amount available for
borrowings and letters of credit under the Credit Facility will not only
be adjusted (increased or decreased, as applicable) by the semi-annual
borrowing base determination, but also (i) decreased by monthly mandatory
reductions in the borrowing base of $1.5
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million per month and (ii) adjusted for sales of collateral having an
aggregate value exceeding the lesser of $4.0 million per year or 5% of the
Company's total proved reserve values. Both the Company and Christiania
may initiate two unscheduled redeterminations of the borrowing base
during any consecutive twelve-month period. No assurance can be given
that the bank will not elect to redetermine the borrowing base in the
future. If the sum of the outstanding principal and letters of credit
(both drawn and undrawn) exceeds the borrowing base, the Company shall,
within 30 days, either repay such excess in full or provide additional
collateral acceptable to Christiania. At March 31, 1999, the Company had
$23 million of outstanding indebtedness under the Credit Facility.
The interest rate for borrowings under the Credit Facility are
determined at either (i) the ABR rate, or (ii) the Eurodollar Rate plus
2.25%, at the election of the Company. The "ABR" rate is the higher of
(i) Christiania Bank's prime rate then in effect plus 0.5%, (ii) the
secondary market rate for three-month certificates of deposit plus 1.5%
or (iii) the federal funds rate then in effect plus 1.0%. The effective
interest rate under the Credit Facility for the year ended December 31,
1998 was 6.8%. Interest is due on a quarterly basis. The Credit Facility
is collateralized by substantially all of the oil and natural gas assets
of the Company, including accounts receivable, equipment and gathering
systems. The proceeds of the Credit Facility may be used to finance
working capital needs and for general corporate purposes of the Company
in the ordinary course of its business.
The Credit Facility contains certain covenants by the Company, including
(i) limitations on additional indebtedness and on guaranties by the
Company except as permitted under the Credit Facility, (ii) limitations
on additional investments except those permitted under the Credit
Facility and (iii) restrictions on dividends or distributions or on
repurchases or redemptions of capital stock by the Company except for
those involving repurchases of MHI capital stock which may not exceed
$500,000 in any fiscal year. The Credit Facility requires the Company to
maintain and comply with certain financial covenants and ratios,
including a minimum interest coverage ratio, a minimum current ratio and
a covenant requiring that the Company's general and administrative
expenses may not exceed 12.5% of the Company's gross revenues in a
calendar year. The Company was in violation of certain administrative
and one financial covenant of the Credit Facility as of December 31, 1998.
The Company has obtained a waiver with respect to those violations, from
the lender of the Credit Facility, which agreed not to assert any default
based upon such violations. The Company and the lender have entered into a
First Amendment to the Credit Facility to amend certain financial covenants
and the effective interest rate under the Credit Facility.
4. FEDERAL INCOME TAXES:
The components of the net deferred taxes are as follows (in thousands):
DECEMBER 31,
-------------------
1997 1998
------- --------
Deferred tax assets:
Net operating loss carryforward $ 3,242 $ 6,613
Other 30 46
------- --------
Total deferred tax asset 3,272 6,659
------- --------
Deferred tax liabilities:
Oil and gas properties (5,063) (4,774)
Other (9)
------- --------
Total deferred tax liability (5,063) (4,783)
------- --------
Net deferred taxes $(1,791) $ 1,876
======= ========
At December 31, 1998, the Company had a net operating loss carryforward
of approximately $19.5 million, which begins expiring in 2017.
Utilization of the net operating loss carryforward is subject to annual
limitations due to certain stock ownership changes that have occurred or
may occur. Realization of deferred tax assets associated with the net
operating loss carryforward is dependent upon generating sufficient
taxable income prior to their expiration. Management believes it is more
likely than not that future taxable income generated will be sufficient
to recover the net operating loss prior to expiration. Estimates of
taxable income are significantly effected by changes in oil and gas
prices, estimates of future production, and estimates of operating and
capital costs. The net deferred tax assets could be reduced in the near
term if management's estimates of taxable income during the carryforward
period are significantly reduced.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income tax expense (benefit) differs from the amount that would be provided
by applying the statutory U.S. federal income tax rate to (loss) income
before income taxes for the following reasons (in thousands):
YEAR ENDED DECEMBER 31,
----------------------------
1996 1997 1998
------ ---- -------
Computed statutory tax (benefit) expense at 34% $ (304) $ 1 $(4,826)
Changes in taxes resulting from:
Section 29 credits (13)
Conversion to C corporation status 2,032
Permanent differences 10 (11)
Other 65 (115)
------ ---- -------
Total income tax expense (benefit) $1,780 $11 $(4,952)
====== ==== =======
5. HEDGING ACTIVITIES:
In an effort to achieve more predictable cash flows and earnings and reduce
the effects of volatility of the price of oil and natural gas on the
Company's operations, the Company has hedged in the past, and in the future
expects to hedge oil and natural gas prices through the use of swaps, put
options and costless collars. While the use of these hedging arrangements
limits the downside-risk of adverse price movements, it also limits future
gains from favorable movements.
The annual average oil and natural gas prices received by the Company
have fluctuated significantly over the past three years. Approximately
54%, 72% and 48% of the Company's production was hedged during the years
ended December 31, 1996, 1997 and 1998, respectively. The Company's
weighted average natural gas price received per Mcf (including the
effects of hedging transactions) was $2.15, $2.33 and $2.07 during the
years ended December 31, 1996, 1997 and 1998, respectively. Hedging
transactions resulted in a ($0.24), ($0.32) and $0.01 increase
(reduction) in the Company's weighted average natural gas price received
per Mcf in 1996, 1997 and 1998, respectively. The unrealized (loss) gain
related the hedging contracts was ($1.1 million), ($1.1 million) and
$2.1 million as of December 31, 1996, 1997, and 1998, respectively.
As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its gas production for 1999 and 2000 as
follows:
PRICE PER MMbtu
------------------------------------------------
COLLAR
VOLUME IN -------------------------------
PERIOD MMbtu FLOOR CEILING STRIKE PRICE
- ------------------------- --------- ------------- ------------- ------------
Jan 1999 - Dec 1999
Put option 600,000 $2.25
Costless collar 1,800,000 $2.25 $2.99
Costless collar 1,800,000 $2.00 $2.22
Costless collar 2,400,000 $2.15 $2.38
Costless collar 1,800,000 $1.98 $2.22
Costless collar 1,200,000 $2.15 $2.36
Jan 2000 - April 2000
Costless collar 600,000 $2.00 $2.22
Costless collar 1,200,000 $2.15 $2.38
Costless collar 600,000 $1.98 $2.22
Costless collar 600,000 $2.15 $2.36
These hedging transactions are settled based on settlement prices
relative to a Houston Ship Channel Index. With respect to any particular
costless collar transaction, the counterparty is required to make a
payment to the Company if the settlement price for any settlement period
is below the floor price for such transaction, and the Company is
required to make payment to the counterparty if the settlement price for
any settlement period is above the ceiling price for such transaction.
For put options, the counterparty is required to make payment to the
Company if the settlement price for any settlement period is below the
strike price for such transaction. The Company is not required to make
any payment in connection with the settlement of put options. The
premium paid by the Company for the option was approximately $229,500.
As of December 31, 1998, approximately $76,500 remains unamortized.
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. EMPLOYEE BENEFIT PLANS:
STOCK OPTIONS
On July 1, 1998, the shareholders of MHI approved the Michael Holdings,
Inc. 1998 Stock Option Plan ("1998 Plan"). The 1998 Plan is available
for grants to substantially all employees and directors of MHI and the
Company. The 1998 Plan is administered by the Compensation Committee of
the Board of Directors of MHI and the Company. A maximum of 194,000 shares
of MHI common stock is available for grant under the 1998 Plan. As of
December 31, 1998, MHI granted, at exercise prices in excess of the fair
market value per share, options covering a total of 73,350 shares to 22
employees and directors of the Company. Options that have been granted
and are outstanding generally expire 10 years from the date of grant and
become exercisable at the rate of 33.33% per year. The following is a
summary of all stock options activity for 1998. The Company did not have
a stock option plan in 1996 and 1997.
NUMBER OF WEIGHTED
SHARES AVERAGE
UNDERLYING EXERCISE
OPTIONS PRICE
---------- --------
Outstanding at December 31, 1997 - -
Granted 73,350 $ 78.35
Exercised - -
Forfeited - -
------ -------
Outstanding at December 31, 1998 73,350 $ 78.35
====== =======
Exercisable at December 31, 1998 - -
====== =======
At December 31, 1998, the Company had an additional 120,650 shares
available for grants of options under the 1998 Plan. If granted, these
additional options will be exercisable at a price not less than the fair
market value per share of the Company's Common Stock on the date of
grant. The weighted average fair value of options granted during 1998
was $18.12.
The fair value of each stock option granted is estimated as of the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions for grants in 1998: no dividend yield;
expected volatility of 0.00%; risk-free interest rates of 5.40% and an
expected option life of 5 years.
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1998:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------------------------------- -----------------------------------
WEIGHTED
AVERAGE
EXERCISE REMAINING
PRICE OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
$ 78.35 73,350 9.52 $ 78.35 - -
Common Stock issued through the exercise of stock options results in a tax
deduction for the Company equivalent to the taxable gain recognized by the
optionee. For financial reporting purposes, the tax effect of this
deduction is accounted for as a credit to additional paid-in capital rather
than as a reduction of income tax expense. There were no exercises of
options as of December 31, 1998.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
If the fair value based method of accounting in Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation"
("SFAS 123") had been applied, the Company's net loss for 1998 would
have approximated the pro forma amount below (in thousands):
YEAR ENDED
DECEMBER 31, 1998
-----------------
Net loss - as reported $ (9,241)
Net loss - pro forma $ (9,380)
The effects of applying SFAS 123 in this pro forma disclosure are not
indicative of future amounts as the Company anticipates making awards in
the future under its stock-based compensation plans.
401(k) PLAN
The Company sponsors a 401(k) profit sharing plan (the "401(k) Plan") under
Section 401(k) of the Internal Revenue Code, which covers all employees of
the Company, subject to eligibility conditions. Effective August 1, 1998,
the Company, began to match $0.50 for each $1.00 of employee deferral, with
the Company's contribution not to exceed 6% of an employee's salary,
subject to limitations imposed by the Internal Revenue Code. The Company's
contributions amounted to approximately $18,000 for the year ended December
31, 1998. The Company did not make any contributions to the 401(k) Plan
during the years ended December 31, 1996 and 1997.
7. RECENT ACCOUNTING PRONOUNCEMENT:
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", ("SFAS 133") which is effective for
fiscal years beginning after June 15, 1999. SFAS 133 establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for
hedging activities. It also requires that an entity recognize all
derivatives as either assets or liabilities in the statement of
financial position and measure those items at fair value. If certain
conditions are met, a derivative may be specifically designated as (a) a
hedge of the exposure to changes in the fair value of a recognized asset
or liability or an unrecognized firm commitment, (b) a hedge of the
exposure to variable cash flows of a forecasted transaction, or (c) a
hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale
security, or a foreign-currency-dominated forecasted transaction. For a
derivative designated as hedging the exposure to variable cash flows of
a forecasted transaction (referenced to as a cash flow hedge), the
effective portion of the derivative gain or loss is initially reported
as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction
affects earnings. The ineffective portion of the gain or loss is
reported in earnings immediately. The extent of the impact of adopting
SFAS 133 on the Company's financial position, results of operations, or
cash flows will be a function of the open derivative contracts at the
date of adoption. As of December 31, 1998, the Company can not estimate
the impact of SFAS 133 on its future consolidated financial position,
results of operations or cash flows.
8. RELATED PARTY TRANSACTIONS AND SIGNIFICANT CONCENTRATIONS:
Beginning in April 1996, the Company entered into an agreement,
continuing thereafter on a quarterly basis subject to termination by
either party, with Upstream Energy Services ("Upstream") whereby
Upstream purchases all of the gas produced by the Company at spot market
prices. The chairman of the board and chief executive officer ("CEO") of
the Company had an ownership interest in Upstream until August 1997.
Upstream executed a promissory note in an aggregate principal amount of
$20,000 payable to the Company's chairman of the board and chief
executive officer in connection with the purchase of his interest.
Interest on the indebtedness accrues at a rate of 8.25% per annum.
Effective November 1, 1998, the Company entered into a new agreement
with Upstream. Under the terms of the agreement, the Company pays
Upstream a marketing fee as follows:
VOLUMETRIC TIER (MMBTU/DAY) MARKETING FEE
--------------------------- -------------
1. First 20,000 $0.03/MMbtu
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. 20,001 to 40,000 $0.02/MMbtu
3. All volumes over 40,000 $0.01/MMbtu
The Sales Agreement is effective for a one-year period and is renewable
quarterly thereafter, subject to either party giving 60 days written notice
of termination.
Marketing fees paid to Upstream were approximately $106,000, $220,000
and $253,000 for the years ended December 31, 1996, 1997 and 1998,
respectively. During the years ended December 31, 1996, 1997 and 1998,
Upstream purchased gas produced by the Company for approximately $3.2
million, $9.7 million and $20.8 million, respectively. At December 31,
1996, 1997 and 1998, receivables from Upstream of approximately $2.1
million, $3.9 million and $5.2 million respectively, were included in
accrued oil and gas sales in the balance sheet. The Company believes the
revenues received were equivalent to those that would be paid under an
arms-length transaction in the normal course of business.
In July 1997, the Company executed in writing a verbal agreement which
had granted to the vice president of geosciences of the Company a 1.5%
of 8/8ths overriding royalty interest in leases acquired either directly
or indirectly by the Company or its affiliates in Webb County or Zapata
County, Texas. This overriding royalty interest expires upon the death
of the vice president or upon his termination, resignation or retirement
from the Company. The overriding royalty interest does not apply to any
producing properties acquired by the Company except for deepenings or
sidetracks of existing wells and/or all new wells drilled on the
acquired producing properties. For the year ended December 31, 1996,
1997 and 1998, the Vice President of geosciences received from the
Company approximately $33,000, $105,000 and $275,000, respectively,
under the overriding royalty interests.
On June 10, 1997, the Chairman of the Board and CEO of the Company,
entered into an agreement with the Company pursuant to which he granted
the Company an option to purchase his undivided two-thirds working
interest in a leasehold interest. The Company exercised this option and
purchased the lease. The leasehold interest expires on May 30, 2000 and
covers approximately 750 acres in Webb County, Texas. The exercise price
of the option was $87,500. In addition, pursuant to the agreement, the
Chairman of the Board and CEO reserved a 1% overriding royalty interest.
In December 1998, the Company loaned $1.5 million to a joint venture
between a Mexican construction company and a Texas limited liability
company that participates in the drilling of natural gas wells for
Petroleos Mexicanos ("Pemex") in the Burgos Basin of Northern Mexico.
The Mexican construction company has a 51% ownership interest in the
joint venture and the Texas limited liability company has a 49%
ownership interest. The note receivable is due December 1999 and bears
interest at 12%. The Company has the option to convert the note
receivable to a 50% equity interest in the Texas limited liability
company.
9. SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for interest are as follows (in thousands):
YEAR ENDED DECEMBER 31,
---------------------------------------
1996 1997 1998
---- ---- ----
Interest payments (net of interest capitalized of $217, $574,
and $1,440 during 1996, 1997, and 1998, respectively) $833 $1,626 $7,677
Non-cash investing and financing transactions not reflected in the
statement of cash flows include the following (in thousands):
YEAR ENDED DECEMBER 31,
1996 1997 1998
---- ---- ----
Changes in accounts payable related to capital expenditures $238 $ 465 $5,225
Increase of oil and gas properties due to recognition of
deferred tax liabilities from acquired properties 1,285
Transfer of oil and gas properties as repayment
Of note payable to a limited partnership 4,791
Adjustment to purchase price of certain oil and gas properties 420
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. COMMITMENTS AND CONTINGENCIES:
LEASES
The Company has entered into a noncancelable operating lease agreement for
office space in Houston, Texas. The lease term expires in 2004, with two
options to renew the lease for a period of five years each. Future minimum
lease payments required as of December 31, 1998 related to noncancelable
operating leases are as follows:
YEAR ENDED DECEMBER 31,
-----------------------
1999 $144,583
2000 144,583
2001 157,075
2002 163,321
2003 114,159
2004 56,011
--------
$779,732
========
Rent expense for the years ended December 31, 1996, 1997 and 1998 was
approximately $50,000, $69,000 and $154,000, respectively.
LEGAL PROCEEDINGS
The Company has been and may in the future be involved as a party in
various legal proceedings, which are incidental to the ordinary course of
business. Management of the Company regularly analyzes current information
and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. In the opinion of management and
legal counsel, as of December 31, 1998, there were no threatened or pending
legal matters which would have a material impact on the Company's
consolidated financial position, results of operations or cash flows.
OTHER MATTERS
In conjunction with the 1996 Acquisition, Conoco (as the successor in
interest to the seller) and the Company entered into a Gas Exchange
Agreement whereby such parties agreed that the Company would deliver to
Conoco all of the natural gas produced from the leases acquired in the
1996 Acquisition at the point(s) at which such gas enters the transmission
pipelines owned by Lobo Pipeline Company ("Lobo Pipeline") (the
"delivery point") in exchange for natural gas in the same quantity and
quality delivered by Conoco at the Agua Dulce hub near Corpus Christi,
Texas. The parties' obligations under the Gas Exchange Agreement are
subject to the natural gas delivered and the pipeline meeting certain
specifications. The title to the Company gas vests in Conoco at the
delivery point, except to the extent such amount exceeds the amount of
redelivered gas at the redelivery point, in which case the Company
retains title and ownership of such excess, which is then transported by
Lobo Pipeline pursuant to an Interruptible Gas Transportation Agreement.
The consideration received by Lobo Pipeline is $0.17 per Mcf for
compression, transportation and dehydration.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES:
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
DECEMBER 31,
----------------------
1997 1998
------- ---------
Unproved oil and gas properties $ 1,247 $ 14,496
Proved oil and gas properties 33,447 140,490
Other 283 881
------- ---------
34,977 155,867
Accumulated depreciation, depletion and amortization (6,966) (24,989)
------- ---------
$28,011 $ 130,878
======= =========
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Costs incurred for oil and gas property acquisition, exploration and
development activities, whether capitalized or expensed, are as follows
(in thousands):
YEAR ENDED DECEMBER 31
------------------------------
1996 1997 1998
------- ------- --------
Property acquisition:
Unproved $ 2,929 $ 355 $ 15,183
Proved 9,554 2,425 78,458
Development 2,757 12,074 25,295
Interest capitalized 217 574 1,440
------- ------- --------
Total costs incurred $15,457 $15,428 $120,376
======= ======= ========
SALES OF OIL AND GAS
Substantially all of the Company's natural gas is sold to one purchaser
(see Note 8). Substantially all of the Company's oil and condensate is sold
to two customers.
OIL AND GAS RESERVE QUANTITIES (UNAUDITED)
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil
reserves is very complex, requiring significant subjective decisions in the
evaluation of all available geological, engineering and economic data for
each reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors including, but not
limited to, additional development activity, evolving production history
and continual reassessment of the viability of production under varying
economic conditions. Consequently, material revisions to existing reserve
estimates occur from time to time. Although every reasonable effort is made
to ensure that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective decisions required
and variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with
financial statement disclosures.
The reserve information as of December 31, 1996, 1997 and 1998 was prepared
by Huddleston & Co., Inc. The Company emphasizes that reserve estimates are
inherently imprecise and that estimates of new discoveries are more
imprecise than those of proved producing oil and gas properties.
Accordingly, these estimates are expected to change as future information
becomes available.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate that geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are proved reserves that can be expected to be recovered
through existing wells with existing economic and operating methods.
No major discovery or other favorable or adverse event subsequent to
December 31, 1998 is believed to have caused a material change in the
estimates of proved or proved developed reserves as of that date.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the Company's net proved reserves, including
the changes therein, and proved developed reserves (all within the United
States) at the end of each of the three years in the period ended December
31, 1998:
CRUDE OIL NATURAL
(MBBl) GAS (MMcf)
--------- ----------
Proved developed and undeveloped reserves:
January 1, 1996 2,260 5,909
Revision of previous estimates -- 5,920
Extensions, discoveries and other additions 9 2,299
Production (37) (1,324)
Sales of minerals in place (2,182) --
Purchases of reserves in place 189 36,442
------ ------
December 31, 1996 239 49,246
------ ------
Revision of previous estimates (38) (6,848)
Extensions, discoveries and other additions 70 9,105
Production (21) (3,685)
Purchases of reserves in place 15 3,347
------ ------
December 31, 1997 265 51,165
------ ------
Revision of previous estimates (144) (15,128)
Extensions, discoveries and other additions 411 56,116
Production (79) (10,510)
Sales of minerals in place (4) (716)
Purchases of reserves in place 4,474 108,826
------ ------
December 31, 1998 4,923 189,753
====== =======
CRUDE OIL NATURAL
(MBBl) GAS (MMcf)
--------- ----------
Proved developed reserves:
December 31, 1995 689 2,627
December 31, 1996 79 16,924
December 31, 1997 108 22,937
December 31, 1998 904 54,277
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES (UNAUDITED)
SFAS No. 69 prescribes guidelines for computing a standardized measure of
future net cash flows and changes therein relating to estimated proved
reserves. The Company has followed these guidelines which are briefly
discussed below.
Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated
quantities of oil and gas to be produced. Estimated future income taxes are
computed using current statutory income tax rates, including consideration
for estimated future statutory depletion and alternative fuels tax credits.
The resulting future net cash flows are reduced to present value amounts by
applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such do not
necessarily reflect the Company's expectations of actual revenues to be
derived from those reserves nor their present worth. The limitations
inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (in thousands):
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31,
-----------------------------------------
1996 1997 1998
-------- -------- --------
Future cash inflows $129,588 $115,766 $396,091
Less related future:
Production costs (19,319) (20,226) (74,723)
Development costs (16,070) (17,295) (92,504)
Income tax expense (28,715) (22,497) (38,182)
-------- -------- --------
Future net cash flows 65,484 55,748 190,682
10% annual discount for estimating timing of cash flows (23,135) (19,109) (80,172)
-------- -------- --------
Standardized measure of discounted future net cash flows $ 42,349 $ 36,639 $110,510
======== ======== ========
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves is as follows (in
thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1997 1998
-------- -------- --------
Beginning of the period $ 12,877 $ 42,349 $ 36,639
-------- -------- --------
Revisions of previous estimates:
Changes in prices and costs 17,803 (9,701) (8,241)
Changes in quantities 9,108 (12,789) (19,637)
Development costs incurred during the period 96 1,836 2,400
Additions to proved reserves resulting from extensions
and discoveries, less related costs 2,051 11,172 31,001
Purchases of reserves in place 31,082 3,894 83,040
Sales of reserves in place (11,983) (729)
Accretion of discount 1,851 6,073 5,149
Sales of oil and gas, net of production costs (1,663) (7,269) (18,262)
Net change in income taxes (12,744) 3,530 (7,280)
Production timing and other (6,129) (2,456) 6,430
-------- -------- --------
Net increase (decrease) 29,472 (5,710) 73,871
End of the period $ 42,349 $ 36,639 $110,510
======== ======== ========
49
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the names, ages and positions of the
directors and executive officers of the Company. A summary of the background
and experience of each of these individuals is set forth following the table.
NAME AGE POSITION WITH COMPANY
- ---- --- ---------------------
Glenn D. Hart 42 Chairman of the Board and Chief Executive Officer
Michael G. Farmar 41 President, Chief Operating Officer and Director
Jerry F. Holditch 41 Vice President-Geosciences and Director
Douglas R. Fogle 43 Vice President-Engineering
Robert L. Swanson 41 Vice President-Finance
Scott R. Sampsell 42 Vice President, Controller, Treasurer and Secretary
Jim R. Smith 59 Director
Jack I. Tompkins 53 Director
Bryant H. Patton 41 Director
Glenn D. Hart served as President of the Company from its inception
in 1982 until August 1996, when he was elected to his current position as
Chairman of the Board and Chief Executive Officer. From 1980 to 1983, Mr.
Hart was an engineering manager with Sanchez-O'Brien Oil & Gas Corporation,
an independent exploration and production company in South Texas. From 1978
to 1980, he held several engineering positions with Tenneco Oil Company's
Gulf Coast District. Mr. Hart has a B.S. in petroleum engineering from Texas
A&M University.
Michael G. Farmar has served as President and Director of the
Company since August 1996 and was elected Chief Operating Officer in January
1997. From January 1995 to August 1996, Mr. Farmar served as a financial
advisor to small independent oil companies. In 1988, Mr. Farmar joined
Odyssey Petroleum Company, where, as General Manager, he was responsible for
operational and financial functions of the company until it was sold in 1994.
As an analyst for Maxus Exploration Company from 1986 until 1988, Mr. Farmar
worked on mergers, acquisitions and divestitures. From 1984 to 1986, Mr.
Farmar served in Diamond Shamrock Exploration Company's strategic planning
group. Mr. Farmar began his career with Chevron U.S.A. in 1980 and held
drilling and production engineering positions through 1983. Mr. Farmar holds
a B.S. in petroleum engineering from the University of Southern California
and an MBA from Southern Methodist University.
Jerry F. Holditch joined the Company in 1987 and has served as Vice
President of Geosciences and as Director since that time. From 1982 until
1987, Mr. Holditch served as a developmental geologist with TransTexas Gas
Corporation and its predecessors, where he was involved in numerous drilling
activities in the Lobo Trend area. From 1980 until 1982, Mr. Holditch was
employed as a Gulf Coast geologist with Gulf Oil Corporation. Mr. Holditch
holds a B.S. in geology from Texas A&M University.
Douglas R. Fogle has served as Engineering Manager of the Company
since 1994 after joining the Company in 1992 as a Production Engineer and was
appointed to the additional position of Vice President of Engineering in
October 1998. From 1986 to 1991, Mr. Fogle worked as an insurance agent. From
1984 to 1986, Mr. Fogle worked with Langham Energy, an independent
exploration and production company, as Senior Petroleum Engineer. Mr. Fogle
worked from 1978 through 1984 with Champlin Petroleum (which was subsequently
acquired by Union Pacific Resources Company), an independent exploration and
production company, first as a Drilling and Completion Engineer and then,
starting in 1983, as Staff Production Engineer. Mr. Fogle has a B.S. in
petroleum engineering from Texas A&M University.
Robert L. Swanson joined the Company in September 1997 and has
served as Vice President of Finance since that time. From 1994 until joining
the Company, Mr. Swanson served as controller, chief financial officer and
50
treasurer of Southwest Ice Enterprises, L.C., a Texas limited liability
company and the owner and operator of a professional hockey team in Houston,
Texas. Prior to joining Southwest Ice Enterprises, L.C., Mr. Swanson was
employed as a public accountant from 1985 to 1994 with two Houston-area
accounting firms and one San Antonio-area accounting firm. Mr. Swanson is a
certified public accountant and is a member of the American Institute of
Certified Public Accountants and the Texas Society of Certified Public
Accountants.
Scott R. Sampsell has served as the Company's Controller and
Treasurer since 1992 and was appointed to the additional positions of Vice
President and Secretary in April 1998. From 1982 to 1992, Mr. Sampsell worked
in various accounting supervisory roles with Union Texas Petroleum
Corporation, an independent exploration and production company, including
Manager of Financial and Operational Accounting for one of its subsidiaries.
From 1977 until 1982, Mr. Sampsell worked with Supron Energy Corporation, an
independent exploration and production company, where he began as staff
accountant and advanced to Assistant Treasurer.
Jim R. Smith has served as a Director of the Company since November
1996. Since 1964, Mr. Smith has managed a privately-owned real estate
development company headquartered in Houston, Texas, which he founded. Mr.
Smith is also a private investor and holds positions with several non-profit
organizations, including Chairman of the Board of Directors of Goodwill
Industries of Houston.
Jack I. Tompkins has served as a Director of the Company since July
1997. Mr. Tompkins is a managing director of Raintree Equity Advisors, L.L.C.
and is Chairman of the Board of Automotive Realty Trust of America. From 1988
until October 1996, Mr. Tompkins served as Senior Vice President, Chief
Information, Administrative and Accounting Officer at Enron Corporation. He
also served as a member of Enron Corporation's Management Committee from 1989
through 1996. Mr. Tompkins began his career with Arthur Young & Co., serving
three years before joining Arthur Andersen, L.L.P., where he was elected to
the partnership in 1981 and was in charge of the Mergers and Acquisitions
Program for the Houston office. Mr. Tompkins also serves as chairman of the
board of Boys and Girls Country of Houston, Inc., and formerly served on the
board of directors of Bank of America Texas, the Private Sector Council and
Junior Achievement of Southeast Texas, Inc.
Bryant H. Patton has served as a Director of the Company since July
1997. Since 1991, Mr. Patton has been the Vice President of Associated Energy
Managers ("AEM"), an institutional investment management firm specializing in
private investments in the energy industry. AEM has invested for its clients
over $300 million with 23 different independent oil and gas companies through
three investment partnerships. Mr. Patton's industry experience spans 20
years including ten years as an equity owner in a fully integrated,
family-owned, oil and gas producing company consisting at one time of seven
entities and 350 employees.
ITEM 11. EXECUTIVE COMPENSATION
The following table sets forth certain summary information regarding
compensation paid or accrued by the Company to or on behalf of the Company's
executive officers (the "Named Executive Officers") for the fiscal years ended
December 31, 1997 and 1998.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
--------------------- 401K STOCK OPTIONS ALL OTHER
PRINCIPAL POSITIONS SALARY BONUS CONTRIBUTIONS GRANTED COMPENSATION
- ------------------------------------------------- -------- -------- ------------- ------------- ------------
GLENN D. HART
Chairman of the Board and Chief Executive Officer
1998 $238,500 $202,500 $3,038 -0- $ 10,553 (1)
1997 144,000 6,000 - -0- 11,303 (1)
MICHAEL G. FARMAR
President and Chief Operating Officer
1998 165,000 135,000 $2,160 -0- $ -0-
1997 84,000 3,500 - -0- -0-
JERRY F. HOLDITCH
Vice President-Geosciences
1998 99,000 75,000 $1,355 -0- $274,690 (2)
1997 60,000 2,500 -0- -0- 104,946 (2)
DOUGLAS R. FOGLE
Vice President-Engineering
1998 90,900 11,000 $1,262 -0- 1,686 (1)
1997 63,000 2,625 -0- -0- 4,023 (1)
SCOTT R. SAMPSELL
Vice President, Controller, Treasurer and Secretary
1998 81,300 20,900 $ 998 -0- -0-
1997 69,450 3,050 -0- -0- -0-
(1) Represents the estimated value of personal use of a Company vehicle.
(2) Represents amounts paid or accrued to Mr. Holditch during 1998
pursuant to certain overriding royalty interests granted to him.
No options were issued to or exercised by the Named Executive Officers in 1998.
51
STOCK OPTION AND OTHER EMPLOYEE COMPENSATION PLANS
In July 1998, MHI adopted the Michael Holdings, Inc. 1998 Stock
Option Plan (the "Option Plan") pursuant to which incentive stock options as
defined in the Internal Revenue Code of 1986, as amended ("ISOs"), and
non-qualified stock options ("NQOs") will be available for grant to key
employees, consultants and directors of MHI and the Company. The Option Plan
is administered by the Compensation Committee of the Board of Directors of
MHI. A maximum of 194,000 shares, subject to adjustment for certain events of
dilution, is available for grant under the Option Plan. The Option Plan
provides that the Option Agreement applicable to the grant of options may
provide that unmatured installments of outstanding options will accelerate
and become fully vested upon a "change of control" of MHI (as defined in the
Option Plan).
As of December 31, 1998, a total of 73,350 options were granted
under the Option Plan. Grants to employees and directors were granted at an
exercise price equal to not less than the fair market value per share on the
date of grant. All such options will have terms of not more than ten years
and be exercisable in cumulative annual installments of 33.33% of the total
number of shares subject to the option grants, beginning on the first
anniversary of the date of grant.
The Option Plan provides that the plan may be amended or modified by
the Board of Directors of MHI without the approval of the shareholders of
MHI, except for any amendment which would increase the total number of shares
reserved for issuance under the Option Plan or amendments which require
shareholder approval pursuant to applicable legal requirements or securities
exchange rules.
OVERRIDING ROYALTY INTERESTS
The Company has had in place for a number of years an arrangement,
and by written agreement dated July 24, 1997 the Company formalized such
arrangement, pursuant to which it has granted to Jerry Holditch, Vice
President--Exploration and a director of the Company, a 1.5% of 8/8ths
overriding royalty interest in all leases acquired either directly or
indirectly by the Company or its affiliates in Webb County or Zapata County,
Texas. For the year ended December 31, 1996, 1997 and 1998, Mr. Holditch
received from the Company $32,638, $104,946 and $274,690, respectively, under
the overriding royalty interests. The overriding royalty interests will not
apply to any producing properties acquired by the Company except for
deepenings or sidetracks of existing wells and all new wells drilled on
acquired producing properties. According to the terms of the agreement
establishing the overriding royalty interests, the Company's obligation to
assign overriding royalty interests to Mr. Holditch expires upon the death of
Mr. Holditch or upon his termination, resignation or retirement from the
Company; however, any overriding royalty interests assigned prior to such an
event shall be unaffected by the occurrence of that event. The agreement also
restricts Mr. Holditch's ability to compete with the Company in the Lobo
Trend for a period of three years following any resignation or retirement of
Mr. Holditch from the Company. If, following Mr. Holditch's retirement or
resignation, the Company becomes financially incapable of drilling or
completing wells on locations previously identified or selected by Mr.
Holditch, the Company shall provide written authorization to Mr. Holditch to
waive the three-year non-competition provision so that Mr. Holditch may
pursue the development of such location prospects. The Company does not
anticipate entering into any similar arrangements with any of its officers or
directors in the future.
EMPLOYMENT AGREEMENTS
The Company has entered into employment agreements, effective April
1, 1998, with Glenn D. Hart, Michael G. Farmar and Jerry F. Holditch,
pursuant to which Mr. Hart will serve as Chief Executive Officer of the
Company, Mr. Farmar will serve as President of the Company and Mr. Holditch
will serve as Vice President-Exploration. Each employment agreement is for a
term of two years and is automatically renewed for a period of two years from
and after the first day of each calendar quarter, commencing July 1, 1998,
unless either party gives written notice at least 30 days prior to the end of
the applicable period. The employment agreements provide for an annual base
salary ($270,000 for Mr. Hart, $180,000 for Mr. Farmar and $100,000 for Mr.
Holditch), which amount may be increased subject to periodic reviews. In
addition, Messrs. Hart, Farmar and Holditch are eligible to receive an annual
incentive bonus in an amount to be determined by the Board of Directors, but
in no event will such bonus amount be less than 50% nor more than 100% of the
employee's annual base salary. The employment agreements of Messrs. Hart and
Farmar further provide that the employee shall be granted options under the
Option Plan upon terms and conditions and in an amount to be determined by
the Compensation Committee. If during the term of the agreement the
employee's employment with the Company is terminated without "cause" (as
defined therein) or due to his resignation
52
for "good reason" (as defined therein), the Company will be obligated to pay
the employee payments in an amount equal to his base salary for the remaining
term of the agreement plus his accrued but unpaid bonus as of the date of
termination. The obligations of the Company under the employment agreements
are guaranteed by MHI.
COMPENSATION OF DIRECTORS
Non-employee directors of the Company are eligible to receive grants
of nonqualified stock options to purchase shares of Common Stock pursuant to
the Option Plan. On August 1, 1998, based on their relative length of service
as directors, Messrs. Tompkins and Patton were granted options to purchase
10,000 shares of Common Stock, and Mr. Smith was granted an option to
purchase 20,000 shares of Common Stock, at exercise prices equal to the fair
market value of the Common Stock on the date of grant.
In addition, the Company's non-employee directors receive $2,000
plus out-of-pocket expenses for each meeting of the Board of Directors that
they attend.
BOARD COMMITTEES
Pursuant to the Company's Bylaws, the Board of Directors has
established standing Audit and Compensation Committees. The Audit Committee
recommends to the Board the selection and discharge of the Company's
independent auditors, reviews the professional services performed by the
auditors, the plan and results of the auditing engagement and the amount of
fees charged for audit services performed by the auditors and evaluates the
Company's system of internal accounting controls. The Compensation Committee
recommends to the Board the compensation to be paid to the Company's
directors, executive officers and key employees and administers the
compensation plans for the Company's executive officers and directors. The
members of the Audit Committee are Messrs. Farmar, Smith and Tompkins. The
members of the Compensation Committee are Messrs. Smith, Tompkins and Patton.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of December 31, 1998, (i) the
number of shares owned by each person known by the Company to own
beneficially Common Stock of MHI, (ii) the number of shares owned
beneficially by each director and (iii) the number of shares owned
beneficially by all executive officers and directors as a group. MHI owns of
record all of the issued and outstanding shares of common stock of the
Company.
COMMON STOCK
BENEFICIALLY PERCENTAGE OF
NAME OF PERSON OR GROUP OWNED(1) OWNERSHIP
- ----------------------- -------- ---------
EXECUTIVE OFFICERS AND DIRECTORS
Glenn D. Hart 281,900 36.5%
Michael G. Farmar 234,200 30.3%
Jerry F. Holditch 64,500 8.3%
Jim R. Smith 80,650 10.4%
Jack I. Tompkins 20,300 2.6%
Bryant H. Patton -- --
Scott R. Sampsell 24,200 3.1%
Douglas R. Fogle 34,275 4.4%
Robert L. Swanson -- --
All executive officers and directors, as a group 760,525 98.3%
(1) Except as otherwise noted, the named shareholder has sole voting,
investment and dispositive power.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company currently markets all of its natural gas through
Upstream Energy Services, L.L.C. ("Upstream") pursuant to a Natural Gas Sales
Agreement dated as of November 1, 1998. The Company and the predecessor to
Upstream had similar marketing arrangements prior to April 1996. During the
year ended December 31, 1996, 1997 and 1998, the Company paid Upstream or its
predecessor marketing fees of $106,000, $220,000 and $253,000, respectively,
under these arrangements. Until August 1997, Glenn D. Hart, the Company's
Chairman and Chief Executive Officer, owned 20% of the equity securities of
Upstream and its predecessor. In such capacity, Mr. Hart
53
received dividends of $26,875 and $6,000 in the year ended December 31, 1996
and 1997, respectively. Additionally, Upstream executed a promissory note in
an aggregate principal amount of $20,000 payable to Mr. Hart in connection
with the purchase by Upstream of Mr. Hart's interest. Interest on the
indebtedness accrues at a rate of 8.25% per annum. Neither Mr. Hart nor the
Company or any other officer or director of the Company currently owns any
interest in Upstream.
The Company has granted to Jerry F. Holditch, Vice
President-Exploration and a director of the Company, a 1.5% of 8/8ths
overriding royalty interest in all leases acquired either directly or
indirectly by the Company or its affiliates in Webb County and Zapata County,
Texas. See Item 11. Executive Compensation.
On June 10, 1997, Glenn D. Hart, Chairman of the Board and Chief
Executive Officer of the Company, entered into an agreement with the Company
pursuant to which Mr. Hart granted the Company an option to purchase an
undivided two-thirds working interest, which Mr. Hart owns in his individual
capacity, in a leasehold interest. The Company exercised this option and
purchased this lease. The leasehold interest expires on May 30, 2000 and
covers approximately 750 acres in Webb County, Texas. The exercise price of
the option was $87,500 plus approximately $2,000 in carrying fees. In
addition, pursuant to the agreement. Mr. Hart reserved a 1% overriding
royalty interest.
Concurrently with the closing of the sale of the Senior Notes, the
Company acquired, for a purchase price of $11.0 million, the Net Profits
Interest from Cambrian, at which time Cambrian received a warrant from MHI
to acquire 38,671 shares of Common Stock at an exercise price of $8.00 per
share. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Financing Arrangements."
Although the Company has no present intention to do so, it may in
the future enter into other transactions and agreements incidental to its
business with its directors, officers and principal shareholders. The Company
intends any such transactions and agreements to be on terms no less favorable
to the Company than could be obtained from unaffiliated parties on an arms'
length basis.
MHI has entered into Indemnity Agreements with each of the directors
of MHI (who also serve as the directors of the Company), pursuant to which
MHI has agreed to indemnify each director to the fullest extent permitted
under the Texas Business Corporation Act. In addition, pursuant to the
Agreement, MHI shall advance reasonable expenses incurred by each director
under certain circumstances in any proceeding in which each director was, is
or is threatened to be named a defendant.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULTES AND REPORTS ON FORM 8-K
(a) 1. CONSOLIDATED FINANCIAL STATEMENTS
See Index on page 30.
2. FINANCIAL STATEMENT SCHEDULES
None.
54
3. EXHIBITS
The following instruments are included as exhibits to this report.
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1* Articles of Incorporation of the Company.
3.2* By-Laws of the Company.
4.2* Indenture, dated as of April 2, 1998, between the Company and
State Street Bank and Trust Company as Trustee
10.1*** Michael Holdings, Inc. 1998 Stock Option Plan.
10.2** Employment Agreement dated April 1, 1998 between the Company
and Glenn D. Hart.
10.3** Employment Agreement dated April 1, 1998 between the Company
and Michael G. Farmar.
10.4** Employment Agreement dated April 1, 1998 between the Company
and Jerry F. Holditch.
10.5* Purchase and Sale Agreement dated February 20, 1998 by and
between the Company and Conoco, Inc.
10.6* Purchase and Sale Agreement dated February 5, 1998 by and
between the Company and Enron Oil and Gas Company
10.7* Stock Purchase Warrant granted by Michael Holdings, Inc. to
Cambrian Capital Partners, L.P., dated April 2, 1998.
10.8* Form of Indemnification Agreement by and between the Company
and its directors.
10.9* Assets Agreement dated April 20, 1998 by and between the
Company and Mobil Exploration & Producing U.S. Inc. acting as
Agent for Mobil Producing Texas & New Mexico Inc.
10.10* Oil and Gas Lease dated April 20, 1998 by and between the
Company and Mobil Producing Texas & New Mexico Inc.
10.11* Warrant to Purchase Shares of Common Stock granted by Michael
Holdings, Inc. to Dale L. Schwartzhoff.
10.12* First Amended and Restated Shareholders Agreement of the
Company.
10.13* Credit Agreement dated May 15, 1998 among the Company,
Christiania and the lenders named therein.
10.14* Master Commodity Swap Agreement dated May 15, 1998 between
Christiania and the Company.
10.15*** Natural Gas Marketing, Transportation and Processing
Agreement dated as of November 1, 1998 by and between the
Company and Upstream Energy Services Company.
10.16*** First Amendment to Credit Agreement dated March 29, 1999
among the Company, Christiania and the lenders named
therein.
10.17*** Letter Agreement dated March 30, 1999 between the Company
and Christiania.
27.1*** Financial Data Schedule.
* Previously filed as an Exhibit (with a corresponding Exhibit number)
to the Company's Registration Statement on Form S-4 filed May 8,
1998, No. 333-52263, and incorporated herein by reference.
** Management compensation or incentive plan previously filed.
*** Filed herewith.
(b) REPORTS ON FORM 8-K.
None.
(c) EXHIBITS REQUIRED BY ITEM 601 OF REGULATION S-K
Not applicable.
55
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.
MICHAEL PETROLEUM CORPORATION
Dated: April 1, 1999
By: /s/ MICHAEL G. FARMAR
-----------------------
Michael G. Farmar
President and Chief
Operating Officer
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Michael G. Farmar and Glenn D. Hart
and each of them, as true and lawful attorneys-in-fact and agents with full
power of substitution and resubstitution for him and in his name, place and
stead, in any and all capacities, to sign any and all documents relating to
the Annual Report on Form 10-K, for the fiscal year ended December 31, 1998,
including any and all amendments and supplements thereto, and to file the
same with all exhibits thereto and other documents in connection therewith
with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents full power and authority to do and perform each
and every act and thing requisite and necessary to be done in and about the
premises, as fully as to all intents and purposes as he might or could do in
person, hereby ratifying and confirming all that said attorneys-in-fact and
agents or their or his substitute or substitutes may lawfully do or cause to
be done by virtue hereof.
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
ANNUAL REPORT ON FORM 10-K HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON
BEHALF OF THE COMPANY AND IN THE CAPACITIES INDICATED ON THE 1 DAY OF APRIL,
1999.
NAME: CAPACITIES:
/s/ GLENN D. HART Chairman of the Board and Chief Executive Officer
- --------------------- (Principal Executive Officer)
Glenn D. Hart
/s/ MICHAEL G. FARMAR President, Chief Operating Officer and Director
- ---------------------
Michael G. Farmar
/s/ JERRY F. HOLDITCH Vice President-Geosciences and Director
- ---------------------
Jerry F. Holditch
/s/ ROBERT L. SWANSON Vice President-Finance
- --------------------- (Principal Accounting and Financial Officer)
Robert L. Swanson
/s/ SCOTT R. SAMPSELL Vice President-Accounting, Treasurer, and Secretary
- ---------------------
Scott R. Sampsell
56
/s/ JIM R. SMITH Director
- ---------------------
Jim R. Smith
/s/ JACK I. TOMPKINS Director
- ---------------------
Jack I. Tompkins
/s/ BRYANT H. PATTON Director
- ---------------------
Bryant H. Patton
57