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, 1999
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 31, 2000, 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 .................................................................. 3
Background and Recent Developments.................................... 3
1998 Acquisitions..................................................... 6
Market Factors........................................................ 7
Competition........................................................... 8
Governmental Regulation............................................... 9
Abandonment Costs.....................................................12
Operating Hazards and Insurance.......................................12
Employees.............................................................13
Item 2. Properties.................................................................13
Oil and Natural Gas Reserves..........................................14
Item 3. Legal Proceedings..........................................................20
Item 4. Submission of Matters to a Vote of Security Holders........................21
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......21
Item 6. Selected Consolidated Financial Data.......................................21
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition..................................................22
General...............................................................22
Results of Operations.................................................23
Liquidity and Capital Resources.......................................26
Item 7A Quantitative and Qualitative Disclosures About Market Risk.................32
Item 8. Financial Statements.......................................................35
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................................64
Item 10. Directors and Executive Officers of the Registrant.........................64
Item 11. Executive Compensation.....................................................66
Item 12. Security Ownership of Certain Beneficial Owners and Management.............69
Item 13. Certain Relationships and Related Transactions.............................69
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............70
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 and Financial Condition - Cautionary Statements Regarding
Forward-Looking Information.
PART I
ITEM 1. BUSINESS
BACKGROUND AND RECENT DEVELOPMENTS
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 expanded its production and reserve base in recent years
through development drilling and exploitation activities and by acquiring
producing and undeveloped properties. 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.
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. The
Company uses 3-D seismic imaging and other advanced technologies in the
development and exploitation of its properties.
ACQUISITIONS AND SUBSTANTIAL INDEBTEDNESS
During 1998, the Company implemented a growth strategy aimed at
accomplishing strategic and complementary acquisitions that would expand its
inventory of producing and undeveloped properties. To facilitate this
strategy, in April 1998, the Company completed a $135 million debt offering of
its 11 1/2% Series A Notes due 2005. By September 1998, all of the $135
million original principal amount of the Series A Notes had been exchanged for
its 11 1/2% Series B Notes due 2005, the terms of which are substantially
identical to the terms of the Series A Notes. The Series A and Series B Notes
are sometimes referred to in this report as "Senior Notes."
The Company completed various acquisitions during 1998, each of which
is described below. The Company financed these acquisitions primarily through
proceeds from the issuance of the Senior Notes, applying approximately $90
million in net proceeds from the sale of its Senior Notes in connection with
the closing of these acquisitions.
The issuance of the Senior Notes substantially increased the
Company's level of indebtedness over historical levels. This increased level
of indebtedness had several important effects on the Company's operations,
including the following: (i) a substantial portion of the Company's cash flow
from operations was dedicated to the payment of interest on its debt, thereby
reducing funds available to it for other purposes; (ii) the Company's
leveraged position substantially increased its vulnerability to adverse
changes in general economic and industry conditions; and (iii) the Company's
ability to obtain additional financing for working capital, capital
expenditures and general corporate and other purposes became constrained. As a
result of changes in industry conditions coupled with these factors, the
Company's earnings and cash flows became insufficient to meet all of its fixed
charges.
RECENT DEVELOPMENTS
During 1998 and 1999, the Company's results of operations and
financial condition deteriorated significantly. This deterioration was a
result of a combination of factors, including low oil and natural
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gas prices during the second half of 1998 and the first four months of 1999,
failure to successfully realize anticipated benefits from acquired properties
and the significant debt burden incurred by the Company in 1998 to finance its
acquisition strategy.
INDUSTRY CONDITIONS. Declines in oil and natural gas prices adversely
affected the Company's financial condition, liquidity and results of
operations in 1998 and 1999. Although oil and natural gas prices recovered
during 1999, the effect of the price declines coupled with the Company's
inability to service its outstanding indebtedness and the lack of alternate
sources of capital on terms acceptable to management caused the Company to not
achieve the levels of revenues and cash flows necessary in order to meet its
substantial debt obligations.
EXECUTION OF VOTING AGREEMENT AND FILING OF PETITIONS IN BANKRUPTCY.
Beginning in the second quarter of 1999, representatives of the Company and
its financial advisor engaged during 1999, began meeting with certain holders
of the Senior Notes to seek financial restructuring alternatives. An interest
payment on the Senior Notes of approximately $7.8 million was due on October
1, 1999, but was not paid by the Company. A 30-day grace period under the
Indenture governing the Senior Notes expired on October 31, 1999 without
payment of interest on the Senior Notes, and, as a result, an event of default
occurred under the Indenture. The Indenture provides that in the event of an
event of default, the entire indebtedness under the Senior Notes may be
declared due and payable.
During 1999, the Company experienced a number of covenant defaults
under its secured credit facility (the "Credit Facility") with Christiania
Bank og KreditKasse ("Christiania"). The Company was able to obtain a number
of waivers to certain of these defaults during 1999, but under an amendment to
the Credit Facility entered into in early 1999, the Company was to begin
making $1.5 million monthly principal payments under the Credit Facility on
October 31, 1999. The Company did not make the $1.5 million principal payment
due October 31, 1999, which constituted an event of default under the Credit
Facility.
Under the cross default provisions contained in the Indenture
governing the Senior Notes and in the Credit Facility with Christiania, a
default under either the Senior Notes or the Credit Facility constituted a
default under the other instrument.
Effective December 10, 1999, the Company, its parent corporation,
Michael Holdings, Inc. ("MHI"), and certain of its subsidiaries entered into
an agreement (the "Voting Agreement") with certain holders of the Company's
Senior Notes, which provided for (i) the filing of a Chapter 11 bankruptcy
case by the Company, MHI and certain subsidiaries, (ii) a marketing process
with respect to the Company and its assets under the Voting Agreement and
(iii) the filing of a consensual joint plan of reorganization of the Company
(the "Plan"). The Voting Agreement was signed by Holders of more than
$90,000,000, or two-thirds, of the outstanding principal amount of the Senior
Notes (the "Consenting Holders"). In accordance with the Voting Agreement, on
December 10, 1999, the Company, MHI and certain of its subsidiaries filed
petitions for relief under Chapter 11 of the Bankruptcy Code in the United
States Bankruptcy Court for the Southern District of Texas, Laredo Division
(the "Bankruptcy Court"). As described below, the Voting Agreement generally
obligated the Consenting Holders to vote in favor of the Plan so long as the
Plan contained terms consistent with a term sheet attached to the Voting
Agreement.
The bankruptcy petitions were filed in order to give the Company an
opportunity to conserve its cash and restructure its debt. Since December 10,
1999, the Company, MHI and the filing subsidiaries have operated as
debtors-in-possession under the Bankruptcy Code. The Company has curtailed its
developmental drilling program, limiting expenditures to a one-rig drilling
program. No trustee or
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examiner has been appointed and the Company, MHI and these subsidiaries are
paying their postpetition obligations (except those subject to Bankruptcy
Court approval) as they become due.
On January 11, 2000, the Bankruptcy Court entered an agreed final
order authorizing use of cash collateral, with the agreement of Christiania.
Under the order, the Company must comply with certain financial covenants and
pay interest weekly to Christiania. On April 5, 2000, the Court entered its
Second Final Agreed Order Authorizing use of Cash Collateral and Granting
Adequate Protection. This Order was entered with the agreement of Christiania,
who consented to the Company's continued use of Christiania's cash collateral
in accordance with the terms and conditions set forth in the Order until May 1,
2000, unless extended by the parties or further order of the Court after notice
and a hearing. Among other things, the Order provides Christiania new, first
priority and senior security interests in the Company's assets and requires
the Company to make weekly adequate protection payments to Christiania during
the term of the Order. The Order also imposes certain reporting requirements
and cash collateral operating requirements on the Company.
THE VOTING AGREEMENT. The terms of the Voting Agreement contemplated
that the Plan would provide for a sale of the Company or its assets in
court-supervised proceedings under the Bankruptcy Code. Under the Voting
Agreement, the Consenting Holders agreed to vote in favor of the Plan so long
as the Plan was consistent in all material respects with the term sheet for
the Plan attached to the Voting Agreement. The term sheet set forth, among
other things, a process for the marketing and sale of the Company or its
assets for a "Net Consideration" (as defined in the term sheet) of at least
$120 million, as adjusted for certain costs and working capital items, the
proceeds of which shall be applied first to the repayment of the Company's
bank debt under the Credit Facility (approximately $24.3 million principal
amount outstanding at December 31, 1999). The Voting Agreement provided that,
so long as no "Termination Event" occurred, the Consenting Holders would:
1. vote to accept the Plan;
2. neither commence nor assist or encourage any other
person to commence any other legal or enforcement
actions concerning the Company's debts;
3. not take any position in the bankruptcy proceedings
that conflicts with their obligation to support the
Plan; and
4. vote their Senior Note claims to reject any
bankruptcy plan for the Company other than the Plan.
The Voting Agreement contemplated that the Company and its
subsidiaries would continue to operate as debtors-in-possession subject to the
supervision of the Bankruptcy Court, and that the Plan would provide for the
payment of all trade creditors' claims as and when they come due in the
ordinary course or in full on the effective date of the Plan.
The Voting Agreement provided that the obligations of the Consenting
Holders may terminate upon a "Termination Event," which included any failure
under the marketing process to timely achieve certain milestones, including
the receipt of at least one final bid to purchase the Company or its assets by
March 17, 2000 in an amount equal to at least $120 million, subject to
adjustment for certain costs and working capital items. As of March 17, 2000,
the Company had not received a final bid in such an amount sufficient to meet
this requirement. The Company and its advisors have continued to negotiate
with the holders of the Senior Notes and with prospective purchasers for a
consensual Plan. The
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Company expects to file the Plan and related disclosure statement with the
Bankruptcy Court in April 2000.
On April 3, 2000, the Bankruptcy Court entered an agreed order
extending the period during which the Company would have exclusivity to file
its Plan and disclosure statement to April 17, 2000.
At this time, it is not possible to predict the outcome of the
bankruptcy proceedings, or the effect on the Company's business or on the
interests of its creditors, royalty owners or stockholders, or whether certain
executory contracts will be assumed or rejected. As a result of the bankruptcy
filing, certain of the Company's liabilities are subject to compromise.
1998 ACQUISITIONS
The Company significantly expanded its asset base and operations
during 1998 through acquisitions and investments.
ENRON ACQUISITION
In March 1998, the Company closed its acquisition of Lobo Trend
properties with Enron Oil and Gas Company ("Enron"). Under 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 Senior Notes.
In addition, the Company granted to Enron a non-exclusive license to use the
seismic data it conveyed to the Company.
CONOCO ACQUISITION
The Company completed its acquisition of properties from Conoco Inc.
("Conoco") 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 Senior Notes to pay the purchase price of the Conoco Acquisition.
LOBO LEASE TRANSACTION
By agreement dated April 20, 1998, the Company acquired from a
subsidiary of Mobil Corporation ("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
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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 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 (bearing interest
at 12% per annum) to 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 note became past due on December 15, 1999
and this receivable has been fully reserved by the Company.
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 adversely affected the
Company's financial condition, liquidity and results of operations in 1998 and
1999.
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.
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 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
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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 automatically for successive one-year periods thereafter. 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 an acquisition by the Company of Lobo Trend
properties made in 1996, Conoco (as the successor in interest to the seller)
and the Company entered into a Gas Exchange Agreement whereby the parties
agreed that the Company would deliver to Conoco all of the natural gas
produced from the leases acquired in that acquisition at the point(s) at which
the 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 ranges from $0.11 to $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 Inc., EOG Resources Inc. and numerous
independent oil and natural gas companies. 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 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 and the pending bankruptcy proceedings. 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.
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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 any future
acquisitions in this area. There can be no assurance that financing will be
available, or if so, on terms that are acceptable to the Company. Failure to
secure such financing or to locate industry partners will 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 Conditions." The Company's current
financial condition and the fact it is subject to Bankruptcy Court
jurisdiction is a negative competitive condition presently affecting the
Company.
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. Since 1985, 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.
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The FERC has also announced several important transportation-related
policy statements and rule changes, including a statement of policy and final
rule issued February 25, 2000 concerning alternatives to its traditional
cost-of-service ratemaking methodology to establish the rates interstate
pipelines may charge for their services. The final rule revises FERC's pricing
policy and current regulatory framework to improve the efficiency of the
market and further enhance competition in natural gas markets.
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
public health and the environment affect the Company's oil and natural gas
operations and costs. 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 investigation, rendering a person or entity liable
for environmental investigation cleanup costs and for national resource
damages 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 for the release of a
"hazardous substance" into the environment. These persons include the current
or former owner or operator of any site where a release historically 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. It should be
noted that CERCLA excludes petroleum from the definition of hazardous
substance. Comparable state statutes also impose liability on the owner or
operator of a
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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.
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 Clean Water Act ("CWA") imposes restrictions and strict controls
regarding the discharge of wastes, including produced waters and other oil and
natural gas wastes, into waters of the United States, a term broadly defined.
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 CWA
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. The Oil Pollution
Act ("OPA") amends and augments oil spill
-11-
provisions of the CWA. 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 CWA 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
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 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.
-12-
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, 1999, the Company employed 28 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.
On March 27, 2000, the Bankruptcy Court approved an Employee
Retention Bonus Plan. Under the terms of the Employee Retention Bonus Plan,
eligible employees are entitled to a bonus equal to three months salary if the
employee remains employed with the Company through the effective date of the
plan of reorganization. The estimated cost of the Employee Retention Bonus
Plan is approximately $400,000.
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, 1999. 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
primarily geologic target in the Lobo Trend is the Lobo sand series of the
Lower Wilcox formation, which contained multiple pay sands. The primary
objectives in the Lobo Trend are the Lobo l 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. The introduction of
3-D seismic to the area in the early 1990's 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
-13-
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, 1997, 1998
and 1999. The reserve data and present values presented have been estimated by
Netherland Sewell & Assoc., Inc. for the year ended December 31, 1999 and
Huddleston & Co., Inc. for the years ended December 31, 1998 and 1997. 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,
------------------------------------------------
1997 1998 1999
-------------- ------------- -------------
Estimated proved reserves:
Oil and condensate (MBbls) 265 4,923 1,415
Natural gas (MMcf) 51,165 189,753 185,652
Natural gas equivalents (MMcfe) 52,754 219,291 194,141
Proved developed reserves as a percentage of proved reserves 45% 27.2% 33.9%
PV-10 Value (dollars in thousands)(1) $51,487 $132,638 $133,341
(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 Securities
and Exchange Commission (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, 1999 were $23.80
per Bbl of oil and $2.33 per Mcf of natural gas, compared to $9.17 per
Bbl of oil and $1.85 per Mcf of natural gas as of December 31, 1998, and
$15.91 per Bbl of oil and $2.42 per Mcf of natural gas as of December 31,
1997.
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
-14-
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,
1997, 1998, and 1999.
YEAR ENDED DECEMBER 31,
------------------------------------------------
1997 1998 1999
-------------- -------------- -------------
Production volumes:
Oil and condensate (MBbls) 21 79 116
Natural gas (MMcf) 3,685 10,510 14,122
-------------- -------------- -------------
Total (MMcfe) 3,811 10,984 14,817
============== ============== =============
Average realized prices:
Oil, condensate and natural gas liquids (per Bbl) $18.95 $11.19 $16.77
Natural gas (per Mcf) (1) 2.33 2.07 2.28
Natural gas equivalents (per Mcfe) (1) 2.35 2.06 2.30
Expenses (per MCFE):
Production costs $0.49 $0.37 $0.37
Depreciation, depletion and amortization 0.96 1.14 1.21
Impairment of oil and gas properties 0.06 0.49 0.26
General and administrative, net 0.26 0.16 0.15
(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, 1999:
1999
------------------------------------------------
GROSS NET
------------------------- --------------------
Oil 7 --
Natural gas 347 141
------------------------- --------------------
Total 354 141
========================= ====================
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, 1999.
1999
--------------------------------------------------------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
----------------------------- ----------------------------- ----------------------------
GROSS NET GROSS NET GROSS NET
-------------- -------------- -------------- -------------- -------------- --------------
-15-
Lobo Trend 32,200 19,586 56,617 41,523 88,817 61,109
Other 2,585 394 -- -- 2,585 394
-------------- -------------- -------------- -------------- -------------- --------------
Total 34,785 19,980 56,617 41,523 91,402 61,503
============== ============== ============== ============== ============== ==============
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, 1997, 1998 and 1999.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
1997 1998 1999
---------------------- ---------------------- ---------------------
GROSS NET GROSS NET GROSS NET
----------- ----------- ---------- ----------- ---------- ----------
Development wells
Productive Natural Gas 15 9.2 26 17.6 20 16.1
Productive Oil 0 0.0 0 0.0 0 0.0
Dry 4 2.5 6 4.7 6 3.0
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 19 11.7 32 22.3 26 19.1
=========== =========== ========== =========== ========== ==========
Wells in progress at end of period 1 0.7 6 3.8 3 2.0
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, 2000 to March 31, 2000, the Company participated in
drilling activities on a total of 3 gross (2 net) wells, 2 gross (2 net) of
which have been completed as productive wells, with one well still in progress.
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
-16-
The Company believes it has satisfactory title to 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 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
includable 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.
-17-
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.
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
-18-
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.
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.
-19-
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.
WORKOVER.
Operations on a producing well to restore or increase production.
ITEM 3. LEGAL PROCEEDINGS
On December 10, 1999, the Company, MHI, and certain of its subsidiaries
filed petitions for relief under Chapter 11 of the Bankruptcy Code in order to
facilitate the restructuring of the Company's liabilities. The Company continues
to operate as a debtor-in-possession subject to the Bankruptcy Court's
supervision and orders. The filing was made in the U.S. Bankruptcy Court for the
Southern District of Texas, Laredo Division. See Item 1.
- - "Business - Background and Recent Developments."
On March 27, 2000, the Company received a demand letter from a royalty
owner. The demand letter challenges certain deductions used by the Company to
calculate prices for oil and gas royalties. The Company believes that it has
substantial defenses to this claim and intends to vigoriously assert such
defenses. However, the investigation into this claim is in the early phases and
the potential range of loss, if any, cannot presently be determined.
On March 31, 2000, the Company received correspondence from counsel to
the Official Committee of Unsecured Creditors requesting the Company to take
legal action on behalf of the Company's Estate against Glenn D. Hart, Michael G.
Farmar and the directors of Company, alleging certain misstatements in
connection with the issuance of the Senior Notes and certain breaches of
fiduciary duties to the creditors. The Company is currently evaluating the
claims made under these allegations, but currently knows of no basis for their
assertion.
In addition to the matters noted above, 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, 1999, there were
no threatened or pending legal matters, other than the matters noted above,
which would have a material impact on the Company's consolidated financial
position, results of operations or cash flows.
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 1999.
-20-
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 31, 2000, substantially all of the common
stock of MHI was 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, 1998 and 1999. 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 Senior 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,
1999. The financial data for each of the years ended, and as of, December 31,
1995, 1996, 1997, 1998 and 1999 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. The financial data set forth below is
derived from the historical financial statements of the Company, and based on
the uncertainties associated with the Company's ongoing reorganization
proceedings, may not be considered as indicative of the Company's future
performance. (See Item 1. - "Business - Background and Recent Developments."
-21-
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
1995 1996 1997 1998 1999
-------------- -------------- -------------- -------------- -------------
(IN THOUSANDS)
Income Statement Data:
Operating revenues $ 2,937 $ 3,776 $9,139 $22,718 $34,150
Operating expenses 4,113 3,581 7,072 24,049 31,052
-------------- -------------- -------------- -------------- -------------
Operating income (loss) (1,176) 195 2,067 (1,331) 3,098
Loss from continuing operations (2,114) (2,479) (7) (8,710) (16,443)
Discontinued operations 2,087 - - - -
Extraordinary item - - - (531) -
Net loss $ (27) $(2,479) $ (7) $(9,241) $(16,443)
AS OF DECEMBER 31,
----------------------------------------------------------------------------
1995 1996 1997 1998 1999
-------------- -------------- -------------- -------------- -------------
(DOLLARS IN THOUSANDS)
Balance Sheet Data:
Current assets $ 1,241 $ 4,375 $ 5,255 $ 8,951 $ 15,265
Oil and gas properties, net 7,890 16,208 28,011 130,878 134,357
Total assets 9,145 21,001 33,617 147,282 149,811
Debt 6,892 16,686 27,941 144,883 157,401
Shareholder's equity (deficit) $ 423 $(1,908) $(1,915) $(11,156) $(27,599)
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, 1999. 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
Effective December 10, 1999, the Company, MHI and certain of its
subsidiaries entered into the Voting Agreement with certain holders of the
Company's Senior Notes for a consensual joint plan of reorganization of the
Company. The terms of the Voting Agreement contemplated that the Plan will
provide for a sale of the Company or its assets in court-supervised
proceedings under the Bankruptcy Code. On December 10, 1999, the Company, MHI
and certain of its subsidiaries filed petitions for relief under Chapter 11 of
the Bankruptcy Code in the Bankruptcy Court. The Company expects to file the
Plan and related disclosure statement with the Bankruptcy Court in April 2000.
In addition to the approval of the Bankruptcy Court, the consummation of the
plan of reorganization will be subject to the consent of the requisite number
and amount of certain of the Company's creditors. The Voting Agreement
contemplated that the Company and its subsidiaries will continue to operate as
debtors-in-possession subject to the supervision of the Bankruptcy Court, and
that the Plan will provide for the payment of all trade creditors' claims as
and when they come due in the ordinary course or in full on the effective date
of the Plan. There can be no assurance that the Bankruptcy Court will approve
the Plan.
-22-
The Voting Agreement provided that the obligations of the parties
thereto may terminate upon a "Termination Event," which includes any failure
under the marketing process to timely achieve certain milestones, including
the receipt of at least one final bid by March 17, 2000 in an amount equal to
at least $120 million, as adjusted for certain costs and working capital
items. As of March 17, 2000, the Company had not received a final bid in such
an amount sufficient to meet this requirement. The Company and its advisors
continue to negotiate with the holders of the Senior Notes and with
prospective purchasers for a consensual plan of reorganization.
As of December 10, 1999, the Company discontinued the accrual of
interest on unsecured liabilities subject to compromise, which consist
primarily of the Senior Notes. As such, approximately $936,000 of interest
expense pertaining to the Senior Notes was not recognized for the period from
December 10, 1999 through December 31, 1999.
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, 1997, 1998 and 1999:
YEAR ENDED DECEMBER 31
---------------------------------------------------------
1997 1998 1999
----------------- ----------------- ----------------
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT DATA)
Production volumes:
Oil and condensate (MBbls) 21 79 116
Natural gas (MMcf) 3,685 10,510 14,122
Average sales prices:
Oil and condensate (per Bbl) $18.95 $ 11.19 $ 16.77
Natural gas (per Mcf) (1) 2.33 2.07 2.28
Operating revenues:
Oil and condensate $ 565 $ 888 $ 1,943
Natural gas(1) 8,574 21,780 32,207
----------------- ----------------- ----------------
Total $9,139 $ 22,668 $34,150
================= ================= ================
(1) Includes effects of hedging transactions.
-23-
COMPARISON OF YEARS ENDED DECEMBER 31, 1999 AND 1998
Oil and natural gas revenues for the year ended December 31, 1999
increased 51% to $34.2 million from $22.7 million for the year ended December
31, 1998. Production volumes for oil and natural gas for the year ended
December 31, 1999 increased 35% to 14,817 MMcfe from 10,984 MMcfe for the year
ended 1998. Average oil and natural gas prices (including the effect of
hedging transactions) increased 12% to $2.30 per Mcfe for 1999 from $2.06 per
Mcfe for 1998. The increase in natural gas production in 1999 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,
1999 increased 32% to $5.4 million from $4.1 million for the year ended
December 31, 1998, primarily due to the increase in production. However,
actual production costs per equivalent unit remained unchanged at $0.37 per
Mcfe for the years ended December 31, 1999 and 1998.
Depletion, depreciation and amortization ("DD&A") expense for the
year ended December 31, 1999 increased 43% to $18.0 million from $12.6 million
for the same period in 1998. The increase in DD&A expense was due to higher
production volumes. The depletion rate per Mcfe increased from $1.14 for 1998
to $1.21 for 1999. The increase in rate was primarily due to cost overruns for
certain wells completed in the first quarter of 1999, plus below average
reserves per well completed under the Company's 1998 drilling program.
Impairment charges decreased to $3.8 million for the year ended
December 31, 1999 compared to $5.4 million for the year ended December 31,
1998. Impairment charges incurred in 1999 and 1998 were primarily due to
development dry holes drilled on certain oil and gas leases that resulted in a
reduction in the estimated proved reserves. The impairment charge was
calculated using discounted cash flows of proved reserves using prices and
costs consistent with those used for internal decision making purposes.
General and administrative expense increased 21% to $2.2 million in
1999 from $1.8 million for the same period in 1998 due to the addition of
several new employees and their related benefits, plus increases in office
expenses and legal and professional fees.
Interest expense and loan amortization costs, net of capitalized
interest, for the year ended December 31, 1999 increased 32% to $16.2 million
compared to $12.3 million for 1998. The increase was due to the higher levels
of outstanding debt and increased interest rates for the Credit Facility
during 1999. The increases in the interest rates for the Credit Facility were
due to the payment of default interest rates charged during 1999 and was
partially offset by the discontinuance of interest on the Senior Notes
beginning December 10, 1999 due to the bankruptcy proceedings. As such,
approximately $936,000 of interest expense pertaining to the Senior Notes was
not recognized for the period from December 10, 1999 through December 31, 1999.
For the year ended December 31, 1999, the Company recorded in
interest income and other, an allowance for bad debts totaling $1.5 million
pertaining to a note receivable from a Texas limited liability company. The
allowance was established as a result of a contract cancellation by a third
party with a joint venture partner of the Texas limited liability company.
For the year ended December 31, 1999, the Company had incurred $1.5
million which consisted of approximately $792,000 of restructuring costs
(consisting principally of investment banking, legal and professional fees)
and approximately $721,000 of bankruptcy reorganization costs (legal and
other fees) pertaining to the Company's proposed capital restructuring
discussed under "Liquidity and Capital
-24-
Resources." These restructuring costs were expensed during the fourth quarter
due to the Bankruptcy filing on December 10, 1999. No restructuring or
reorganization costs were incurred in the year ended December 31, 1998.
Income tax expense was $1.9 million for the year ended December 31,
1999 as a valuation allowance of $7.2 million was recorded by the Company,
compared to an income tax benefit of $4.9 million for the same period in 1998.
The valuation allowance recorded by the Company is the principal reconciling
item between the expected tax benefit and the recorded tax amount. The
Company's net operating loss carryforward was fully reserved as of December
31, 1999 as the status of the current and future drilling program,
uncertainty about the availability of capital and the bankruptcy proceedings
resulted in uncertainty as to whether sufficient taxable income will be
available to utilize the entire net operating loss carryforward. Any
restructuring of the Company's indebtedness may result in a significant stock
ownership change which would significantly affect the timing of the
utilization of the net operating loss carryforward. The valuation allowance
related to tax assets could be adjusted in the future due to changes in
estimates of future taxable income and the outcome of the Bankruptcy
proceedings.
The extraordinary loss of $531,000 (net of the income tax benefit of
$285,000) for the year ended December 31, 1998 was due to the early
extinguishment of the previous credit facility. No extraordinary items were
recognized in the year ended December 31, 1999.
The net loss for the year ended December 31, 1999 was $16.4 million
compared to a loss of $9.2 million for the year ended December 31, 1998,
primarily as a result of the factors discussed above.
COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997
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 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. The
impairment charge was calculated using discounted cash flows of proved
reserves using prices and costs consistent with those used for internal
decision making purposes.
-25-
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 had 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 as of
at least $19.5 million would 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 believed it was more likely
than not that the net operating loss would 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 pertained to development dry holes,
intangible drilling costs, capitalized interest and depletion and depreciation
of oil and gas and other properties. Differences in these items began 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 Company's
net operating loss carryforward was fully reserved as of December 31, 1999 as
the status of the current and future drilling program, uncertainty about the
availability of capital and the bankruptcy proceedings resulted in uncertainty
as to whether sufficient taxable income will be available to utilize the
entire net operating loss carryforward. Any restructuring of the Company's
indebtedness may result in a significant stock ownership change which would
significantly affect the timing of the utilization of the net operating loss
carryforward. The valuation allowance related to tax assets could be adjusted
in the future due to changes in estimates of future taxable income and the
outcome of the Bankruptcy proceedings.
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 write-off of the
remaining loan costs relating to the Company's previous credit facility, 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.
LIQUIDITY AND CAPITAL RESOURCES
BANKRUPTCY PROCEEDINGS
On December 10, 1999, the Company, MHI and certain of Company's
subsidiaries filed voluntary petitions for relief under Chapter 11 of the
U.S. Bankruptcy Code in order to facilitate the restructuring of the Company's
liabilities. The Company has operated as a debtor-in-possession subject to
the Bankruptcy Court's supervision and orders.
-26-
The bankruptcy petitions were filed in order to preserve cash and to
give the Company the opportunity to restructure its debt. The consummation of
a plan of reorganization is the primary objective of the Company. The plan of
reorganization will set forth the means for satisfying claims, including
liabilities subject to compromise, and interests in the Company. A plan of
reorganization may result in, among other things, the sale of the Company's
oil and natural gas producing assets. The consummation of a plan of
reorganization will require approval of the Bankruptcy Court.
At this time, it is not possible to predict the outcome of the
bankruptcy proceedings, in general, or the effect on the business of the
Company or on the interests of creditors, royalty owners or stockholders.
There can be no assurance that the plan of reorganization to be submitted by
the Company will be approved or that the Bankruptcy Court will permit the
Company to continue to operate as a debtor-in-possession. As a result, there
is substantial doubt about the Company's ability to continue as a going
concern. See the Consolidated Financial Statements of the Company included
under Item 8 of this report.
In the ordinary course of business, the Company makes substantial
capital expenditures for the exploration and development of oil and natural
gas reserves. Historically, the Company has financed its capital expenditures,
debt service and working capital requirements with cash flow from operations,
public offerings of debt, and a senior credit facility. Cash flow from
operations is sensitive to the prices the Company receives for its oil and
natural gas. Reductions in capital spending or an extended decline in oil and
gas prices would result in less than anticipated cash flow from operations
which would likely have a further material adverse effect on the Company.
Proceeds from oil and natural gas sales are received at approximately the same
time that production-related burdens, such as royalties, production taxes and
drilling program obligations, are payable.
Presently, the Company is operating pursuant to the cash collateral
order authorizing the use of cash collateral and the related budget. To the
extent that on-going expenses are for post-petition goods and services after
December 10, 1999, are within the ordinary course of business and are
reflected on the court-approved budget, the Company is permitted to make such
expenditures without further Bankruptcy Court Approval. Any expenditure,
however, that is outside the ordinary course of business or that is not
reflected on the budget, must be specifically authorized by the Bankruptcy
Court.
On January 11, 2000, the Company and its senior secured lender
entered into a cash collateral agreement, which contains certain financial
covenants and provides for weekly payments of interest by the Company at the
rate of prime plus 3.50% per annum (12.5% as of March 31, 2000). On April 5,
2000, the Court entered its Second Final Agreed Order Authorizing use of Cash
Collateral and Granting Adequate Protection. This Order was entered with the
agreement of Christiania, who consented to the Company's continued use of
Christiania's cash collateral in accordance with the terms and conditions set
forth in the Order until May 1, 2000, unless extended by the parties or
further order of the Court after notice and a hearing. Among other things,
the Order provides Christiania new, first priority and senior security
interests in the Company's assets and requires the Company to make weekly
adequate protection payments to Christiania during the term of the Order. The
Order also imposes certain reporting requirements and cash collateral
operating requirements on the Company.
CASH FLOWS
Cash flows provided by operating activities were $3.5 million, $5.3
million, and $15.4 million for the years ended December 31, 1997, 1998 and
1999, respectively. The increases in 1998 and 1999 were primarily attributable
to increased production resulting from the acquisitions, new wells placed on
line as a result of the Company's drilling activities and changes in working
capital. Cash and working capital in 2000 are expected to be provided through
internally generated cash flows and borrowings, if available . See "-Financing
Arrangements" below.
Cash flows used in investing activities by the Company were $15.0
million, $116.3 million and $25.9 million in 1997, 1998 and 1999,
respectively. Property additions through acquisition, exploration and
development activities were the primary reasons for the use of funds in
investing activities. Cash
-27-
flows used in investing activities by the Company for 1997, 1998 and 1999
resulted primarily from the acquisition and development of the Lobo Trend
properties.
Cash flows provided by the Company's financing activities were $11.1
million, $110.7 million and $11.0 million in 1997, 1998 and 1999,
respectively. In 1998, the financing cash flows were primarily from proceeds
from the Senior Notes and borrowings under the Credit Facility. In 1999, the
financing cash flows were primarily proceeds from borrowings under 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 prior credit
facility in place. Approximately $90 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
have had an adverse effect, and would have a further 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.
For the years ended December 31, 1998 and 1999, the Company recorded
impairment provisions on producing properties of $5.4 million and $3.8
million, respectively. The impairment provisions were determined based on an
assessment of recoverability of net property costs from estimated future net
cash flows from those properties. The impairment charge was calculated using
discounted cash flows of proved reserves using prices and costs consistent
with those used for internal decision making purposes. If oil and gas prices
decline in the future, the Company may be required to record further
impairment provisions, which may be material.
The Company has made, and will continue to make, ordinary course
capital expenditures for the development, and exploitation of oil and natural
gas reserves, subject to economic conditions and in accordance with the
rulings and procedures set forth by the Bankruptcy Court. Throughout the
Chapter 11 filing, the Company has operated a one-rig drilling program. In
addition, the Company plans to make capital expenditures in the ordinary
course to enhance current production through workovers, recompletions, and
other production enhancing activities deemed to be economic. See
" - Bankruptcy Proceedings" above.
The Company has currently budgeted approximately $16.1 million in
capital expenditures related to its oil and gas properties in 2000, of which
approximately $15.6 million would be for development and exploitation
activities, and approximately $500,000 would be for delay rentals, lease
bonuses, geological and geophysical costs. Actual amounts to be expended by
the Company for these activities will be dependent upon a number of factors,
including Bankruptcy Court approval, oil and natural gas prices, the
availability of capital, seismic and contract service costs, availability of
drilling rigs and future drilling results. The Company is not contractually
committed to expend the budgeted funds. See " - Capital Expenditures and
Outlook" below.
FINANCING ARRANGEMENTS
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In August 1996, the Company entered into a comprehensive financing
with a limited partnership ("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
canceled, and MHI issued to Cambrian a warrant to acquire 38,671 shares of its
Common Stock at a exercise price of $8.00 per share.
In May 1998, the Company entered into its Credit Facility with
Christiania as lender and administrative agent. 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, the borrowing base effective April 1, 1999, was reduced to $23
million.
The Company was in violation of certain administrative and one
financial covenant under the Credit Facility as of December 31, 1998. The
Company obtained a waiver with respect to those violations from Christiania.
The Company was in violation of certain administrative and one financial
covenant under the Credit Facility as of December 31, 1999. During 1999, the
Company entered into a number of amendments to and waivers under the Credit
Facility, including an amendment requiring the principal amount outstanding to
be decreased by mandatory reductions of $1.5 million per month, beginning
October 31, 1999. The principal reduction amount due on October 31, 1999 was
not paid by the Company, resulting in an additional default under the Credit
Facility. During 1999, Christiania began charging the default rate of interest
as provided for under terms of the Credit Facility. In January 2000, the
Company and Christiania entered into a cash collateral agreement, which
contains certain financial covenants and provides for weekly payments of
interest by the Company. This rate of interest is currently prime plus 3.5%
per annum (12.5% as of March 31, 2000). The cash collateral order has been
extended to expire on May 1, 2000.
The Company granted liens to Christiania on substantially all of the
Company's oil and natural gas properties. The Credit Facility contains a
number of covenants to be complied with by the Company, including limitations
on additional indebtedness and investments, and restrictions on dividends and
other distributions. The Credit Facility also requires the Company to maintain
and comply with certain financial covenants and ratios, including the
maintenance of a minimum interest coverage, a minimum current ratio, and a
limitation on general and administrative expenses.
The Company had $24.3 million of indebtedness outstanding under the
Credit Facility at December 31, 1999. Pursuant to the cross default provisions
contained in the indenture governing the
-29-
Senior Notes and under the Credit Facility, a default under either the Senior
Notes or the Credit Facility constitutes a default under the other instrument.
As such, both the Senior Notes and the Credit Facility have been classified as
current obligations of the Company as of December 31, 1999, as a result of
these events.
See Note 3 of Notes to Consolidated Financial Statements.
11 1/2% SENIOR NOTES DUE 2005
The Indenture governing the Senior Notes 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, create liens, enter into transactions with affiliates,
sell assets or enter into certain mergers and consolidations.
CAPITAL EXPENDITURES AND OUTLOOK
The following table sets forth the Company's capital expenditures for
the three years ended December 31, 1999 (in thousands):
YEAR ENDED DECEMBER 31
--------------------------------------------------------
1997 1998 1999
----------------- ---------------- -----------------
Property acquisition:
Unproved $ 355 $ 15,183 $ 108
Proved 2,425 78,458 -
Development 12,074 25,295 23,767
Interest capitalized 574 1,440 1,413
----------------- ---------------- -----------------
Total costs incurred $ 15,428 $120,376 $25,288
================= ================ =================
The Company currently has budgeted capital expenditures of
approximately $16.1 million for 2000. 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 20 gross
(16 net) wells in 2000. The Company's existing cash and cash flows from
operations will not be sufficient to fund this level of planned capital
expenditures for its existing properties through 2000. The Company will
require additional capital to fund property acquisitions and planned drilling
activities, and access to these markets could be restricted due to the
Bankruptcy proceedings. 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, 1997, 1998, or 1999.
EFFECTS OF INFLATION AND CHANGES IN PRICE
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
-30-
increase (decrease) in the operating costs 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 generally requires 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 Company believes it has completed the necessary modifications to
its internal information computer systems in preparation for the Year 2000.
The Company's Year 2000 project incurred costs of approximately $10,000,
funded by cash from operations. The Company also believes that it has
completed its review of the Year 2000 compliance status of field equipment,
including compressor stations, gas control systems and data logging equipment.
The Company did not experience any significant operational
difficulties or incur any other significant expenses in connection with Year
2000 issues. The Company will continue to monitor all critical systems for
incidents of delayed complications or disruptions and problems encountered
through third parties with whom the Company deals so that they may be timely
addressed.
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 concerning the effects of and potential outcomes from
the Company's Chapter 11 proceeding or other claims against the Company or
its officers and directors, statements regarding the levels of capital
expenditures for 2000 and succeeding periods, the availability of sources of
capital to fund 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 capital, the Company's success in dealing with its creditors,
future governmental regulation, future oil and natural gas reserves, future
drilling and development opportunities and operations, future production of
oil and natural gas (and the prices thereof and costs therefor), anticipated
results of hedging activities, 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)
actions and approvals of the Bankruptcy Court, (ii) the degree of success and
outcome resulting from the Company's negotiations with its creditors, (iii)
factors such as natural gas price fluctuations and markets, uncertainties of
estimates of reserves and future net revenues, the success of the Company's
drilling activities, 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, (iv) the
ability of the Company to obtain other sources of capital to fund its
activities, (v) uncertainties inherert in contested or adversarial
proceedings, (vi) adverse changes to the Company's properties acquired or
developed, (vii) adverse changes in the market for the Company's oil and
natural gas production and (viii)
-31-
those additional factors discussed 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.
All of the forward-looking statements made in this Annual Report on
Form 10-K are qualified by these cautionary statements and there can be no
assurance that the actual results or developments anticipated by the Company
will be realized or, even if substantially realized, that they will have the
expected consequences to or effects on the Company or its business or
operations. Such statements are not guarantees of future performance and
actual results or developments may differ materially from those anticipated in
these statements.
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 72%,
48% and 57% of the Company's production was hedged during the years ended
December 31, 1997, 1998 and 1999, respectively. The Company's weighted average
natural gas price received per Mcf (including the effects of hedging
transactions) was $2.33, $2.07 and $2.28 during the years ended December 31,
1997, 1998 and 1999, respectively. Hedging transactions resulted in a ($0.32),
$0.01 and ($0.04) (reduction) increase in the Company's weighted average
natural gas price received per Mcf in 1997, 1998 and 1999, respectively. The
fair value of these hedging contracts was $(1.1 million), $2.1 million and
$441,000 as of December 31, 1997, 1998, and 1999, respectively.
The Company entered into commodity price hedging contracts with
respect to its gas production for 1999 and 2000 as follows:
-32-
PRICE PER MMBTU
----------------------------------------------
COLLAR
-------------------------------
VOLUME IN
PERIOD MMBTU FLOOR CEILING STRIKE PRICE
-----------------------------------------------------------------------------------------------
January 1999 - April 1999
Put option 600,000 $2.25
Costless Collar 1,800,000 $2.25 $2.99
January 1999 - December 1999
Costless Collar 1,800,000 $2.00 $2.22
Costless Collar 1,800,000 $1.98 $2.22
May 1999 - December 1999
Costless Collar 2,400,000 $2.15 $2.38
Costless Collar 1,200,000 $2.15 $2.36
January 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 were to be 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.
In October 1999, Christiania terminated two costless collar contracts
which hedged a monthly volume of 300,000 MMBtu, with floor prices of $1.98 and
$2.15 and ceiling prices of $2.22 and $2.36, respectively. The termination
cost of approximately $1.3 million was added to the outstanding balance of the
Credit Facility. Gains and losses on hedge contracts terminated prior to
maturity are deferred until the related hedged item is recognized in income.
In January 2000, a third party terminated the remaining hedge
contracts open as of December 31, 1999. The third party is seeking a claim of
approximately $450,000 as a result of the termination of these contracts. The
Company does not concur with the third party's calculation of the amount of
this claim.
Because all of the Company's natural gas hedge contracts have been
terminated as of January 2000, a tabular presentation of the hedge positions
as of December 31, 1999 has not been provided.
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, 2000.
-33-
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, 1999, the Company can not estimate the impact
of SFAS 133 on its future consolidated financial position, results of
operations or cash flows.
The borrowings under the Credit Facility and the value of the Senior
Notes are subject to market fluctuations as influenced by certain economic
factors and events. The interest rate for borrowings under the Credit Facility
is determined based on the Cash Collateral Agreement approved by the
Bankruptcy Court. The interest rate on the outstanding borrowings as of
December 31, 1999 is the Christiania Bank prime rate plus 3.5%. The fair value
of the Credit Facility approximates its market value. The fair value of the
Senior Notes was approximately $97 million and $61 million at December 31,
1998 and 1999, respectively. The effective interest rates for the years ended
December 31, 1998 and 1999 were 12.04% and 11.56%, respectively.
-34-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Accountants...........................................................................36
Consolidated Balance Sheets.................................................................................37
Consolidated Statement of Operations........................................................................38
Consolidated Statement of Stockholder's Deficit.............................................................39
Consolidated Statement of Cash Flows........................................................................40
Notes to Consolidated Financial Statements..................................................................41
-35-
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Michael Petroleum Corporation
(Debtor-in-Possession):
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 (Debtor-in-Possession) at December 31, 1999 and 1998,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States, which require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As described in Note 1 of
the consolidated financial statements, the Company has filed voluntarily under
Chapter 11 of the U. S. Bankruptcy Code, has incurred losses from operations
in 1999 and 1998 and has an accumulated deficit. These matters raise
substantial doubt about the Company's ability to continue a going concern.
Management's plan in regard to these matters is also described in Note 1 to
the consolidated financial statements. The consolidated financial statements
do not include any adjustments that might result from the outcome of this
uncertainty.
PricewaterhouseCoopers LLP
Houston, Texas
April 10, 2000
-36-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
(In thousands of dollars, except share data)
DECEMBER 31,
--------------------------------
1998 1999
-------------- -------------
ASSETS
Current assets:
Cash and cash equivalents $ 430 $ 855
Receivables:
Accrued oil and gas sales 5,362 8,299
Joint interest and other 1,004 443
Notes receivable 1,500 135
Prepaid expenses and other 655 1,375
-------------- -------------
Total current assets 8,951 11,107
Oil and gas properties (successful efforts method), at cost 155,867 181,126
Less: accumulated depletion, depreciation and amortization (24,989) (46,769)
-------------- -------------
130,878 134,357
Deferred income taxes 1,876 -
Other assets 5,577 4,347
-------------- -------------
Total assets $147,282 $149,811
============== =============
LIABILITIES AND STOCKHOLDER'S DEFICIT
Liabilities Not Subject to Compromise:
Current liabilities:
Accounts payable:
Trade $ 7,202 $ 3,023
Revenue distribution 1,723 -
Accrued interest 4,076 240
Accrued liabilities 554 -
Credit Facility and other 41 24,348
-------------- -------------
Total current liabilities 13,596 27,611
Long-term debt 144,842 -
-------------- -------------
Liabilities Subject to Compromise:
Accounts payable:
Trade - 3,633
Revenue distribution - 2,396
Accrued interest - 10,708
Accrued liabilities - 9
Senior Notes - 133,053
-------------- -------------
Total current liabilities subject to compromise - 149,799
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 (11,767) (28,210)
-------------- -------------
Total stockholder's deficit (11,156) (27,599)
-------------- -------------
Total liabilities and stockholder's deficit $147,282 $149,811
============== =============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
-37-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1997 1998 1999
------------- ------------- --------------
Revenues:
Oil and natural gas sales $ 9,139 $ 22,668 $ 34,150
Gain on sale of oil and natural gas properties - 50 -
------------- ------------- --------------
9,139 22,718 34,150
------------- ------------- --------------
Operating expenses:
Production costs 1,870 4,118 5,435
Depletion, depreciation and amortization 3,651 12,620 17,988
Impairment of oil and natural gas properties 238 5,424 3,829
Exploration 333 85 109
Restructuring costs - - 792
Reorganization costs - - 721
General and administrative 980 1,802 2,178
------------- ------------- --------------
7,072 24,049 31,052
------------- ------------- --------------
Operating income (loss) 2,067 (1,331) 3,098
------------- ------------- --------------
Other income (expense):
Interest income and other 46 235 (1,459)
Interest expense and other (2,109) (12,281) (16,206)
------------- ------------- --------------
(2,063) (12,046) (17,665)
(Loss) income before income taxes and extraordinary item 4 (13,377) (14,567)
Provision (benefit) for income taxes 11 (4,667) 1,876
------------- ------------- --------------
Loss before extraordinary item (7) (8,710) (16,443)
Extraordinary item - extinguishment of T.E.P. Financing,
net of tax of $285
- (531) -
------------- ------------- --------------
Net loss $ (7) $(9,241) $(16,443)
============= ============= ==============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
-38-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENT OF STOCKHOLDER'S DEFICIT
For the years ended December 31, 1997, 1998 and 1999
(In thousands of dollars, except per share data)
COMMON STOCK
-------------------------
ADDITIONAL
PAID-IN ACCUMULATED
SHARES AMOUNT CAPITAL DEFICIT TOTAL
--------- ---------- ------------ ------------- ------------
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)
Net loss (16,443) (16,443)
--------- ---------- ------------ ------------- ------------
Balance December 31, 1999 10 $1 $610 $(28,210) $(27,599)
========= ========== ============ ============= ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
-39-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands of dollars)
YEAR ENDED DECEMBER 31,
------------------------------------------
1997 1998 1999
------------ ----------- -----------
Cash flows from operating activities:
Net loss $ (7) $ (9,241) $(16,443)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depletion, depreciation and amortization 3,651 12,620 17,988
Impairment of oil and natural gas properties 238 5,424 3,829
Allowance for bad debts - - 1,500
Deferred income taxes 11 (4,952) 1,876
Extraordinary item - extinguishment of T.E.P. Financing, net
of taxes - 470 -
Gain on sale of oil and gas properties - (50) -
Abandonment of oil and gas properties 249 35 -
Amortization of debt and bond issuance costs - 619 816
Amortization of deferred loss on early termination of
commodity swap Agreements - 712 1,003
Amortization of discount on debt 131 205 244
Changes in assets and liabilities:
Accounts receivable - accrued oil and gas sales (2,333) (1,370) (2,937)
Accounts receivable - joint interest and other 562 (514) 561
Prepaid expenses and other 72 (1,236) (9)
Accounts payable - trade 710 (1,769) (89)
Accounts payable - revenue distribution 296 (32) 673
Accrued interest (121) 3,813 6,872
Accrued liabilities 7 518 (545)
------------ ----------- -----------
Net cash provided by operating activities 3,466 5,252 15,339
------------ ----------- -----------
Cash flows from investing activities:
Additions to oil and gas properties (14,963) (114,978) (25,739)
Proceeds from sale of oil and gas properties - 150 -
Issuance of notes receivable - (1,500) (135)
------------ ----------- -----------
Net cash used in investing activities (14,963) (116,328) (25,874)
------------ ----------- -----------
Cash flows from financing activities:
Proceeds from long-term debt 14,238 145,603 11,000
Payments on long-term debt (3,114) (29,314) (40)
Additions to deferred loan costs (26) (5,565) -
------------ ----------- -----------
Net cash provided by financing activities 11,098 110,724 10,960
------------ ----------- -----------
Net increase (decrease) in cash and cash equivalents (399) (352) 425
Cash and cash equivalents, beginning of period 1,181 782 430
------------ ----------- -----------
Cash and cash equivalents, end of period $ 782 $ 430 $ 855
============ =========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
-40-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
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 96% and 87% of the Company's
proved reserves at December 31, 1999 and 1998, respectively.
CHAPTER 11 BANKRUPTCY FILING AND LIQUIDITY
Effective on December 10, 1999, the Company, MHI and certain of its
subsidiaries entered into the Voting Agreement with certain holders of the
Company's Senior Notes for a consensual joint plan of reorganization of
the Company (the "Plan"). The terms of the Voting Agreement contemplated
that the Plan would provide for a sale of the Company or its assets in
court-supervised proceedings under the Bankruptcy Code. The Voting
Agreement also contemplated that the Company and its subsidiaries would
continue to operate as debtors-in-possession subject to the supervision
of the Bankruptcy Court, and that the Plan would provide for the payment
of all trade creditors' claims as and when they come due in the ordinary
course or in full on the effective date of the Plan. On December 10,
1999, the Company, MHI and certain of its subsidiaries filed petitions
for relief under Chapter 11 of the Bankruptcy Code in Bankruptcy Court.
The bankruptcy petitions were filed in order to give the Company an
opportunity to conserve its cash and restructure its debt. Since
December 10, 1999, the Company, MHI and the filing subsidiaries have
operated as debtors-in-possession under the Bankruptcy Code. The Company
has curtailed its developmental drilling program, limiting expenditures
to a one-rig drilling program. No trustee or examiner has been appointed
and the Company, MHI and these subsidiaries are paying their postpetition
obligations (except those subject to Bankruptcy Court approval) as they
become due. See also discussion of cash collateral agreement with
Christiania at Note 3.
41
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Voting Agreement provided that the obligations of the parties thereto
may terminate upon a "Termination Event," which included any failure under
the marketing process to timely achieve certain milestones, including the
receipt of at least one final bid by March 17, 2000 in an amount equal to
at least $120 million, as adjusted for certain costs and working capital
items. Although the Company received several bids, as of March 17, 2000,
the Company had not received a final bid in such an amount sufficient to
meet this requirement.
The accompanying financial statements have been prepared on a going
concern basis which contemplates continuity of operations, realization of
assets and liquidation of liabilities in the ordinary course of business.
As a result of the bankruptcy filing and related events, there is no
assurance that the carrying amounts of assets will be realized or that
liabilities will be liquidated or settled for the amounts recorded. In
addition, a plan of reorganization, or rejection thereof, could change
the amounts reported in the financial statements. As a result, there is
substantial doubt about the Company's ability to continue as a going
concern. The ability of the Company to continue as a going concern is
dependent upon confirmation of a plan of reorganization, adequate sources
of capital and the ability to sustain positive results of operations and
cash flows sufficient to continue to explore for and develop oil and gas
reserves.
In the ordinary course of business, the Company makes substantial capital
expenditures for the exploration and development of oil and natural gas
reserves. Historically, the Company has financed its capital expenditures,
debt service and working capital requirements with cash flow from
operations, public offerings of debt and a senior credit facility. Cash
flow from operations is sensitive to the prices the Company receives for
its oil and natural gas. A reduction in planned capital spending or an
extended decline in oil and gas prices could result in less than
anticipated cash flow from operations, which would likely have a further
material adverse effect on the Company.
Management's plan is to continue the marketing and sale of the Company or
its assets or reorganize the capital structure of the Company. The Company
and its advisors have continued to negotiate with the holders of the
Senior Notes and with prospective purchasers for a consensual plan of
reorganization.
The Company expects to file a plan and related disclosure statement with
the Bankruptcy Court in April 2000. In addition to the approval of the
Bankruptcy Court, the consummation of the plan will be subject to the
consent of the requisite number and amount of certain of the Company's
creditors. At this time, it is not possible to predict the outcome of
the bankruptcy proceedings, the effect on the Company's business or
on the interests of its creditors, royalty owners or stockholders or
whether certain executory contracts will be assumed or rejected. As a
result of the bankruptcy filing, certain of the Company's liabilities
are subject to compromise. Through December 31, 1999, the Company has
incurred expenses of approximately $1.5 million which consisted of
approximately $792,000 pertaining to restructuring costs (consisting
principally of investment banking, legal and professional fees) and
approximately $721,000 pertaining to the bankruptcy proceedings (legal,
professional and other fees).
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 one financial institution. The Company periodically assesses the
financial condition of the institutions and believes that any possible
credit risk is minimal.
OIL AND GAS PROPERTIES
-42-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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. Impairment charges calculated are based on
discounted cash flows determined based on proved reserves using prices
and costs consistent with those used for internal decision making
purposes.
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, 1998 and 1999.
OTHER ASSETS
Other assets include loan origination costs which are amortized on a
straight-line basis over the term of the related obligation. In addition,
the non-current portion of the unamortized hedging termination costs are
included in other assets. Gains and losses on hedge contracts terminated
prior to maturity are deferred until the related hedged item is recognized
in income.
-43-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INCOME TAXES
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.
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
other than as described in Note 8.
-44-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts reported in the balance sheet for cash and cash
equivalents, receivables, and accounts payable other than those subject
to compromise approximate their fair value. The fair value of the Company's
long-term debt and derivative financial instruments are estimated using
current market quotes. Due to the bankruptcy filing (see Note 1), the
Company is uncertain as to the timing and amount of liquidation or
settlement of liabilities subject to compromise. Accordingly, except for
debt which has quoted market prices, the Company does not believe it is
practicable to estimate the fair value of those liabilities.
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 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
-45-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Loss from continuing operations (1,465) (9,375)
3. DEBT:
Debt consisted of the following (in thousands):
DECEMBER 31,
-------------------------------
1998 1999
-------------- --------------
11 1/2% Senior Notes due 2005 (subject to compromise) $135,000 $135,000
Credit Facility 12,000 24,315
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 65 33
Note payable to an individual, payable monthly, interest at 8%, due
February 2000, unsecured 9 1
-------------- --------------
147,074 159,349
Unamortized original issue discount on Senior Notes (2,191) (1,948)
-------------- --------------
Total debt 144,883 157,401
Less: current portion (41) (157,401)
-------------- --------------
Long-term debt $144,842 $ -
============== ==============
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
rates under the Senior Notes for the years ended December 31, 1998 and 1999
was 12.0% and 11.6%, respectively. 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
estimated fair value of the Senior Notes was $97 million and $61 million at
December 31, 1998 and 1999, respectively. As the Senior Notes are unsecured
obligations subject to compromise under the Bankruptcy proceeding,
beginning December 10, 1999, the Company discontinued accruing interest
under the Indenture which would
-46-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
have been approximately $936,000 through December 31, 1999. An interest
payment on the Senior Notes of approximately $7.8 million was due on
October 1, 1999, but was not paid by the Company. A 30-day grace period
under the Indenture governing the Senior Notes expired on October 31,
1999 without payment of interest on the Senior Notes, and, as a result,
an event of default occurred under the Indenture. The Indenture provides
that in the event of an event of default, the entire indebtedness under
the Senior Notes may be declared due and payable.
Under the cross default provisions contained in the Indenture governing
the Senior Notes and in the Credit Facility described below, a default
under either the Senior Notes or the Credit Facility constituted a
default under the other instrument (see Note 1 discussing bankruptcy
proceedings). Consequently, balances outstanding under the Senior Notes
and Credit Faciltiy have been classified as current liabilities as of
December 31, 1999.
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.
-47-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
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 initial terms of 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 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. The principal
balance outstanding was due and payable on May 28, 2002, and each letter of
credit was to be reimbursable by the Company when drawn, or if not then
otherwise reimbursed, paid pursuant to a loan under the Credit Facility.
Effective April 1, 1999, the new borrowing base was reduced to $23 million
and certain terms of the Credit Faciltiy were amended. 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 was not only to 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. The Company did not make the $1.5
million principal payment due October 31, 1999, which constituted an event
of default under the Credit Facility.
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 and pending a stay by
the bankruptcy court, either repay such excess in full or provide
additional collateral acceptable to Christiania.
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%. Due to violations of certain covenants
during 1999, Christiania began charging the default rate of interest which
was prime plus 3.5% per annum. The effective interest rates under the
Credit Facility for the years ended December 31, 1998 and 1999 was 6.8% and
9.3%, respectively. 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
-48-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
proceeds of the Credit Facility were used for general corporate purposes.
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
obtained a waiver with respect to those violations from Christiania, which
agreed not to assert any default based on such violations. The Company and
Christiania also amended certain financial covenants. The Company was in
violation of certain administrative and two financial covenants of the
Credit Facility as of December 31, 1999.
On January 11, 2000, the Company and Christiania entered into a cash
collateral agreement, which contains certain financial covenants and
provides for weekly payments of interest by the Company. The cash
collateral agreement modified the previous financial covenants which
were in violation at December 31, 1999, but did not modify the
administrative covenants which the Company had violated. On April 5,
2000, the Court entered its Second Final Agreed Order Authorizing use of
Cash Collateral and Granting Adequate Protection. This Order was entered
with the agreement of Christiania, who consented to the Company's
continued use of Christiania's cash collateral in accordance with the
terms and conditions set forth in the Order until May 1, 2000, unless
extended by the parties or further order of the Court after notice and a
hearing. Among other things, the Order provides Christiania new, first
priority and senior security interests in the Company's assets and requires
the Company to make weekly adequate protection payments to Christiania
during the term of the Order. The Order also imposes certain reporting
requirements and cash collateral operating requirements on the Company.
4. FEDERAL INCOME TAXES:
The components of the net deferred taxes are as follows (in thousands):
DECEMBER 31,
----------------------
1998 1999
------- -------
Deferred tax assets:
Net operating loss carryforward $ 6,613 $10,392
Other 46 52
------- -------
Total deferred tax asset 6,659 10,444
------- -------
Deferred tax liabilities:
Oil and gas properties (4,774) (3,198)
Other (9) (18)
------- -------
Total deferred tax liability (4,783) (3,216)
------- -------
Valuation allowance (7,228)
------- -------
Net deferred taxes $ 1,876 $ -0-
======= =======
Income tax expense was $1.9 million for the year ended December 31, 1999 as
a full valuation allowance was recorded by the Company for the net deferred
tax assets which existed at December 31, 1999. The net deferred asset as
December 31, 1998 of $1.9 million was recorded based on management's belief
that it was
-49-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
more likely than not that future taxable income, which included the
effect of certain tax planning strategies, would be sufficient to fully
utilize existing net operating losses prior to expiration. However, a
portion of the net operating loss carryforward (approximately $30.6
million as of December 31, 1999) was reserved as of December 31, 1999 as
the status of the current and future drilling program and uncertainty
about the availability of capital resulted in uncertainty as to whether
sufficient taxable income will be available to utilize the entire net
operating loss carryforward. Any restructuring of the Company's
indebtedness may result in a significant stock ownership change which
would significantly affect the timing of the utilization of the net
operating loss carryforward. The valuation allowance related to tax
assets could be adjusted in the future due to changes in estimates of
future taxable income and the outcome of the Bankruptcy proceedings.
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,
--------------------------------------------
1997 1998 1999
------------ ------------ -------------
Computed statutory tax (benefit) expense at 34% $1 $(4,826) $(4,953)
Changes in taxes resulting from:
Valuation allowance - - 7,228
Permanent differences 10 (11) (14)
Other - (115) (385)
------------ ------------ -------------
Total income tax expense (benefit) $11 $(4,952) $1,876
============ ============ =============
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 72%, 48%
and 57% of the Company's production was hedged during the years ended
December 31, 1997, 1998 and 1999, respectively. The Company's weighted
average natural gas price received per Mcf (including the effects of
hedging transactions) was $2.33, $2.07 and $2.28 during the years ended
December 31, 1997, 1998 and 1999, respectively. Hedging transactions
resulted in a ($0.32), $0.01 and ($0.04) (reduction) increase in the
Company's weighted average natural gas price received per Mcf in 1997, 1998
and 1999, respectively. The unrealized gain (loss) related the hedging
contracts was ($1.1) million, $2.1 million and $441,000 as of December 31,
1997, 1998 and 1999, respectively.
-50-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
------------------------- ----------- -------- --------- --------------
January 1999 - April 1999
Put option 600,000 $2.25
Costless Collar 1,800,000 $2.25 $2.99
January 1999 - December 1999
Costless Collar 1,800,000 $2.00 $2.22
Costless Collar 1,800,000 $1.98 $2.22
January 1999 - December 1999
Costless Collar 2,400,000 $2.15 $2.38
Costless Collar 1,200,000 $2.15 $2.36
January 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.
In October 1999, Christiania terminated two costless collar contracts which
hedged a monthly volume of 300,000 MMBtu, with floor prices of $1.98 and
$2.15 and ceiling prices of $2.22 and $2.36, respectively. The termination
cost of approximately $1.3 million was added to the outstanding balance of
the Credit Facility. Gains and losses on hedge contracts terminated prior
to maturity are deferred until the related hedged item is recognized in
income.
In January 2000, a third party terminated the remaining hedge contracts
open as of December 31, 1999. The third party is seeking a claim of
approximately $450,000 as a result of the termination of these contracts.
The Company does not concur with the third party's calculation of the
amount of the claim.
-51-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Because the Company's natural gas hedge contracts have been terminated as
of January 2000, a tabular presentation of the hedge positions as of
December 31, 1999 has not been provided.
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. As of December 31, 1999, MHI granted, at exercise
prices in excess of the fair market value per share, options covering a
total of 15,000 shares to two employees 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. As of December
31, 1999, the following is a summary of all stock options activity for 1998
and 1999. The Company did not have a stock option plan in 1997.
NUMBER OF WEIGHTED
SHARES AVERAGE
UNDERLYING EXERCISE
OPTIONS PRICE
-------------- ------------
Outstanding at December 31, 1997 - -
Granted 73,350 $ 78.35
Exercised - -
Expired - -
Forfeited - -
-------------- ------------
Outstanding at December 31, 1998 73,350 $ 78.35
============== ============
Granted 15,100 $ 78.35
Exercised - -
Expired (8,632) 78.35
Forfeited (17,268) 78.35
-------------- ------------
Outstanding at December 31, 1999 62,550 $ 78.35
============== =============
At December 31, 1998 and 1999, the Company had an additional 120,650 and
131,550 shares, respectively 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.
-52-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average fair value of options granted during 1998 and 1999
was $18.12 and $17.31, respectively.
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 and 1999: no dividend
yield; expected volatility of 0.00%; risk-free interest rates ranging from
5.1% to 5.4% and an expected option life of 5 years.
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1999:
WEIGHTED
WEIGHTED AVERAGE WEIGHTED
AVERAGE REMAINING AVERAGE
OPTIONS EXERCISE EXERCISE CONTRACTUAL OPTIONS EXERCISE
OUTSTANDING PRICE PRICE LIFE EXERCISABLE PRICE
----------------- ---------------- ---------------- ---------------- ---------------- ----------------
62,550 $ 78.35 $ 78.35 8.69 15,848 $ 78.35
Exercisable stock options and weighted average exercise prices at December
31, 1998 follow.
WEIGHTED
AVERAGE
OPTIONS EXERCISE
EXERCISABLE PRICE
--------------- ------------
December 31,1998 - -
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 or 1999.
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 and 1999
would have approximated the pro forma amount below (in thousands):
YEAR ENDED YEAR ENDED
DECEMBER 31, 1999 DECEMBER 31, 1998
--------------------- ---------------------
Net loss - as reported $ (16,443) $ (9,241)
Net loss - pro forma $ (16,677) $ (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
-53-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $-0-, $18,000 and $26,000 for the
years ended December 31, 1997, 1998 and 1999, respectively.
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, 2000. 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, 1999, 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 CEO 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
2. 20,001 to 40,000 $0.02/MMbtu
3. All volumes over 40,000 $0.01/MMbtu
-54-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Sales Agreement is effective for a one-year period and is renewable
automatically for successive one-year periods thereafter.
Marketing fees paid to Upstream were approximately $220,000, $253,000 and
$278,000 for the years ended December 31, 1997, 1998 and 1999,
respectively. During the years ended December 31, 1997, 1998 and 1999,
Upstream purchased gas produced by the Company for approximately $9.7
million, $20.8 million and $32.2, respectively. At December 31, 1998 and
1999, receivables from Upstream of approximately $5.2 million and $7.8
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. Substantially all of the Company's operated oil
and natural gas is sold to three customers.
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, 1997, 1998 and 1999,
the Vice President - Geosciences received from the Company approximately
$105,000, $275,000 and $433,000, 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
1999, the Company loaned $135,000 to its Chairman and CEO. The note is
unsecured, due on demand, and bears interest at 10%.
In December 1998, the Company loaned $1.5 million (at interest bearing 12%
per annum) to a Texas limited liability company that participated in the
drilling of natural gas wells in Northern Mexico. The note became past due
on December 15, 1999 and this receivable has been fully reserved by the
Company.
9. SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for interest are as follows (in thousands):
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
-------- -------- --------
Interest payments (net of interest capitalized of $574, $1,440
and $1,413, during 1997, 1998, and 1999, respectively) $1,626 $7,677 $8,275
Non-cash investing and financing transactions not reflected in the
statement of cash flows include the following (in thousands):
-55-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
-------- -------- --------
Changes in accounts payable related to capital expenditures $465 $5,225 $457
Increase of oil and gas properties due to recognition of deferred
Tax liabilities from acquired properties - 1,285 -
10. COMMITMENTS AND CONTINGENCIES:
LEASES
The Company has entered into two noncancelable operating lease agreements
for office space in Houston, Texas and Laredo, Texas. The lease terms
expire in 2004, with two options to renew the lease for a period of five
years each for the Houston office lease. Future minimum lease payments
required as of December 31, 1999 related to noncancelable operating leases
are as follows (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------
2000 $180
2001 194
2002 201
2003 152
2004 74
----------
$801
==========
Rent expense for the years ended December 31, 1997, 1998 and 1999 was
approximately $69,000, $154,000 and $193,000, respectively.
LEGAL PROCEEDINGS
On December 10, 1999, the Company, MHI, and certain of its subsidiaries
filed petitions for relief under Chapter 11 of the Bankruptcy Code in order
to facilitate the restructuring of the Company's liabilities. The Company
continues to operate as a debtor-in-possession subject to the Bankruptcy
Court's supervision and orders. The filing was made in the U.S. Bankruptcy
Court for the Southern District of Texas, Laredo Division.
On March 27, 2000, the Company received a demand letter from a royalty
owner. The demand letter challenges certain deductions used by the Company
to calculate prices for oil and gas royalties. The Company believes that it
has substantial defenses to this claim and intends to vigorously assert
such defenses. However, the investigation into this claim is in its early
phases and the potential range of loss, if any, cannot presently be
determined by the Company.
-56-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 31, 2000, the Company received correspondence from counsel to the
Official Committee of Unsecured Creditors requesting the Company to take
legal action on behalf of the Company's Estate against Glenn D. Hart,
Michael G. Farmar and the directors of Company, alleging certain
misstatements in connection with the issuance of the Senior Notes and
certain breaches of fiduciary duties to the creditors. The Company is
currently evaluating the claims made under these allegations, but currently
knows of no basis for their assertion.
In addition to the matters noted above, 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,
1999, there were no threatened or pending legal matters, other than the
matters noted above, which would have a material impact on the Company's
consolidated financial position, results of operations or cash flows.
EMPLOYEE RETENTION PLAN
On March 27, 2000, the Bankruptcy Court approved an Employee Retention
Bonus Plan. Under the terms of the Employee Retention Bonus Plan, eligible
employees are entitled to a bonus equal to three months salary if the
employee remains employed with the Company through the effective date of
the plan of reorganization. The estimated cost of the Employee Retention
Bonus Plan is approximately $400,000.
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 ranges from $0.11 to $0.17 per Mcf for compression,
transportation and dehydration.
11. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(Unaudited):
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
-57-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31,
-------------------------
1998 1999
---------- ----------
Unproved oil and gas properties $ 14,496 $ 12,107
Proved oil and gas properties 140,490 168,059
Other 881 960
---------- ----------
155,867 181,126
Accumulated depreciation, depletion and amortization (24,989) (46,769)
---------- ----------
$130,878 $134,357
========== ==========
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,
------------------------------------
1997 1998 1999
---------- ---------- ---------
Property acquisition:
Unproved $ 355 $ 15,183 $ 108
Proved 2,425 78,458 -
Development 12,074 25,295 23,767
Interest capitalized 574 1,440 1,413
---------- ---------- ---------
Total costs incurred $ 15,428 $120,376 $25,288
========== ========== =========
OIL AND GAS RESERVE QUANTITIES
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 and evolving production
history. Continual reassessment of the viability of production under
varying economic conditions requires additional capital, the source of
which is unclear due in part to the Company's operations under Chapter
11 bankruptcy proceedings. 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
and could result in different estimates of proved reserve quantities and
related future net cash flows.
-58-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The reserve information as of December 31, 1999 was prepared by Netherland
Sewell and Associates, Inc. The reserve information as of December 31, 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, 1999 is believed to have caused a material change in the
estimates of proved or proved developed reserves as of that date.
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, 1999:
CRUDE OIL NATURAL GAS
(MBBL) (MMCF)
------------ ------------
Proved developed and undeveloped reserves:
January 1, 1997 239 49,246
Extensions, discoveries and other additions. 70 9,105
Production (21) (3,685)
Purchases of reserves in place 15 3,347
Revision of previous estimates (38) (6,848)
------------ ------------
December 31, 1997 265 51,165
------------ ------------
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
Revision of previous estimates (144) (15,128)
------------ ------------
December 31, 1998 4,923 189,753
------------ ------------
Extensions, discoveries and other additions. 108 17,511
Production (116) (14,122)
Sales of minerals in place - -
Purchases of reserves in place - -
Revision of previous estimates (3,500) (7,490)
------------ ------------
December 31, 1999 1,415 185,652
============ ============
-59-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CRUDE OIL NATURAL GAS
(MBBL) (MMCF)
------------ ------------
Proved developed reserves:
December 31, 1996 79 16,924
December 31, 1997 108 22,937
December 31, 1998 904 54,277
December 31, 1999 421 63,239
-60-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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):
AS OF DECEMBER 31,
----------------------------------------------
1997 1998 1999
------------- ------------- -------------
Future cash inflows $115,766 $396,091 $466,002
Less related future:
Production costs (1) (20,226) (74,723) (124,873)
Development costs (17,295) (92,504) (86,349)
Income tax expense (22,497) (38,182) (44,352)
------------- ------------- -------------
Future net cash flows 55,748 190,682 210,428
10% annual discount for estimating timing of cash flows (19,109) (80,172) (100,299)
------------- ------------- -------------
Standardized measure of discounted future net cash flows $ 36,639 $110,510 $110,129
============= ============= =============
(1) The increase in production costs from the year ended December 31, 1999
compared to December 31, 1998 was primarily related to longer economic
lives of certain natural gas wells, higher estimated severance taxes, and
higher estimated lease operating expenses.
-61-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
-------------------------------------------------
1997 1998 1999
--------------- -------------- -------------
Beginning of the period $42,349 $ 36,639 $110,510
Revisions of previous estimates:
Changes in prices and costs (9,701) (8,241) 33,469
Changes in quantities (12,789) (19,637) (31,243)
Development costs incurred during the period 1,836 2,400 4,900
Additions to proved reserves resulting from extensions
and discoveries, less related costs 11,172 31,001 12,311
Purchases of reserves in place 3,894 83,040 -
Sales of reserves in place - (729) -
Accretion of discount 6,073 5,149 13,264
Sales of oil and gas, net of production costs (7,269) (18,262) (29,023)
Net change in income taxes 3,530 (7,280) (1,084)
Production timing and other (2,456) 6,430 (2,975)
--------------- -------------- -------------
Net increase (decrease) (5,710) 73,871 (381)
--------------- -------------- -------------
End of the period $36,639 $110,510 $110,129
=============== ============== =============
-62-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 43 Chairman of the Board and Chief Executive Officer
Michael G. Farmar 42 President, Chief Operating Officer and Director
Jerry F. Holditch 42 Vice President-Geosciences and Director
Douglas R. Fogle 44 Vice President-Engineering
Robert L. Swanson 42 Vice President-Finance
Sarah Ruddock 40 Vice President-Land
Scott R. Sampsell 43 Vice President, Controller, Treasurer and Secretary
Jim R. Smith 60 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
-63-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
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 has a
B.B.A. in Accounting from Texas Tech University and is a Certified Public
Accountant, a member of the American Institute of Certified Public Accountants
and the Texas Society of Certified Public Accountants.
Sarah Ruddock joined the Company in 1994 and was promoted to Land
Manager in 1995 and Vice President - Land in 1999. Prior to 1994, Ms. Ruddock
served as Director of Supply for National Gas Resources, Inc. She has also
worked for Gulf Oil Corp. as a natural gas trader and as a U.S. Gulf Coast
Landman. Ms. Ruddock is a graduate of the University of Texas at Austin where
she received a B.B.A. in Petroleum Land Management. Ms. Ruddock is a Certified
Professional Landman and a member of the Houston Association of Professional
Landmen and the American Association of Professional Landmen.
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.
During October 1999, two directors of the Company, Bryant H. Patton
and Jack I. Tompkins, resigned.
-64-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1998 and 1999.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
----------------------------
401K STOCK ALL OTHER
CONTRI- OPTIONS COMPEN-
PRINCIPAL POSITIONS SALARY BONUS BUTIONS GRANTED SATION
- ------------------------------------------------------- ------------- ------------- ------------- ------------- -------------
GLENN D. HART
Chairman of the Board and Chief Executive
Officer
1999 $270,000 $-0- $5,000 -0- $10,552 (1)
1998 $238,500 $202,500 $3,038 -0- $10,553 (1)
1997 $144,000 $6,000 -0- -0- $11,303 (1)
MICHAEL G. FARMAR
President and Chief Operating Officer
1999 192,000 -0- $5,015 -0- -0-
1998 165,000 135,000 $2,160 -0- -0-
1997 84,000 3,500 -0- -0- -0-
JERRY F. HOLDITCH
Vice President-Geosciences
1999 112,000 -0- $3,220 -0- 432,885 (2)
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
1999 105,950 4,183 $3,167 -0- -0-
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
1999 84,850 7,283 $2,546 -0- -0-
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 pursuant to certain
overriding royalty interests granted to him.
-65-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
No options were issued to or exercised by the Named Executive Officers in
1997, 1998 or 1999.
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, 1999, a total of 62,550 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, 1997, 1998 and 1999, Mr. Holditch
received from the Company $104,946, $274,690 and $432,885, 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
-66-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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
-67-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
administers the compensation plans for the Company's executive officers and
directors. The members of the Audit Committee are Messrs. Farmar and Smith.
The only member of the Compensation Committee is Mr. Smith.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of December 31, 1999, (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
NAME OF PERSON OR GROUP OWNED(1) PERCENTAGE OF 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%
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 719,725 93.0%
(1) Except as otherwise noted, the named shareholder has sole voting,
investment and dispositive power.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In December 1999, the Company loaned $135,000 to its Chairman and
Chief Executive Officer. The note is unsecured, due on the earlier to occur
of June 1, 2000 or demand by the Company, and bears interest at 10% per annum.
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, 1997, 1998 and 1999, the Company paid Upstream or its predecessor
marketing fees of $220,000, $253,000 and $278,000, 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 received dividends of $6,000 in
the year ended December 31, 1997. 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.
-68-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 as $87,500 plus approximately $3,000 in carrying fees. In addition,
pursuant to the agreement, Mr. Hart reserved a 1% overriding royalty interest.
No royalties were paid in 1998 or 1999.
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 SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
See Index on page 35.
2. Financial Statement Schedules
None.
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MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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* Natural Gas Marketing, Transportation and processing Agreement
dated as of November 1, 1998 by and between the Company and
Upstream Energy Services Company.
10.15** First Amendment to Credit Agreement dated March 29, 1999 among
the Company, Christiania and the lenders named therein.
10.16** Letter Agreement dated March 30, 1999 between the Company and
Christiania.
10.17*** Second Amendment to Credit Agreement dated August 1, 1999 among
the Company and Christiania.
10.18*** Promissory Note Dated December 9, 1999 from Glenn D. Hart and the
Company.
10.19 Voting Agreement dated as of December 10, 1999 by and among the
Company, MHI, certain of the Company's subsidiaries and certain
holders of the Company's Senior Notes (filed as Exhibit 10.1 to
the Company's current report on Form 8-K dated December 13, 1999
and incorporated herein by reference.
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.
** Previously filed as an Exhibit with corresponding Exhibit
number) to the Company's Annual Report on form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference.
*** Filed herewith.
-70-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(b) Reports on Form 8-K.
In October 1999, the Company filed a Current Report on Form 8-K dated
October 6, 1999 under Item 5. "Other Events" concerning the Company's
presentation to certain holders of its Senior Notes.
In November 1999, the Company filed a Current Report on Form 8-K dated
November 1, 1999 under Item 5. "Other Events" reporting the Company's
failure to pay the interest payment on its Senior Notes due on October
1, 1999 following a 30-day grace period.
In December 1999, the Company filed a Current Report on Form 8-K dated
December 13, 1999, under Item 3. - "Bankruptcy or in Receivership"
reporting the filing of the petitions for relief under Chapter 11 of
the Bankruptcy Code.
(c) Exhibits required by Item 601 of Regulation S-K
See (a) 3. - "Exhibits" above of this Item 14.
-71-
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.
Dated: April 10, 2000 MICHAEL PETROLEUM CORPORATION
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.
-72-
MICHAEL PETROLEUM CORPORATION
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 10th 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
/s/ JIM R. SMITH Director
- ------------------------------------------------------
Jim R. Smith
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