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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
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[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required)
For the fiscal year ended December 31, 1995
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (No Fee Required)
Commission File Number 1-10874
MESA Inc.
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(Exact Name of Registrant as Specified In Its Charter)
Texas 75-2394500
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(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Number)
1400 Williams Square West
5205 North O'Connor Boulevard
Irving, Texas (214) 444-9001 75039-3746
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(Address of Principal (Registrant's (Zip Code)
Executive Offices) Telephone Number)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common stock, $.01 par value........................ New York Stock Exchange
Preferred Stock Purchase Rights......................New York Stock Exchange
13-1/2% Subordinated Notes due May 1, 1999.......... New York Stock Exchange
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
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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]
Number of shares outstanding as of the close of business on March 6,
1996: 64,050,009.
Aggregate market value of 56,833,524 shares held by non-affiliates of
Registrant at the closing price on March 6, 1996, of $2.875: approximately
$163.4 million.
DOCUMENTS INCORPORATED BY REFERENCE
None
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TABLE OF CONTENTS
PART I
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 8. Consolidated Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Signatures
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PART I
Item 1. Business
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The Company
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MESA Inc. is one of the largest independent oil and gas companies in the
United States and considers itself one of the most efficient operators of
domestic natural gas producing properties and natural gas processing
facilities. MESA has been publicly traded since 1964 and is primarily in the
business of exploring for, developing, producing, processing and selling
natural gas and oil in the United States.
As of December 31, 1995, MESA owned approximately 1.9 trillion cubic feet
of equivalent proved natural gas reserves ("Tcfe"). Approximately 65% of MESA's
total equivalent proved reserves is natural gas and the balance is principally
natural gas liquids ("NGLs"), which are extracted from natural gas through
processing plants. Substantially all of MESA's proved reserves are proved
developed reserves. Quantities stated as equivalent natural gas reserves are
based on a factor of six thousand cubic feet ("Mcf") of natural gas per barrel
("Bbl") of liquids. See "-- Reserves."
MESA's principal business strategies include (i) maximizing the value of
its existing high-quality, long-life reserves through efficient operating and
marketing practices, (ii) processing natural gas to extract value-added
products such as NGLs and helium, (iii) conducting selective exploratory and
development activities, principally in existing areas of operations, (iv)
making acquisitions of producing properties with exploration and development
potential in areas where MESA has operating experience and expertise, (v)
generating value and cash flow from investments in natural gas and other energy
futures contracts, and (vi) promoting the use of compressed and liquefied
natural gas as a transportation fuel.
MESA Inc. (the "Company") is a holding company and conducts its operations
through its subsidiaries. Unless the context otherwise requires, the term
"MESA" means the Company and its subsidiaries taken as a whole and includes the
Company's predecessors, Mesa Limited Partnership (the "Partnership") and Mesa
Petroleum Co. ("Original Mesa"). MESA maintains its principal offices at 1400
Williams Square West, 5205 North O'Connor Boulevard, Irving, Texas 75039-3746,
where its telephone number is (214) 444-9001. At December 31, 1995, MESA
employed 385 employees.
Financial Condition, Liquidity and Exploration of Strategic Alternatives
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MESA has a highly leveraged capital structure with long-term debt,
including current maturities, totaling approximately $1.2 billion at December
31, 1995. MESA's current financial forecasts indicate, assuming no changes in
capital structure and no significant transactions are completed, that cash
generated by operating activities, together with available cash and investment
balances, will not be sufficient to make all of its required debt principal and
interest obligations due in June 1996.
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In an effort to address its liquidity issues, MESA's Board of Directors
(the "Board") approved a proposal solicitation process which started in late
1994 and was expanded in mid-1995. The process has included solicitation of
proposals for a sale of MESA, a stock-for-stock merger, joint ventures, asset
sales, equity infusions, and refinancing transactions.
On February 28, 1996, MESA signed a letter of intent with Rainwater, Inc.
("Rainwater"), an independent investment company owned by Ft. Worth, Texas,
investor Richard Rainwater, to raise $265 million of equity in connection with
a refinancing of MESA's debt. The transaction, more fully described in the
"Capital Resources and Liquidity" section of "Management's Discussion and
Analysis of Financial Condition and Results of Operations" located elsewhere in
this Form 10-K, is subject to certain conditions, including definitive
agreements, arrangement of new debt financing, due diligence, and MESA
stockholder approval. The parties anticipate executing definitive agreements in
approximately 30 days. The transaction will be submitted to a vote of
stockholders at a special meeting expected to take place in June 1996.
The ability of MESA to continue as a going concern is dependent upon
several factors. The successful completion of the Rainwater transaction is
expected to position MESA to continue as a going concern and to pursue its
business strategies. If the Rainwater transaction is not completed, MESA will
pursue other alternatives to address its liquidity issues and financial
condition, including other potential transactions arising from the proposal
solicitation process, the possibility of seeking to restructure its balance
sheet by negotiating with its current debt holders or seeking protection from
its creditors under the Federal Bankruptcy Code.
For additional information regarding the Rainwater transaction and MESA's
financial position, see Notes 2 and 4 to the consolidated financial statements
of the Company and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" included elsewhere in this Form 10-K.
Properties
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Approximately 95% of MESA's proved reserves are concentrated in the
Hugoton field of southwest Kansas and the West Panhandle field of Texas. The
two fields are each part of a reservoir that extends from southwest Kansas,
through the Oklahoma panhandle, and into the Texas panhandle. These fields,
which produce gas from depths of 3,500 feet or less, are known for their stable
long-life production profiles. MESA's other properties are primarily in the
Gulf of Mexico and the Rocky Mountains.
In recent years MESA has concentrated its efforts on fully developing its
existing long-life reserve base and improving its marketing flexibility. In the
Hugoton field, these efforts have included infill drilling (i.e., drilling an
additional well on each 640-acre spacing unit), installing additional
compression and gathering facilities, and the construction of a new natural gas
processing plant, which has the ability to extract a greater quantity of NGLs
per Mcf of natural gas, reject nitrogen and produce crude helium. The new plant
also has the capability to liquefy natural gas. Two significant gas sales
contracts related to Hugoton production expired in May
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1995, giving MESA a substantial amount of uncommitted deliverability available
for sale after that date. In the West Panhandle field, development activities
have included well workovers and deepenings/redrills, adding compression
facilities, and the expansion and upgrading of natural gas processing
facilities to process greater quantities of natural gas and produce crude
helium. In addition, MESA restructured its contractual arrangements in the West
Panhandle field to more clearly define its right to production and to create
greater marketing flexibility. Beginning in late 1994 MESA began to direct a
greater portion of its capital spending towards exploration and development in
the Gulf of Mexico.
MESA's strategies for replacing reserves and increasing production are
based on a multi-step approach, including (i) development and exploratory
drilling in the Gulf of Mexico based on evaluation of three- dimensional
("3-D") seismic data, (ii) developing additional reserves in certain deeper
portions of the West Panhandle field reservoir, and (iii) acquisitions of new
leases and producing properties with development and exploration potential,
particularly in areas where MESA presently or historically has operated. The
extent to which MESA pursues these activities is largely dependent on the
success of its proposal solicitation process and the amount of cash flow
available for capital spending after such process is complete.
MESA has maintained a large geological and geophysical database covering
the Midcontinent and other areas where it has historically operated. As capital
becomes available and conditions permit, MESA intends to exploit its database
and consider selective acquisitions of producing properties with development
and exploration potential in the Texas Panhandle, the Hugoton field, and other
areas of the Midcontinent and Gulf Coast regions.
Hugoton Field
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The Hugoton field in southwest Kansas began producing in 1922, and is the
largest producing gas field in the continental United States. MESA's Hugoton
properties, which represent approximately 13% of the proved reserves in the
field, are concentrated in the center of the field on over 230,000 net acres,
covering approximately 400 square miles. MESA produces natural gas from
approximately 1,400 wells (950 of which are operated by MESA) on these
properties. MESA owns substantially all of the gathering and processing
facilities which service its production from the Hugoton field and which allow
MESA to control the production stream from the wellbore to the various
interconnects it has with major intrastate and interstate pipelines.
MESA's Hugoton properties are capable of producing more than 230 million
cubic feet ("MMcf") of wet gas per day (i.e., gas production at the wellhead
before processing and before reduction for royalties). Substantially all of
MESA's Hugoton production is processed through its Satanta natural gas
processing plant (the "Satanta Plant"). After processing, on a peak production
day, MESA has available to market over 150 MMcf of residue (processed) gas and
13 thousand barrels ("MBbls") of NGLs. Production in the Hugoton field is
subject to allowables set by state regulators.
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MESA's Hugoton properties accounted for approximately 64% of its
equivalent proved reserves and 64% of the present value of estimated future net
cash flows, determined as of December 31, 1995, in accordance with Securities
and Exchange Commission (the "Commission") guidelines. The Hugoton properties
accounted for approximately 47%, 53%, and 48% of MESA's oil and gas revenues
for the years ended December 31, 1995, 1994, and 1993, respectively. The
percentage of revenues from the Hugoton field has been less than the percentage
of equivalent proved reserves due primarily to the longer life of the Hugoton
properties compared to MESA's other properties.
See "Production--Hugoton Field."
West Panhandle Field
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The West Panhandle properties are located in the northern panhandle region
of Texas, and are geologically similar to MESA's Hugoton properties. Natural
gas from these properties is produced from approximately 600 wells which MESA
operates on over 185,000 net acres. All of MESA's West Panhandle production is
processed through MESA's Fain natural gas processing plant (the "Fain Plant").
MESA's West Panhandle reserves are owned and produced pursuant to
contracts with Colorado Interstate Gas Company ("CIG"), originally executed in
1928 by predecessors of both companies. An amendment to these contracts, the
Production Allocation Agreement ("PAA"), allocates 77% of the production from
the West Panhandle field properties to MESA and 23% to CIG, effective as of
January 1, 1991. Under the associated agreements, MESA operates the wells and
production equipment and CIG owns and operates the gathering system by which
MESA's production is transported to the Fain Plant. CIG also performs certain
administrative functions. Each party reimburses the other for certain costs and
expenses incurred for the joint account.
As of December 31, 1995, MESA's West Panhandle properties represented
approximately 32% of MESA's equivalent proved reserves, and approximately 32%
of the present value of estimated future net cash flows, determined in
accordance with Commission guidelines. Production from the West Panhandle
properties accounted for approximately 33%, 36%, and 40% of MESA's oil and gas
revenues for the years ended December 31, 1995, 1994, and 1993, respectively.
Although the West Panhandle properties are long-lived, the percentage of MESA's
revenues represented by West Panhandle production has been greater than the
percentage of equivalent proved reserves represented by such properties. This
is a result of higher gas prices received under a sales contract for
approximately 29% of MESA's West Panhandle residue gas production, as well as
the higher yield of NGLs extracted from West Panhandle natural gas as compared
to Hugoton natural gas.
The Fain Plant is capable of processing up to 120 MMcf of natural gas per
day. West Panhandle field natural gas contains a high quantity of NGLs. As a
result, processing this gas yields relatively greater liquid volumes than
recoveries typically realized in other natural gas fields. For example, on a
peak day, MESA can extract approximately 12 MBbls of NGLs at its Fain Plant
from an inlet gas volume of 120 MMcf.
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In the last six years MESA has deepened, redrilled, or reworked 357 wells
in the West Panhandle field, adding reserves, and increasing deliverability.
MESA has also identified in excess of 100 drilling locations targeting reserves
in deeper portions of the reservoirs not currently reached by existing wells.
MESA will commence an active three-year program to develop these reserves in
1996 in anticipation of its contractual right to increase its share of West
Panhandle production in 1997 and thereafter. See "Production--West Panhandle
Production".
Gulf Coast
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MESA's Gulf Coast properties are located offshore Texas and Louisiana.
MESA has operated in the Gulf of Mexico since 1970 and has produced
approximately 425 billion cubic feet of equivalent natural gas ("Bcfe") (net to
MESA's interest). MESA currently owns interests in 45 blocks in the Gulf of
Mexico. As of December 31, 1995, these properties had an estimated 53 Bcfe of
remaining proved reserves. In addition, MESA has over 100,000 miles of
two-dimensional ("2-D") seismic data and over 350 square miles of 3-D seismic
data in the Gulf of Mexico. MESA has an office in Lafayette, Louisiana, to
oversee production from its Gulf Coast properties. MESA's working interests in
seven of its 45 blocks are subject to a net profits interest owned by the Mesa
Offshore Trust.
Over the last five years, MESA has evaluated a number of its offshore
producing properties utilizing well information, 2-D seismic and production
data, combined with 3-D seismic surveys to identify further development and
exploration potential. MESA currently has 10 3-D seismic surveys under
analysis. New well locations were identified on five producing leases in 1995
and one exploratory block was acquired based upon interpretation of 3-D seismic
data. In 1994 and 1995, MESA drilled or participated in 14 wells in the Gulf
Coast area based on 3-D seismic surveys of which 12 were completed as
successful wells. In the aggregate, MESA incurred net capital costs of $36
million during this period and added approximately 51 Bcfe of oil and gas
reserves. MESA intends to continue its evaluation and identification of
additional prospects for drilling in 1996, depending on the success of its
program and other factors. Because it has existing infrastructure and
production facilities on these properties, MESA expects that it will be able to
bring its successful wells on-line more quickly and at lower development costs
than have been typical for offshore production.
Other
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MESA's other producing properties are located in the Rocky Mountain area
of the United States.
MESA's non-oil and gas tangible properties include buildings, leasehold
improvements, and office equipment, primarily in Amarillo, Dallas, and Fort
Worth, Texas, and certain other assets. Non-oil and gas tangible properties
comprise less than 2% of the net book value of MESA's properties.
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Reserves
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The following table summarizes the estimated proved reserves and estimated
future cash flows as estimated in accordance with Commission guidelines
associated with MESA's oil and gas properties as of December 31, 1995, by major
areas of operation (dollar amounts in thousands):
West Gulf
Hugoton Panhandle Coast Other Total
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Proved Reserves:
Natural Gas (MMcf)... 863,939 283,218 38,317 32,555 1,218,029
Natural Gas Liquids
(MBbls)............. 56,720 45,041 122 14 101,897
Oil (MBbls).......... -- 6,817 2,303 401 9,521
Natural Gas
Equivalents (MMcfe). 1,204,259 594,366 52,867 35,045 1,886,537
Future Net Cash Flows.....$1,480,758 $603,356 $43,089 $25,630 $2,152,833
Present Value of Future
Net Cash Flows, Discounted
at 10%.................... $614,508 $306,695 $42,258 $2,728 $966,189
Future Net Cash Flows,
before income taxes ...$1,693,307 $682,714 $41,704 $32,095 $2,449,820
Present Value of Future
Net Cash Flows, Before
Income Taxes,
Discounted at 10%.......$ 658,330 $332,353 $40,716 $ 9,014 $1,040,413
The proved reserve estimates set forth above were prepared by MESA's
engineers. Prior to 1994 MESA's proved reserve estimates were prepared by an
independent petroleum engineering firm. In accordance with a long-term debt
agreement, the independent petroleum engineering firm will prepare proved
reserve estimates as of December 31, 1995, covering MESA's Hugoton properties
in the manner and to the extent required by the debt agreement. Their report is
not yet available and will not be used for purposes other than those prescribed
in the debt agreement. MESA expects, as in prior years, that the Hugoton field
reserve estimates prepared by such independent engineers will be less than
those of MESA's engineers due to the independent engineers' different
interpretation of well-test pressure and cumulative production data related to
MESA's Hugoton field properties. Such differences have been substantial in
previous years. MESA has received preliminary indications from the independent
engineers that their reserve estimates for the Hugoton field will reflect a
downward revision from prior estimates by such engineers and, as a result, such
estimates may be as much as 25% less than MESA's estimates of Hugoton field
reserves as of December 31, 1995. See Note 4 to the consolidated financial
statements of the Company located elsewhere in this Form 10-K for additional
discussion of the independent engineers' reserve report.
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Oil and gas reserve quantities estimated as of December 31, 1995, reflect a
net increase over 1994, after production, of approximately 171 Bcfe of natural
gas. Equivalent natural gas reserves increased in each of MESA's major
production areas. Increases in Hugoton field reserves reflect alignment of the
assumptions used in preparing the proved reserve estimates with MESA's practice
of recovering ethane at the Satanta Plant. In previous years Hugoton proved
reserve estimates were prepared assuming that MESA would not recover ethane
which resulted in slightly higher natural gas volumes, lower NGL volumes and
lower total equivalent volumes than if ethane recovery were assumed. The
decision as to whether or not to recover ethane is based on the relative value
of ethane as a liquid versus the energy-equivalent value of such ethane if left
in the residue natural gas. In the future, if economic conditions warrant, MESA
may revise proved reserves to reflect any changes in such relative values. In
the West Panhandle field, reserves were revised upward to reflect the
development drilling results over the past year and the planned upgrade of the
Fain Plant for a higher rate of liquids recovery per Mcf of gas produced from
the field. In the Gulf Coast, reserve additions resulted from exploratory and
development drilling in 1994 and 1995.
Reserve engineering is not an exact science. Information relating to
MESA's proved oil and gas reserves is based upon engineering estimates.
Estimates of economically recoverable oil and gas reserves and of future net
revenues depend upon a number of factors and assumptions, such as historical
production performance, the assumed effects of regulations by governmental
agencies and assumptions concerning future oil and gas prices, future operating
costs, severance and excise taxes, development costs and workover costs, all of
which may in fact vary considerably from actual future conditions. The accuracy
of any reserve estimate is a function of the quality of the available data, of
engineering and geological interpretation and of subjective judgment. For these
reasons, estimates of the economically recoverable quantities of oil and gas
reserves attributable to any particular group of properties, classifications of
such reserves based on risk of recovery and estimates of the future net
revenues expected therefrom prepared by different engineers or by the same
engineers at different times may vary materially. Actual production, revenues,
and expenditures with respect to MESA's reserves will likely vary from
estimates, and such variances may be material.
During 1995, MESA filed Form EIA-23, which included reserve estimates as
of December 31, 1994, with the Energy Information Administration of the
Department of Energy (the "EIA"). Such reserve estimates did not vary from
those estimates contained herein by more than 5% as described above.
The estimated quantities of proved oil and gas reserves, the standardized
measure of future net cash flows from proved oil and gas reserves (the
"Standardized Measure") and the changes in the Standardized Measure for each of
the three years in the period ended December 31, 1995, are included under
"Supplemental Financial Data" in the notes to the consolidated financial
statements of the Company located elsewhere in this Form 10-K.
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Production
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MESA's Hugoton and West Panhandle fields are both mature reservoirs that
are substantially developed and have long-life production profiles.
Natural gas production is subject to numerous state and federal laws
and Federal Energy Regulatory Commission (the "FERC") regulations. See
"Regulation and Prices" below.
Certain factors affecting production in MESA's various fields are
discussed in greater detail below.
Hugoton Field
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The Kansas Corporation Commission (the "KCC") is the state regulatory
agency that regulates oil and gas production in Kansas. One of the KCC's most
important responsibilities is the determination of market demand (allowables)
for the field and the allocation of allowables among the more than 9,000 wells
in the field.
Twice each year, the KCC sets the fieldwide allowable production at a
level estimated to be necessary to meet the Hugoton market demand for the
summer and winter production periods. The fieldwide allowable is then allocated
among individual wells determined by a series of calculations that are
principally based on each well's pressure, deliverability, and acreage. The
allowables assigned to individual wells are affected by the relative
production, testing, and drilling practices of all producers in the field, as
well as the relative pressure and deliverability performance of each well.
Generally, fieldwide allowables are influenced by overall gas market
supply and demand in the United States as well as specific nominations for gas
from the parties who produce or purchase gas from the field. Since 1987,
fieldwide allowables have increased in each year except 1991. The total field
allowable in 1995 was 619 billion cubic feet ("Bcf") of wellhead gas.
In 1994 the KCC issued an order establishing new field rules which
modified the formulas used to allocate allowables among wells in the Chase
formation portion of the Hugoton field. The standard pressure used in each
well's calculated deliverability was reduced by 35%, greatly benefitting MESA's
high deliverability wells. Also, the new rules assign a 30% greater allowable
to 640-acre units with infill wells than to similar units without infill wells.
Substantially all of MESA's Hugoton infill wells have been drilled. MESA's
share of the allowables from the field increased from approximately 10% in late
1993 to approximately 14% after the new field rules were implemented in 1994.
MESA's share of the field allowable averaged 14.3% in 1995. MESA estimates that
it and the other major producers in the Hugoton field produced at or near full
capacity in 1995 and MESA expects such practice to continue.
MESA's net Hugoton field production decreased to approximately 70 Bcfe in
1995 compared with 73 Bcfe in 1994 as a result of changes in timing and
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duration of equipment maintenance in 1995. MESA expects its Hugoton field
production will decline slightly from 1995 levels each year through 1998.
Beginning in 1999, MESA expects annual production declines will reach the
historical levels of 8% to 10% as a result of normal depletion.
Excluding reserve acquisitions, MESA has invested over $138 million in
capital expenditures in its Hugoton properties since 1986 to drill 382 infill
wells, to construct the Satanta Plant and related facilities, and to upgrade
gathering and compression facilities, production equipment and pipeline
interconnects in order to increase production capacity and marketing
flexibility. MESA expects future capital expenditures to be substantially
lower.
West Panhandle Field
--------------------
MESA's production of wet gas from the West Panhandle field is governed by
the PAA and other contracts with CIG. MESA was entitled to take wet gas
production up to a maximum of 32 Bcf in 1995. MESA actually took 29 Bcf
primarily due to a weather-related decrease in demand in 1995. MESA will again
be entitled to take wet gas production up to a maximum of 32 Bcf during 1996.
After deductions for processing and royalties, MESA expects that 32 Bcf of wet
gas production will result in annual net production volumes of approximately 21
Bcf of residue gas and 3 million barrels ("MMBbls") of NGLs. Beginning in 1997
MESA will have the right to take and market as much gas as it can produce,
subject to specific CIG seasonal and daily entitlements as provided for under
the contracts. Assuming continuation of existing economic and operating
conditions, MESA expects its existing West Panhandle properties will be able to
produce an average of 35 Bcf of wet gas per year for sale in the years 1997
through 2000.
The PAA contains provisions which allocate 77% of ultimate production
after January 1, 1991, to MESA and 23% to CIG. As a result, MESA records 77% of
total annual West Panhandle production as sales, regardless of whether MESA's
actual deliveries are greater or less than the 77% share. The difference
between MESA's 77% entitlement and the amount of production actually sold by
MESA to its customers is recorded monthly as production revenue with
corresponding accruals for operating costs, production taxes, depreciation,
depletion and amortization, and gas balancing receivables. At December 31,
1995, MESA had cumulative production which was less than its 77% entitlement
since January 1, 1991, and a long-term gas balancing receivable of $42.6
million was recorded in MESA's balance sheet in other assets. In future years,
as MESA sells to customers more than its 77% entitlement share of field
production, this receivable will be realized.
See "-- Production Allocation Agreement" in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" located
elsewhere in this Form 10-K.
Natural Gas Processing
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MESA processes its natural gas production for the extraction of NGLs and
helium to enhance the market value of the gas stream. In recent years MESA has
made substantial capital investments to enhance its natural gas
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processing and helium extraction capabilities in the Hugoton and West Panhandle
fields. MESA owns and operates its processing facilities, which allows MESA to
(i) capture the processing margin for itself, as third-party processing
agreements generally available in the industry result in retention of a
significant portion of the processing margin by the contract processor, (ii)
control the quality of the residue gas stream, permitting it to deliver gas
directly to pipelines for sales to local distribution companies, marketing
companies, and end users, and (iii) realize value from premium products such as
helium. MESA believes that the ability to control its production stream from
the wellhead through its processing facilities to disposition at central
delivery points enhances its marketing opportunities and competitive position
in the industry.
Through its natural gas processing plants, MESA extracts raw NGLs and
crude helium from the wet natural gas stream. The NGLs are then transported and
fractionated into their constituent hydrocarbons such as ethane, propane,
normal butane, isobutane, and natural gasolines. The NGLs and helium are then
sold pursuant to contracts providing for market-based prices.
Satanta Natural Gas Processing Plant
------------------------------------
The Satanta Plant has the capacity to process 250 MMcf of natural gas per
day, and enables MESA to extract NGLs from substantially all of the gas
produced from its Hugoton field properties as well as third party producers'
gas. The Satanta Plant also has the ability to extract helium from the gas
stream. In 1995 the Satanta Plant averaged 191 MMcf per day of inlet gas and
produced a daily average of 10.9 MBbls of NGLs, 671 Mcf of crude helium, and
144 MMcf of residue natural gas.
Fain Natural Gas Processing Plant
---------------------------------
Wet gas produced from the West Panhandle field contains a high quantity of
NGLs, yielding relatively greater NGL volumes than realized from most other
natural gas fields. The Fain Plant has inlet capacity of 120 MMcf per day. In
1995 the Fain Plant averaged 81 MMcf per day of inlet gas and produced a daily
average of 8.1 MBbls of NGLs and condensate, 53 Mcf of crude helium, and 61
MMcf of residue natural gas.
MESA plans to expand the Fain Plant to process additional natural gas
production which MESA expects to take beginning in 1997 and to process certain
third-party natural gas. MESA also plans to upgrade the Fain Plant to recover
additional liquids from the natural gas stream due to richer gas in the field.
Sales and Marketing
- -------------------
Following the processing of wet gas, MESA sells the dry (or residue)
natural gas, helium, condensate, and NGLs pursuant to various short- and
long-term sales contracts. Substantially all of MESA's gas and NGL sales are
made at market prices, with the exception of certain West Panhandle field
volumes. Due to a number of market forces, including the seasonal
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demand for natural gas, both sales volumes from MESA's properties and sales
prices received vary on a seasonal basis. Sales volumes and price realizations
for natural gas are generally higher during the first and fourth quarters of
each calendar year.
See "Revenues" in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" located elsewhere in this Form 10-K for a
table showing production and prices by area for the past three years.
Hugoton Gas Sales Contracts
---------------------------
A substantial portion of MESA's Hugoton field production was subject to
two gas purchase contracts with Western Resources, Inc. ("WRI") and Missouri
Gas Energy ("MGE") which expired in May 1995. Under the contracts, WRI and MGE
had the right to purchase 19.9 Bcf during the first five months of 1995 at
market prices. In 1995 WRI and MGE together purchased 20.7 Bcf of gas from MESA
at an average price of $1.44 per Mcf under these contracts. Since June 1, 1995,
gas previously subject to the WRI and MGE contracts has been sold to multiple
purchasers including WRI and MGE under short-term contracts at market prices.
MESA's efforts to maximize its annual production and to direct natural gas
sales to the most favorable markets available are consistent with regulatory
and contractual requirements. MESA sells its Hugoton field production to
marketers, pipelines, local distribution companies, and end-users, generally at
market prices.
West Panhandle Gas Sales Contracts
----------------------------------
Most of MESA's West Panhandle field residue natural gas is sold pursuant
to gas purchase contracts with two major customers in the Texas panhandle area.
Approximately 9 Bcf per year of residue natural gas is sold to a gas
utility that serves residential and commercial customers in Amarillo, Texas,
under the terms of a long-term agreement dated January 2, 1993, which
supersedes the original contract that was in effect since 1949. The agreement
contains a pricing formula for the five-year period from 1993 through 1997
whereby 70% of the volumes sold to the gas utility are sold at fixed prices and
the other 30% of volumes sold are priced at a regional market index based on
spot prices plus $.10 per Mcf. The fixed portion of the price formula was $2.85
per Mcf in 1994, $2.99 per Mcf in 1995 and escalates to $3.21 per Mcf in 1996
and $3.45 per Mcf in 1997. Prices for 1998 and beyond will be determined by
renegotiation. MESA provides the gas utility significant volume flexibility,
including a right to the residue gas volumes required to meet the seasonal
needs of its residential and commercial customers. The average price received
by MESA for natural gas sales to the gas utility in 1995 was $2.55 per Mcf.
Through 1995, MESA's principal industrial customer for West Panhandle
field gas was an intrastate pipeline company which serves various markets,
including an electric power-generation facility near Amarillo. In 1990 MESA
entered into a five-year contract with the pipeline company to supply gas to
13
<PAGE> 14
the power generation facility. The contract provided for a minimum annual
volume of 8.4 Bcf in 1995 at a fixed price per million British thermal units
("MMBtu") of $1.70 in 1995. MESA periodically made sales to the pipeline
company in excess of the minimum volumes specified in the contract at market
prices. In 1995 MESA sold approximately 9.3 Bcf of residue natural gas to the
pipeline for an average price of $1.63 per Mcf. This contract expired on
December 31, 1995.
Effective January 1, 1996, MESA entered into a four-year contract with a
marketing company, an affiliate of the intrastate pipeline company, which
serves the local electric power-generation facility and various other markets
within and outside Amarillo, Texas. The contract provides for the sale of
MESA's West Panhandle field gas which is in excess of the volumes sold to the
gas utility and other existing industrial customers. The price for gas sold
under this contract is a regional market index determined monthly based on spot
prices plus $0.02 per MMBtu.
Other industrial customers purchase natural gas from MESA under short- to
intermediate-term contracts. These sales totaled approximately 3.5 Bcf in 1995.
Prior to 1993, MESA's right to sell natural gas produced from the West
Panhandle field was based, in part, upon contractual requirements to serve
customers in Amarillo, Texas, and its environs. An amendment to the PAA in 1993
removed this restriction, and MESA now has the right to market its production
elsewhere. MESA believes that the right to market production outside the
Amarillo area will ensure that MESA receives competitive terms for its West
Panhandle field production. Through 1999, MESA's West Panhandle field
production is under contract to customers as described above.
NGL, Helium and LNG Sales
-------------------------
NGL production from both the Satanta and Fain plants are sold by component
pursuant to a seven-year contractual arrangement with Mapco Oil and Gas
Company, a major transporter and marketer of NGLs, at the greater of
Midcontinent or Gulf Coast prices at the time of sale. Helium is sold to an
industrial gas company under a fifteen-year agreement that provides for annual
price adjustments.
MESA has formed a liquefied natural gas ("LNG") production and marketing
joint venture, Mesa-Pacific LNG Joint Venture, L.L.C. ("Mesa Pacific"), with
Pacific Enterprises, the parent company of Southern California Gas Company, in
an effort to profit from the increasing use of LNG as a transportation fuel.
Mesa-Pacific purchases LNG from MESA and then markets the product to fleet
operators. MESA produces LNG at its Satanta Plant and is reviewing plans to add
LNG production capabilities at the Fain Plant.
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<PAGE> 15
Major Customers
---------------
See Note 11 to the consolidated financial statements of the Company
located elsewhere in this Form 10-K for information on sales to major
customers.
Production Costs
- ----------------
The table below presents MESA's total production costs (lease operating
expenses and production and other taxes) by area of operation for each of the
years ended December 31 (in thousands, except per Mcf of natural gas equivalent
data):
1995 1994 1993
---------------- ---------------- ----------------
Total Per Mcfe Total Per Mcfe Total Per Mcfe
------- -------- ------- -------- ------- --------
Lease Operating Expense:
Hugoton............... $12,703 $ .18 $12,549 $ .17 $10,001 $ .18
West Panhandle........ 28,357 .73 28,347 .64 29,897 .66
Gulf Coast............ 9,848 .68 11,136 1.15 11,032 .99
Other................. 907 2.57 623 2.00 889 1.03
------- ------- -------
51,815 .42 52,655 .41 51,819 .45
------- ------- -------
Production and Other
Taxes:
Hugoton............... 15,004 .21 17,505 .24 15,405 .27
West Panhandle........ 3,216 .08 3,099 .07 4,581 .10
Gulf Coast............ 34 .00 68 .01 89 .01
Other................. 149 .42 634 2.04 257 .30
------- ------- -------
18,403 .15 21,306 .17 20,332 .18
------- ------- -------
Total Production Costs... $70,218 $ .57 $73,961 $ .58 $72,151 $ .63
======= ======= =======
MESA lease operating expenses consist of lease maintenance, gathering and
processing costs and have a significant fixed-cost component. As a result, the
production cost per Mcfe in the table above is affected by changes in the
volume of oil and gas produced. Production tax rates in Kansas, where MESA's
Hugoton field properties are located, are assessed on wellhead value. These
rates were reduced from 7% in 1993 to 6% in 1994 and 5% in 1995. In 1993 West
Panhandle field taxes included a one-time adjustment related to prior years'
production.
See "-- Costs and Expenses" in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" located elsewhere in this Form
10-K.
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<PAGE> 16
Drilling Activities
- -------------------
The following table shows the results of MESA's drilling activities for
the last five years:
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
Gross Net Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Exploratory
Wells:
Productive.... 1 .3 -- -- -- -- 5 4.1 6 4.7
Dry........... 4 4.0 -- -- 1 1.0 1 .4 1 .2
Development
Wells:
Productive.... 20 14.0 31 24.5 43 29.1 22 16.5 26 10.9
Dry........... -- -- 1 .8 -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total....... 25 18.3 32 25.3 44 30.1 28 21.0 33 15.8
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
At December 31, 1995, the Company was participating in the drilling of one
gross (.25 net) well.
Producing Acreage and Wells, Undeveloped Acreage
- ------------------------------------------------
MESA's ownership of oil and gas acreage held by production, producing
wells and undeveloped oil and gas acreage as of December 31, 1995, is set forth
in the following table:
Producing Producing Undeveloped
Acreage Wells Acreage
---------------- -------------- --------------
Gross Net Gross Net Gross Net
------- ------- ----- ------- ------ ------
Onshore U.S.:
Kansas................ 258,818 231,278 1,387 988.9 5,280 5,280
Texas................. 241,354 185,654 601 452.4 480 156
Wyoming............... 11,477 4,365 2 -- 14,926 9,391
North Dakota.......... 4,661 3,532 20 3.8 3,932 2,572
Other................. 2,597 2,139 13 1.3 22,012 11,573
------- ------- ----- ------- ------ ------
Total Onshore.... 518,907 426,968 2,023 1,446.4 46,630 28,972
------- ------- ----- ------- ------ ------
Offshore U.S.:
Louisiana............. 87,024 45,710 189 39.7 20,210 19,898
Texas................. 73,808 18,848 59 10.1 17,280 17,280
------- ------- ----- ------- ------ ------
Total Offshore... 160,832 64,558 248 49.8 37,490 37,178
------- ------- ----- ------- ------ ------
Grand Total................ 679,739 491,526 2,271 1,496.2 84,120 66,150
======= ======= ===== ======= ====== ======
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<PAGE> 17
MESA has interests in 2,092 gross (1,473.5 net) producing gas wells and
179 gross (22.7 net) producing oil wells in the United States. MESA also owns
approximately 84,632 net acres of producing minerals and 42,964 net acres of
nonproducing minerals in the United States.
The NGV Business
- ----------------
MESA believes that the transportation market offers opportunities to
realize premium prices for natural gas. MESA believes that the natural gas
vehicles ("NGV") market will develop and expand in the next decade,
particularly in light of (i) the National Energy Policy Act of 1992, (ii) the
amendments to the 1990 Federal Clean Air Act which require the use of
alternative fuels by certain fleets, (iii) the requirements of numerous state
and municipal environmental regulations, (iv) generally increased awareness of
the adverse environmental and pollution effects of crude oil-based motor fuels,
and (v) the development of more efficient equipment to convert gasoline- and
diesel-burning engines to operate on natural gas. MESA's strategies have
included (i) the development, manufacture, and sale of engine-specific
conversion equipment which meets the most stringent emissions standards, and
(ii) pursuing conversion equipment sales, fleet conversions, fueling station
installations, and the administration of fueling and conversion programs. In
1996 MESA initiated a strategic process designed to redirect its efforts in the
natural gas-fuel systems business. MESA expects to continue to be active in the
development of conversion systems and will begin providing contract engineering
support for heavy-duty natural gas engine applications, but will no longer
market, manufacture or install such systems.
Conversion Equipment
-------------------
MESA's wholly owned subsidiary, Mesa Environmental Ventures Co. ("Mesa
Environmental") has developed a natural gas vehicle conversion system, the Gas
Engine Management ("GEM") system, which MESA believes is the cleanest and most
advanced conversion product in the industry. Mesa Environmental is currently
marketing its GEM system to fleet operators in the United States. In February
1996 Mesa Environmental signed letters of intent with two companies to exchange
certain of its assets and GEM technology, including the right to manufacture
and install GEM systems, for equity in one such company and a royalty interest
from the other. MESA believes that its association with these leading
manufacturers and marketers will ultimately provide MESA greater profit
potential in the natural gas vehicle conversion business.
Fueling Business
----------------
In 1994 MESA entered into a fueling arrangement with a large operator of
airport shared-ride fleet vehicles. MESA agreed to finance the acquisition by
the fleet operator of certain natural gas-fueled vans and conversion equipment,
and the fleet operator agreed to purchase natural gas at MESA's fueling
facilities. This financing/fueling arrangement is designed to be a model for
similar agreements with fleet operators at select other locations in the U.S.
MESA currently operates natural gas fueling
17
<PAGE> 18
stations near the Phoenix, Arizona, airport and in Anaheim, California. MESA
plans to open a new facility near LAX Airport in Los Angeles in 1996.
Organizational Structure
- ------------------------
MESA owns and operates its oil and gas properties and other assets
through various direct and indirect subsidiaries. Its direct wholly owned
subsidiaries are Mesa Operating Co. ("MOC"), Mesa Holding Co. ("MHC"), and
Hugoton Management Co. ("HMC"). Its principal indirect wholly owned
subsidiary is Hugoton Capital Limited Partnership ("HCLP").
MOC
---
MOC owns MESA's properties in the West Panhandle field of Texas and MESA's
interests in the Gulf of Mexico and the Rocky Mountain area. MOC also owns an
approximate 99% limited partnership interest in HCLP. In addition, MOC owns
helium attributable to its West Panhandle field properties and HCLP's Hugoton
field properties.
MOC is MESA's principal operating subsidiary. Most of MESA's employees are
employed by MOC, and MOC is generally responsible for all of MESA's operations,
administration, and marketing, including the operations of HCLP.
HCLP
----
Substantially all of MESA's Hugoton field property interests (including
gathering systems and compression and gas processing facilities), are owned by
HCLP. HCLP also owns the Satanta Plant, which was constructed by MOC.
MOC operates the plant under a long-term lease.
HCLP was formed in 1991 to own substantially all of MESA's Hugoton field
properties and to issue certain long-term notes secured by those properties
(the "HCLP Secured Notes"). The indenture and mortgage for the HCLP Secured
Notes contain various covenants which, among other things, limit HCLP's ability
to sell or acquire oil and gas property interests, incur additional
indebtedness, make unscheduled capital expenditures, make distributions of
property or funds subject to the mortgage, enter into certain types of
long-term contracts, or forward sales of production. The agreements also
require HCLP to remain in partnership form; its general partner is HMC. The
assets of HCLP, which is required to maintain separate existence from MESA, are
generally not available to pay creditors of MESA or its subsidiaries other than
HCLP. The HCLP agreements require proceeds from production to be applied
towards payment of HCLP's operating, administrative, and capital costs, and to
service HCLP's debt. To the extent cash flows exceed these requirements, such
"excess cash" is generally available for distribution to MESA subsidiaries that
own an equity interest in HCLP.
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<PAGE> 19
MHC
---
MHC principally conducts various investment activities. At December 31,
1995, MHC held approximately $74 million of cash and investments, an
approximate 1% limited partnership interest in HCLP, and all of the equity of
Mesa Environmental.
History of MESA
- ---------------
In 1964 Original Mesa was formed as a public corporation engaged in the
business of exploring for and producing oil and natural gas. Original Mesa's
reserves and revenues grew significantly throughout the 1960s, 1970s, and early
1980s as a result of successful exploration, development and acquisitions.
Original Mesa conducted operations in the United States, and at various times,
Canada, the North Sea, and Australia. Original Mesa was reorganized as the
Partnership, a publicly traded limited partnership, in 1985 and the Partnership
was converted to corporate form as MESA Inc. in 1991.
MESA's two most recent significant acquisitions, Pioneer Corporation in
1986 (which included MESA's West Panhandle field) and Tenneco Inc.'s
midcontinent division in 1988 (which included approximately one-fourth of
MESA's current Hugoton holdings), increased reserves from 1.4 Tcfe at year-end
1985 to over 2.8 Tcfe at year-end 1988. MESA incurred significant debt to make
the reserve acquisitions. MESA also made cash distributions to Partnership
unitholders of over $1.1 billion from 1986 through 1990. The increased debt
associated with the acquisitions, the distributions, and declining gas prices
through the late 1980s and early 1990s, significantly impaired MESA's financial
strength and flexibility. As a result, in 1991 MESA began to sell assets and
refinance and restructure its debt. From 1989 through 1993, MESA sold nearly
600 Bcfe of proved producing reserves for an aggregate of over $633 million.
MESA used the proceeds principally to reduce debt. MESA refinanced $550 million
of bank debt in 1991 with the formation of HCLP and the issuance of the HCLP
Secured Notes. In 1993 MESA restructured substantially all of its $600 million
of outstanding subordinated debt in a debt exchange transaction, which had the
effect of deferring over $150 million of cash interest requirements until after
1995. In the second quarter of 1994 MESA completed a public offering of
approximately 16.3 million shares of common stock at a public offering price of
$6.00 per share (the "Equity Offering"). The Equity Offering resulted in net
proceeds to MESA of approximately $93 million which were used to repay debt.
In an effort to address its liquidity issues, MESA's Board approved a
proposal solicitation process which started in late 1994 and was expanded in
mid-1995. The process has included solicitation of proposals for a sale of
MESA, a stock-for-stock merger, joint ventures, asset sales, equity infusions,
and refinancing transactions. On February 28, 1996, MESA entered into a letter
of intent with Rainwater to raise $265 million of equity in connection with a
refinancing of MESA's debt.
For additional information regarding the Rainwater transaction and MESA's
financial position, see "Management's Discussion and Analysis of
19
<PAGE> 20
Financial Condition and Results of Operations" located elsewhere in this Form
10-K.
Competition
- -----------
The oil and gas business is highly competitive in the search for,
acquisition of, and sale of, oil and gas. MESA's competitors in these endeavors
include the major oil and gas companies, independent oil and gas concerns, and
individual producers and operators, as well as major pipeline companies, many
of which have financial resources greatly in excess of those of MESA. MESA
believes that its competitive position is affected by, among other things,
price, contract terms, and quality of service.
MESA is one of the largest owners of natural gas reserves in the United
States. Production from MESA's properties has access to a substantial portion
of the major metropolitan markets in the United States through numerous
pipelines and other purchasers. MESA is not dependent upon any single purchaser
or small group of purchasers.
MESA believes that its competitive position is enhanced by its substantial
long-life reserve holdings and related deliverability, its flexibility to sell
such reserves in a diverse number of markets, and its ability to produce its
reserves at a low cost.
Operating Hazards and Uninsured Risks
- -------------------------------------
MESA's oil and gas activities are subject to all of the risks normally
incident to exploration for and production of oil and gas, including blowouts,
cratering, and fires, each of which could result in damage to life and
property. Offshore operations are subject to a variety of operating risks, such
as hurricanes and other adverse weather conditions, and lack of access to
existing pipelines or other means of transporting production. Furthermore,
offshore oil and gas operations are subject to extensive governmental
regulations, including certain regulations that may, in certain circumstances,
impose absolute liability for pollution damages, and to interruption or
termination by governmental authorities based on environmental or other
considerations. In accordance with customary industry practices, MESA carries
insurance against some, but not all, of these risks. Losses and liabilities
resulting from such events would reduce revenues and increase costs to MESA to
the extent not covered by insurance.
Regulation and Prices
- ---------------------
MESA's operations are affected from time to time in varying degrees by
political developments and federal, state, and local laws and regulations. In
particular, oil and gas production operations and economics are, or in the past
have been, affected by price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, by changes in
such laws and by constantly changing administrative regulations.
20
<PAGE> 21
Price Regulations
-----------------
In the recent past, maximum selling prices for certain categories of oil,
gas, condensate, and NGLs were subject to federal regulation. In 1981 all
federal price controls over sales of crude oil, condensate and NGLs were
lifted. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") deregulated natural gas prices for all "first sales" of
natural gas, which includes all sales by MESA of its own production. As a
result, all sales of MESA's domestically produced oil, gas, condensate and NGLs
may be sold at market prices, unless otherwise committed by contract.
Natural Gas Regulation
----------------------
Historically, interstate pipeline companies generally acted as wholesale
merchants by purchasing natural gas from producers and reselling the gas to
local distribution companies and large end-users. Commencing in late 1985, the
FERC issued a series of orders that have had a major impact on interstate
natural gas pipeline operations, services, and rates, and thus have
significantly altered the marketing and price of natural gas. The FERC's key
rulemaking action, Order 636 ("Order 636"), issued in April 1992, required each
interstate pipeline to, among other things, "unbundle" its traditional bundled
sales services and create and make available on an open and nondiscriminatory
basis numerous constituent services (such as gathering services, storage
services, firm and interruptible transportation services, and stand-by sales
and gas balancing services), and to adopt a new rate-making methodology to
determine appropriate rates for those services. To the extent the pipeline
company or its sales affiliate makes gas sales as a merchant in the future, it
does so pursuant to private contracts in direct competition with all other
sellers, such as MESA; however, pipeline companies and their affiliates were
not required to remain "merchants" of gas, and most of the interstate pipeline
companies have become "transporters only." In subsequent orders, the FERC
largely affirmed the major features of Order 636 and denied a stay of the
implementation of the new rules pending judicial review. By the end of 1994,
the FERC had concluded the Order 636 restructuring proceedings, and, in
general, accepted rate filings implementing Order 636 on every major interstate
pipeline. However, even through the implementation of Order No. 636 on
individual interstate pipelines is essentially complete, many of the individual
pipeline restructuring proceedings, as well as Order No. 636 itself and the
regulations promulgated thereunder, are subject to pending appellate review and
could possibly be changed as a result of future court orders. MESA cannot
predict whether the FERC's orders will be affirmed on appeal or what the
effects will be on its business.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate pipeline-owned
gathering facilities by interstate pipelines to their affiliates (the so-called
"spin-down" of previously-regulated gathering facilities to the pipeline's
nonregulated affiliate), (ii) the completion of a rulemaking
21
<PAGE> 22
involving the regulation of pipelines with marketing affiliates under Order No.
497, (iii) the FERC's on-going efforts to promulgate standards for pipeline
electronic bulletin boards and electronic data exchange, (iv) a generic inquiry
into the pricing of interstate pipeline capacity, (v) efforts to refine the
FERC's regulations controlling operation of the secondary market for released
pipeline capacity, and (vi) a policy statement regarding market-based rates and
other non-cost-based rates for interstate pipeline transmission and storage
capacity. Several of these initiatives are intended to enhance competition in
natural gas markets, although some, such as "spin-downs," may have the adverse
effect of increasing the cost of doing business on some in the industry as a
result of the monopolization of those facilities by their new, unregulated
owners. The FERC has attempted to address some of these concerns in its orders
authorizing such "spin-downs," but it remains to be seen what effect these
activities will have on access to markets and the cost to do business. As to
all of these recent FERC initiatives, the on-going, or, in some instances,
preliminary evolving nature of these regulatory initiatives makes it impossible
at this time to predict their ultimate impact on MESA's business.
MESA owns, directly or indirectly, certain natural gas facilities that it
believes meet the traditional tests the FERC has used to establish a company's
status as a gatherer not subject to FERC jurisdiction under the Natural Gas Act
of 1938 (the "NGA"). Moreover, recent orders of the FERC have been more liberal
in their reliance upon or use of the traditional tests, such that in many
instances, what was once classified as "transmission" may now be classified as
"gathering." MESA transports its own gas through these facilities. MESA also
transports certain of its gas through gathering facilities owned by others,
including interstate pipelines. With respect to item (i) in the preceding
paragraph, on May 27, 1994, the FERC issued orders in the context of the
"spin-off" or "spin-down" of interstate pipeline-owned gathering facilities. A
"spin-off" is a FERC-approved sale of such facilities to a non-affiliate. A
"spin-down" is the transfer by the interstate pipeline of its gathering
facilities to an affiliate. A number of spin-offs and spin-downs have been
approved by the FERC and implemented. The FERC held that it retains
jurisdiction over gathering provided by interstate pipelines, but that it
generally does not have jurisdiction over pipeline gathering affiliates, except
in the event of affiliate abuse (such as actions by the affiliate undermining
open and nondiscriminatory access to the interstate pipeline). These orders
require nondiscriminatory access for all sources of supply, prohibit the tying
of pipeline transportation service to any service provided by the pipeline's
gathering affiliate, and require the new gathering company to submit a
"default" contract if a satisfactory contract cannot be mutually agreed upon by
the interstate pipeline and its existing customers. Several petitions for
rehearing of the FERC's May 27, 1994, orders were filed. On November 30, 1994,
the FERC issued a series of rehearing orders largely affirming the May 27,
1994, orders. The FERC clarified that "default" contracts are intended to serve
only as a transition mechanism to prevent arbitrary termination of gathering
service to existing customers. Also, the FERC now requires interstate pipelines
to not only seek authority under Section 7(b) of the NGA to abandon
certificated facilities, but also to seek authority under Section 4 of the NGA
to terminate service from both certificated and uncertificated facilities. On
December 31, 1994, an appeal was filed with the U.S. Court of Appeals for the
D.C. Circuit to overturn three of the FERC's November 30, 1994, orders. MESA
cannot predict what the ultimate
22
<PAGE> 23
effect of the FERC's orders pertaining to gathering will have on its production
and marketing, or whether the Appellate Court will affirm the FERC's orders on
these matters.
State and Other Regulation
--------------------------
All of the jurisdictions in which MESA owns producing oil and gas
properties have statutory provisions regulating the exploration for and
production of crude oil and natural gas. Such regulation includes requiring
permits for the drilling of wells, maintaining bonding requirements in order to
drill or operate wells, and relating to the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled and the plugging and abandoning of wells. MESA's
operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration
units and the density of wells which may be drilled and the unitization or
pooling of oil and gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state conservation
laws establish maximum rates of production from oil and natural gas wells,
generally prohibit the venting or flaring of natural gas and impose certain
requirements regarding the ratability of production. Some states, such as
Texas, Oklahoma, and Kansas have, in recent years, reviewed and substantially
revised methods previously used to make monthly determinations of allowable
rates of production from fields and individual wells. See "-- Production" for a
discussion of recent changes to MESA's allowables in the Hugoton field. The
effect of these regulations is to limit the amounts of oil and natural gas MESA
can produce from its wells, and to limit the number of wells or the location at
which MESA can drill.
State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take
requirements, but does not generally entail rate regulation. Natural gas
gathering has received greater regulatory scrutiny at both the state and
federal levels in the wake of the interstate pipeline restructuring under Order
636. For example, Oklahoma recently enacted a prohibition against
discriminatory gathering rates, and certain Texas and Kansas regulatory
officials have expressed interest in evaluating similar rules in their
respective states.
Federal Royalty Matters
-----------------------
By a letter dated May 3, 1993, directed to thousands of producers holding
interests in federal leases, the United States Department of the Interior (the
"DOI") announced its interpretation of existing federal leases to require the
payment of royalties on past natural gas contract settlements which were
entered into in the 1980s and 1990s to resolve, among other things, take-or-pay
and minimum take claims by producers against pipelines and other buyers. The
DOI's letter set forth various theories of liability, all founded on the DOI's
interpretation of the term "gross proceeds" as used in federal leases and
pertinent federal regulations. In an effort to ascertain the amount of such
potential royalties, the DOI sent a letter to
23
<PAGE> 24
producers on June 18, 1993, requiring producers to provide all data on all
natural gas contract settlements, regardless of whether gas produced from
federal leases was involved in the settlement. MESA received a copy of this
information demand letter. In response to the DOI's action, in July 1993
various industry associations and others filed suit in the United States
District Court for the Northern District of West Virginia seeking an injunction
to prevent the collection of royalties on natural gas contract settlement
amounts under the DOI's theories. The lawsuit, styled "Independent Petroleum
Association v. Babbitt," was transferred to the United States District Court in
Washington, D.C. On June 14, 1995, the Court issued a ruling in this case
holding that royalties are payable to the United States on gas contract
settlement proceeds in accordance with the Minerals Management Service's May 3,
1993, letter to producers. This ruling was appealed and is now pending in the
D.C. Circuit Court of Appeals. The DOI's claim in a bankruptcy proceeding
against a producer based upon an interstate pipeline's earlier buy-out of the
producer's gas sale contract was rejected by the Federal Bankruptcy Court in
Lexington, Kentucky, in a proceeding styled "Century Offshore Management
Corp.". While the facts of the Court's decision do not involve all of the DOI's
theories, the Court found on those at issue that DOI's theories were without
legal merit, and the Court's reasoning suggests that the DOI's other claims are
similarly deficient. This decision was upheld in the District Court and is now
on appeal in the Sixth Circuit Court of Appeals. Because both the "Independent
Petroleum Association v. Babbitt" and "Century Offshore Management Corp."
decisions have been appealed, and because of the complex nature of the
calculations necessary to determine potential additional royalty liability
under the DOI's theories, it is impossible to predict what, if any, additional
or different royalty obligation the DOI may assert or ultimately be entitled to
recover with respect to any of MESA's prior natural gas contract settlements.
Environmental Matters
---------------------
MESA's operations are subject to numerous federal, state, and local laws
and regulations controlling the discharge of materials into the environment or
otherwise relating to the protection of the environment, including the
Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Federal Superfund Law." Such laws and
regulations, among other things, impose absolute liability upon the lessee
under a lease for the cost of clean-up of pollution resulting from a lessee's
operations, subject the lessee to liability for pollution damages, may require
suspension or cessation of operations in affected areas, and impose
restrictions on the injection of liquids into subsurface aquifers that may
contaminate groundwater. MESA maintains insurance against costs of clean-up
operations, but it is not fully insured against all such risks. A serious
incident of pollution may, as it has in the past, also result in the DOI
requiring lessees under federal leases to suspend or cease operation in the
affected area. In addition, the recent trend toward stricter standards in
environmental legislation and regulation may continue. For instance,
legislation has been proposed in Congress from time to time that would
reclassify certain oil and gas production wastes as "hazardous wastes" which
would make the reclassified exploration and production wastes subject to much
more stringent handling, disposal, and clean-up requirements. If such
legislation were to be enacted, it could have a significant impact on
24
<PAGE> 25
MESA's operating costs, as well as the oil and gas industry in general. State
initiatives to further regulate the disposal of oil and gas wastes are also
pending in certain states, and these various initiatives could have a similar
impact on MESA.
The Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose a
variety of regulations on "responsible parties" (which include owners and
operators of offshore facilities) related to the prevention of oil spills and
liability for damages resulting from such spills in United States waters. In
addition, OPA imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, the Minerals Management Service (the "MMS")
published an advance notice of its intention to adopt a rule under OPA that
would require owners and operators of offshore oil and gas facilities to
establish $150 million in financial responsibility. Under the proposed rule,
financial responsibility could be established through insurance, guaranty,
indemnity, surety bond, letter of credit, qualification as a self-insurer, or a
combination thereof. There is substantial uncertainty as to whether insurance
companies or underwriters will be willing to provide coverage under OPA because
the statute provides for direct lawsuits against insurers who provide financial
responsibility coverage, and most insurers have strongly protested this
requirement. The financial tests or other criteria that will be used to judge
self-insurance are also uncertain. As a result of the strong opposition to the
$150 million financial responsibility requirement in its present form, the DOI
has decided not to implement the OPA until some time in 1996. While there has
been discussion in the United States Congress about amending the financial
responsibility requirements of the OPA, such action has not been undertaken to
date. MESA cannot predict the final form of the financial responsibility rule
that will be adopted by the MMS, but such rule has the potential to result in
the imposition of substantial additional annual costs on MESA or otherwise have
material adverse effects on MESA's operations in the Gulf of Mexico.
Under current federal regulations concerning offshore operations, the MMS
is authorized to require lessees to post supplemental bonds to cover their
potential leasehold abandonment costs. By letter dated November 9, 1995, MESA
was advised by the MMS that it does not qualify for a waiver from supplemental
bond requirements and that MESA may be required to post supplemental bonds
covering its potential obligations with respect to offshore operations. On
December 8, 1995, the MMS published a Notice of Proposed Rulemaking in which
the MMS proposed to further clarify and update its Outer Continental Shelf
operational bond requirements. Comments with respect to this proposed
rulemaking are due March 7, 1996. MESA cannot predict the final form of the
financial responsibility rule that will be adopted by the MMS or whether the
MMS will require it to post supplemental bonds, but such rule or requirement
has the potential to result in substantial additional annual costs to MESA or
otherwise have material adverse effects on MESA's operation in the Gulf of
Mexico.
In 1993 a number of companies in New Mexico, including MESA, were named in
a preliminary information request from the Environmental Protection Agency (the
"EPA") as persons who may be potentially responsible for costs incurred in
connection with the Lee Acres Landfill site. Although MESA did not directly
dispose of any materials at the site, it may have contracted to
25
<PAGE> 26
transport materials from its operations with certain trucking companies also
named in the information request. To the extent any materials produced by MESA
may have been transported to the site, MESA believes that such materials were
rainwater and/or water produced from natural gas wells, which MESA believes are
exempt or excluded from the definitions of "hazardous waste" or "hazardous
substance" under applicable Federal environmental laws, although the EPA may
assert a contrary position. Since submitting its response to the information
request in April 1994, MESA has not received any additional inquiries or
information from the EPA concerning the site, including whether MESA is, in
fact, asserted to be a responsible party for the site or what potential
liability, if any, MESA may face in connection with this matter.
MESA is not involved in any other administrative or judicial proceedings
arising under federal, state, or local environmental protection laws and
regulations which would have a material adverse effect on MESA's financial
position or results of operations.
Item 2. Properties
===================
Reference is made to Item 1 of this Form 10-K for a description of MESA's
properties.
Item 3. Legal Proceedings
==========================
Masterson Lawsuit
- -----------------
In February 1992 the current lessors of an oil and gas lease (the "Gas
Lease") dated April 30, 1955, between R. B. Masterson, et al., as lessor, and
CIG, as lessee, sued CIG in Federal District Court in Amarillo, Texas, claiming
that CIG had underpaid royalties due under the Gas Lease. The Company owns an
interest in the Gas Lease. In August 1992 CIG filed a third-party complaint
against the Company for any such royalty underpayments which may be allocable
to the Company's interest in the Gas Lease. The plaintiffs alleged that the
underpayment was the result of CIG's use of an improper gas sales price upon
which to calculate royalties and that the proper price should have been
determined pursuant to a "favored-nations" clause in a July 1, 1967, amendment
to the Gas Lease (the "Gas Lease Amendment"). The plaintiffs also sought a
declaration by the court as to the proper price to be used for calculating
future royalties.
The plaintiffs alleged royalty underpayments of approximately $500 million
(including interest at 10%) covering the period from July 1, 1967, to the
present. In March 1995 the court made certain pretrial rulings that eliminated
approximately $400 million of the plaintiffs' claims (which related to periods
prior to October 1, 1989), but which also reduced a number of the Company's
defenses. The Company and CIG filed stipulations with the court whereby the
Company would have been liable for between 50% and 60%, depending on the time
period covered, of an adverse judgment against CIG for post-February 1988
underpayments of royalties. On March 22, 1995, a jury trial began and on May 4,
1995, the jury returned its verdict. Among its findings, the jury determined
that CIG had underpaid royalties for
26
<PAGE> 27
the period after September 30, 1989, in the amount of approximately $140,000.
Although the plaintiffs argued that the "favored-nations" clause entitled them
to be paid for all of their gas at the highest price voluntarily paid by CIG to
any other lessor, the jury determined that the plaintiffs were estopped from
claiming that the "favored-nations" clause provides for other than a
pricing-scheme to pricing-scheme comparison. In light of this determination,
and the plaintiffs' stipulation that a pricing-scheme to pricing-scheme
comparison would not result in any "trigger prices" or damages, defendants
asked the court for a judgment that plaintiffs take nothing. The court, on June
7, 1995, entered final judgment that plaintiffs recover no monetary damages.
The Company cannot predict whether the plaintiffs will appeal.
Preference Unitholders
- ----------------------
The Company was a defendant in certain purported class-action lawsuits
related to the December 31, 1991, conversion of the Partnership into the
Company filed in the U.S. District Court for the Northern District of
Texas--Dallas Division in the fall of 1991. The lawsuits were brought under
Section 14(a) of the Securities Exchange Act of 1934 and Rule 14a-9 thereunder,
as well as state law, and alleged, inter alia, that (i) the General Partner
breached fiduciary duties to the holders of Preference Units in structuring the
conversion of the Partnership to corporate form and allocating Common Stock and
(ii) the related proxy statement contained material misstatements and
omissions. This lawsuit sought payment of preferential distribution amounts on
the Preference Units plus unspecified damages, attorneys' fees and other
relief. On January 17, 1992, plaintiffs moved for leave to amend their
compliant to allege that it was also brought under Sections 11, 12(2) and 15 of
the Securities Act of 1933 and Rule 10b-5 under the Exchange Act and to allege
that the Partnership failed to obtain an allegedly required vote of 90% of
unitholders or, in lieu thereof, the required opinion of independent counsel.
On June 5, 1992, a class was certified. On August 12, 1994, the Court granted
defendants' Motion for Summary Judgment and entered a judgment in favor of all
defendants. The plaintiffs appealed, and on June 19, 1995, the Fifth Circuit
affirmed the decision of the District Court. No application for rehearing or
petition for writ of certiorari was filed. Accordingly, the judgment in favor
of the Company is final and nonappealable.
Lease Termination
- -----------------
In 1991 the Company sold certain producing oil and gas properties to
Seagull Energy Company ("Seagull"). In 1994 two lawsuits were filed against
Seagull in the 100th District Court in Carson County, Texas, by certain land
and royalty owners claiming that certain of the oil and gas leases owned by
Seagull have terminated due to cessation in production and/or lack of
production in paying quantities occurring at various times from first
production through 1994. In the third quarter of 1995 Seagull filed third-party
complaints against the Company claiming breach of warranty and false
representation in connection with the sale of such properties to Seagull. The
Company believes it has several defenses to these lawsuits including a two-year
limitation on indemnification set forth in the purchase and sale agreement.
27
<PAGE> 28
Seagull filed a similar third-party complaint June 29, 1995, against the
Company covering a different lease in the 69th District Court in Moore County,
Texas. The Company believes it has similar defenses in this case.
The plaintiffs in the cases against Seagull are seeking to terminate the
leases. Seagull, in its complaint against the Company, is seeking unspecified
damages relating to any leases which are terminated.
Shareholder Litigation
- ----------------------
On July 3, 1995, Robert Strougo filed a class action and derivative action
in the District Court of Dallas County, Texas, 160th Judicial District, against
T. Boone Pickens, Paul W. Cain, John L. Cox, John S. Herrington, Wales H.
Madden, Jr., Fayez S. Sarofim, Robert L. Stillwell, and J. R. Walsh, Jr. (the
"Director Defendants"), each of whom is a present or former director of MESA.
The class action is purportedly brought on behalf of a class of MESA
shareholders and alleges, inter alia, that the Board infringed upon the
suffrage rights of the class and impaired the ability of the class to receive
tender offers by adoptions of the shareholder rights plan. The lawsuit is also
brought derivatively on behalf of MESA and alleges, inter alia, that the Board
breached fiduciary duties to MESA by adopting the shareholder rights plan and
by failing to consider the sale of MESA. The lawsuit seeks unspecified damages,
attorneys' fees, and injunctive and other relief. Two other lawsuits filed by
Herman Krangel, Lilian Krangel, Jacquelyn A. Cady, and William A. Montagne,
Jr., in the District Court of Dallas County have been consolidated into this
lawsuit. The Court is presently considering a motion to dismiss the plaintiffs'
consolidated petition.
On July 18, 1995, Deborah M. Eigen and Adele Brody filed a purported
derivative lawsuit in the U.S. District Court for the Northern District of
Texas, Dallas Division, against the Director Defendants in their capacities as
members of the Board. This lawsuit is brought under state law and alleges,
inter alia, that the Board breached fiduciary duties to MESA by adopting a
shareholder rights plan and by failing to consider the sale of MESA. The
lawsuit is brought derivatively on behalf of MESA and seeks unspecified
damages, attorneys' fees, and other relief. On January 22, 1996, the Court
denied the Director Defendants' motion to dismiss for failure to state a claim.
Contingencies
- -------------
See Note 9 to the consolidated financial statements of the Company
included elsewhere in this Form 10-K for discussion of the above legal
proceedings and the estimated effect, if any, on MESA's results of operations
and financial position.
Item 4. Submission of Matters to a Vote of Security Holders
============================================================
None.
28
<PAGE> 29
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
======================================================================
The following table sets forth, for the periods indicated, the high and
low closing prices for MESA's common stock as reported by the New York Stock
Exchange:
Common Stock
--------------
High Low
------ ------
1995:
First Quarter........................................ $6-1/8 $4-5/8
Second Quarter....................................... 6-1/8 3-1/2
Third Quarter........................................ 5-1/2 3-7/8
Fourth Quarter....................................... 4-7/8 3
1994:
First Quarter........................................ $8-1/2 $5-5/8
Second Quarter....................................... 7 5-3/8
Third Quarter........................................ 5-7/8 5-1/8
Fourth Quarter....................................... 5-1/2 3-5/8
- ----------
* MESA's common stock trades on the New York Stock Exchange under the symbol
MXP. At December 31, 1995, there were 64,050,009 common shares outstanding.
* MESA has not paid any dividends with respect to its common stock and does
not expect to pay dividends in the future unless and until there is a
material and sustained increase in natural gas prices and adequate
provision has been made for further reduction of debt. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and Note 4 to the consolidated financial statements of the
Company included elsewhere in this Form 10-K for a discussion of
restrictions on the payment of dividends.
At March 6, 1996, there were 18,376 record holders of MESA's common
shares.
Item 6. Selected Financial Data
================================
The following table sets forth selected financial information of MESA as
of the dates or for the periods indicated. This table should be read in
conjunction with the consolidated financial statements of the Company and
related notes thereto included elsewhere in this Form 10-K.
29
<PAGE> 30
As of or for the Years Ended December 31
----------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ---------- ----------
(in thousands, except per share data)
Revenues........ $ 234,959 $ 228,737 $ 222,204 $ 237,112 $ 249,546
========== ========== ========== ========== ==========
Operating income $ 47,965 $ 28,683 $ 22,012 $ 26,221 $ 34,128
========== ========== ========== ========== ==========
Net loss........ $ (57,568) $ (83,353) $(102,448) $ (89,232) $ (79,163)
========== ========== ========== ========== ==========
Net loss per
common share... $ (.90) $ (1.42) $ (2.61) $ (2.31) $ (2.05)
========== ========== ========== ========== ==========
Dividends per
common share... $ -- $ -- $ -- $ -- $ --
========== ========== ========== ========== ==========
Total assets.... $1,464,696 $1,483,959 $1,533,382 $1,676,523 $1,832,816
========== ========== ========== ========== ==========
Long-term debt,
including
current
maturities..... $1,236,743 $1,223,293 $1,241,294 $1,286,155 $1,310,705
========== ========== ========== ========== ==========
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
========================================================================
Disclosure Regarding Forward-Looking Statements
- -----------------------------------------------
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K, including without
limitation, the statements under "Capital Resources and Liquidity" and Notes 2
and 4 to the consolidated financial statements of the Company regarding MESA's
financial position, strategic alternatives, and financial instrument covenant
compliance, are forward-looking statements. Although MESA believes that the
expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to have been correct.
Important factors that could cause actual results to differ materially from
MESA's expectations ("Cautionary Statements") are disclosed in this Form 10-K,
including without limitation in conjunction with the forward-looking statements
included in this Form 10-K. All subsequent written and oral forward-looking
statements attributable to MESA or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.
30
<PAGE> 31
Results of Operations
- ---------------------
The following table presents a summary of the results of operations of
MESA for the years indicated:
Years Ended December 31
-------------------------------
1995 1994 1993
--------- --------- ---------
(in thousands)
Revenues.............................. $ 234,959 $ 228,737 $ 222,204
Operating and administrative costs.... (103,571) (107,767) (100,093)
Depreciation, depletion and
amortization........................ (83,423) (92,287) (100,099)
--------- --------- ---------
Operating income...................... 47,965 28,683 22,012
Interest expense, net of
interest income..................... (132,708) (131,300) (131,298)
Other................................. 27,175 19,264 6,838
--------- --------- ---------
Net loss.............................. $ (57,568) $ (83,353) $(102,448)
========= ========= =========
Revenues
--------
The table below presents, for the years indicated, the revenues,
production and average prices received from sales of natural gas, natural gas
liquids and oil and condensate.
Years Ended December 31
----------------------------
1995 1994 1993
-------- -------- --------
Revenues (in thousands):
Natural gas......................... $129,534 $139,580 $141,798
Natural gas liquids................. 75,321 72,771 61,427
Oil and condensate.................. 19,594 7,877 12,428
-------- -------- --------
Total.......................... $224,449 $220,228 $215,653
======== ======== ========
Natural Gas Production (MMcf):
Hugoton............................. 48,871 51,986 47,476
West Panhandle...................... 20,357 22,983 23,786
Gulf Coast.......................... 8,073 7,359 8,517
Other............................... 11 11 41
-------- -------- --------
Total.......................... 77,312 82,339 79,820
======== ======== ========
Natural Gas Liquids Production (MBbls):
Hugoton............................. 3,524 3,430 1,481
West Panhandle...................... 2,994 3,423 3,480
Gulf Coast.......................... 48 53 81
Other............................... 5 5 8
-------- -------- --------
Total.......................... 6,571 6,911 5,050
======== ======== ========
Oil and Condensate Production (MBbls):
Hugoton............................. -- -- 104
West Panhandle...................... 118 164 153
Gulf Coast.......................... 1,025 337 352
Other............................... 52 45 129
-------- -------- --------
Total.......................... 1,195 546 738
======== ======== ========
31
<PAGE> 32
Year Ended December 31
----------------------
1995 1994 1993
------ ------ ------
Weighted average sales price:
Natural gas (per Mcf)
Hugoton............................... $ 1.32 $ 1.57 $ 1.78
West Panhandle........................ 1.83 1.80 1.72
Gulf Coast............................ 1.59 1.81 2.08
Other................................. .54 1.29 .85
------ ------ ------
Average*......................... $ 1.65 $ 1.67 $ 1.79
====== ====== ======
Natural gas liquids (per Bbl)
Hugoton............................... $10.76 $10.03 $12.35
West Panhandle........................ 12.33 11.06 12.04
Gulf Coast............................ 11.37 11.52 12.61
Other................................. 8.77 8.58 10.51
------ ------ ------
Average.......................... $11.48 $10.55 $12.14
====== ====== ======
Oil and condensate (per Bbl)
Hugoton............................... $ -- $ -- $18.21
West Panhandle........................ 14.13 13.38 15.04
Gulf Coast............................ 16.57 15.18 16.69
Other................................. 16.48 14.43 17.08
------ ------ ------
Average.......................... $16.32 $14.58 $16.63
====== ====== ======
* Includes the effects of hedging activities. See "Natural Gas Prices"
below.
The increase in total revenues from sales of natural gas, NGLs, and oil
and condensate from 1994 to 1995 is primarily attributable to increased oil and
condensate production in 1995, increased liquids prices in 1995 and
approximately $12.7 million of natural gas hedge gains recognized in 1995.
These factors offset the decrease in natural gas and natural gas liquids
production and the lower market prices for natural gas production in 1995. The
increase in revenues from 1993 to 1994 was primarily due to increased natural
gas and natural gas liquids production in 1994, partially offset by the
decrease in prices from 1993 to 1994.
Natural gas revenues decreased from 1993 to 1994 and from 1994 to 1995. In
1995 production was lower in both the Hugoton and West Panhandle fields due to
timing and duration of equipment maintenance and weather-related reduction in
demand, respectively. Total natural gas production increased from 1993 to 1994
primarily due to higher allowables in the Hugoton field partially offset by
slightly lower West Panhandle and Gulf Coast production.
32
<PAGE> 33
Average natural gas prices were slightly lower in 1995 than in 1994. Prices
received for market price-based production was $.22 per Mcf (14%) lower in
1995. MESA's hedge gains increased the reported prices for such production by
$.20 per Mcf. The lower market prices were the result of the continuing surplus
of natural gas supply. Average natural gas prices received were 7% lower in
1994 than in 1993 due to generally lower market prices. (See "Natural Gas
Prices" below.)
NGL revenues increased in 1995 compared to 1994. Hugoton field NGL
production was slightly higher despite lower natural gas production reflecting
improved yields from the Satanta Plant. West Panhandle field NGL production
decreased in 1995 in proportion to the lower natural gas production. The lower
production was offset by higher average prices in 1995 due to improved market
conditions for NGLs. NGL production increased from 1993 to 1994 as a result of
increases in Hugoton field liquids production. In the third quarter of 1993 the
Satanta Plant in the Hugoton field was completed. The plant, which is capable
of processing up to 250 MMcf of natural gas per day, replaced MESA's older
Ulysses natural gas processing plant which could process up to 160 MMcf per
day. The Satanta Plant has the ability to extract a greater quantity of NGLs
per Mcf of natural gas, reject nitrogen and produce crude helium.
Oil and condensate revenues increased approximately 150% from 1994 to
1995. Gulf Coast production was up over 200% due to successful drilling in late
1994. Average oil and condensate prices were also higher in 1995 by $1.74 per
Bbl. Prior to the resumption of drilling in the Gulf Coast in 1994, MESA's oil
and condensate production had been on a decline.
West Panhandle production is governed by the terms of a contract with
CIG. See discussion below under "Production Allocation Agreement."
MESA's production from the Hugoton field is affected by the allowables set
for the entire field and by the portion of allowables allocated to MESA's
wells. See "Production -- Hugoton Field" in the business section of this Form
10-K.
Natural Gas Prices
------------------
Substantially all of MESA's natural gas production is sold under short-or
long-term sales contracts. Approximately 80% of MESA's annual natural gas
sales, whether or not such sales are governed by a contract, are at market
prices. The following table shows MESA's natural gas production sold under
fixed price contracts and production sold at market prices:
Years Ended December 31
--------------------------
1995 1994 1993
------ ------ ------
Natural Gas Production (MMcf):
Sold under fixed price contracts.......... 15,212 13,935 19,467
Sold at market prices..................... 62,100 68,404 60,353
------ ------ ------
Total production..................... 77,312 82,339 79,820
====== ====== ======
Percent sold at market prices............. 80% 83% 76%
====== ====== ======
33
<PAGE> 34
In addition to its fixed price contracts, MESA will, when circumstances
warrant, hedge the price received for its market-sensitive production through
natural gas futures contracts. The following table shows the effects of MESA's
fixed price contracts and hedging activities on its natural gas prices:
Years Ended December 31
--------------------------
1995 1994 1993
------ ------ ------
Average Natural Gas Prices (per Mcf):
Fixed price contracts..................... $ 2.12 $ 2.16 $ 1.94
Market prices received.................... 1.33 1.55 1.75
Hedge gains (losses)...................... .20 .01 (.01)
------ ------ ------
Total market prices.................. 1.53 1.56 1.74
------ ------ ------
Total average prices...................... $ 1.65 $ 1.67 $ 1.79
====== ====== ======
Gains and losses from hedging activities are included in natural gas
revenues when the hedged production occurs. MESA recognized gains from hedging
activities of $12.7 million in 1995, $895,000 in 1994, and losses of $324,000
in 1993.
Costs and Expenses
------------------
MESA's aggregate costs and expenses declined by approximately 7% from 1994
to 1995. Lease operating expenses declined marginally due to decreased
production. Production and other taxes decreased 14% from 1994 to 1995 due to
decreased production in the Hugoton and West Panhandle fields and lower tax
rates for Hugoton field production in 1995. See "Production Costs" in the
business section located elsewhere in this Form 10-K. Exploration charges in
1995 were greater than in 1994 reflecting increased exploration activities in
the Gulf of Mexico and consist primarily of exploratory dry-hole expense.
General and administrative ("G&A") expenses were lower in 1995 than in 1994
primarily due to lower legal expenses and a reduction in employee benefit
expenses. Depreciation, depletion and amortization ("DD&A") expense, which is
calculated quarterly on a unit-of-production basis, was lower in 1995 than in
1994 primarily due to lower equivalent production in 1995, oil and gas reserve
increases in the Hugoton and West Panhandle fields in the fourth quarters of
1994 and 1995, and additional reserve discoveries in the Gulf Coast in 1994 and
1995. (See "Supplemental Financial Data" in the notes to the consolidated
financial statements of the Company located elsewhere in this Form 10-K for
discussion of oil and gas reserves.)
MESA's aggregate costs and expenses declined marginally from 1993 to 1994.
Lease operating expenses increased by 2% as a result of higher operating costs
associated with MESA's Satanta Plant and higher Hugoton
34
<PAGE> 35
field production. See "Production Costs" in the business section located
elsewhere in this Form 10-K. Exploration charges in 1994 were greater than in
1993 reflecting MESA's increased exploration activities in the Gulf of Mexico
and resulted primarily from the purchase of 3-D seismic data. G&A expenses were
higher in 1994 than in 1993 primarily due to litigation expenses associated
with MESA's defense of a royalty lawsuit in the West Panhandle field. DD&A
expense was lower in 1994 compared to 1993. DD&A expense reflects the 1994
reserve increases in the Hugoton and West Panhandle fields and reserve
discoveries in the Gulf Coast. (See "Supplemental Financial Data" in the notes
to the consolidated financial statements of the Company located elsewhere in
this Form 10-K.)
Other Income (Expense)
----------------------
Interest expense in 1995 was not materially different from 1994 and 1993
as average aggregate debt outstanding did not materially change.
Interest income increased from $10.7 million in 1993, to $13.5 million in
1994, and to $15.9 million in 1995 as a result of higher average cash balances
and higher average interest rates earned on these cash balances in 1994 and
1995.
Results of operations for the years 1995, 1994, and 1993 include certain
items which are either non-recurring or are not directly associated with MESA's
oil and gas producing operations. The following table sets forth the amounts of
such items (in thousands):
Years Ended December 31
-------------------------
1995 1994 1993
------- ------- -------
Gains from investments...................... $18,420 $ 6,698 $ 3,954
Gains from collections from Bicoastal
Corporation............................... 6,352 16,577 18,450
Gains on dispositions of oil
and gas properties........................ -- -- 9,600
Litigation settlement....................... -- -- (42,750)
Gain from adjustment of contingency reserve. -- -- 24,000
Expense of debt exchange transaction........ -- -- (9,651)
Other....................................... 2,403 (4,011) 3,235
------- ------- -------
Total Other Income..................... $27,175 $19,264 $ 6,838
======= ======= =======
The gains from investments relate to MESA's investments in marketable
securities and energy futures contracts, which include New York Mercantile
Exchange ("NYMEX") futures contracts, commodity price swaps and options that
are not accounted for as hedges of future production. MESA's investments in
marketable securities and futures contracts are valued at market prices at each
reporting date with gains and losses included in the statement of operations
for such reporting period whether or not such gains or losses have been
realized. At December 31, 1995, MESA had recognized but not realized
approximately $7.6 million of gains primarily associated with open positions in
natural gas futures contracts. As of March 6, 1996, MESA had
35
<PAGE> 36
closed substantially all of the positions open at December 31, 1995, at a
realized loss of $156,000. Positions which were open at December 31, 1995, and
remain open had unrealized gains of $1.7 million at March 6, 1996.
The gains from collection of interest from Bicoastal Corporation relate to
a note receivable from such company, which was in bankruptcy. MESA's claims in
the bankruptcy exceeded its recorded receivable. As of year-end 1995, MESA had
collected the full amount of its allowed claim plus a portion of the interest
due on such claims. The gains on dispositions of oil and gas properties relate
primarily to 1993 sales of oil producing properties in the deep Hugoton and
Rocky Mountain areas for approximately $26 million.
The litigation settlement charge relates to MESA's 1994 settlement of a
lawsuit with Unocal Corporation ("Unocal"). The litigation related to a 1985
investment in Unocal by Original Mesa and certain other defendants. The
plaintiffs had sought to recover alleged "short-swing profits" plus interest
totaling over $150 million pursuant to Section 16(b) of the Securities Exchange
Act of 1934. In early 1994 MESA and the other defendants reached a settlement
with the plaintiffs and agreed to pay $47.5 million to Unocal, of which MESA's
share was $42.8 million. MESA issued additional 12-3/4% secured discount notes
due June 30, 1998 with a face amount of $48.2 million to fund its share of the
settlement.
In the fourth quarter of 1993, MESA completed a settlement with the
Internal Revenue Service (the "IRS") resolving all tax issues relating to the
1984 through 1987 tax returns of Original Mesa. MESA had previously established
contingency reserves for the IRS claims and certain other contingent
liabilities in excess of the actual and estimated liabilities. As a result of
the settlement with the IRS and the resolution and revaluation of certain other
contingent liabilities, MESA recorded a net gain of $24 million in the fourth
quarter of 1993.
The debt exchange expense relates to costs associated with MESA's $600
million debt exchange transaction completed in 1993.
Production Allocation Agreement
-------------------------------
Effective January 1, 1991, MESA entered into the PAA with CIG which
allocates 77% of reserves and production from the West Panhandle field to MESA
and 23% to CIG. During 1995, 1994, and 1993, MESA produced and sold 71%, 69%,
and 74%, respectively, of total production from the field; the balance of field
production was sold by CIG. MESA records its 77% ownership interest in natural
gas production as revenue. The difference between the net value of production
sold by MESA and the net value of its 77% entitlement is accrued as a gas
balancing receivable. The revenues and costs associated with such accrued
production are included in results of operations.
36
<PAGE> 37
The following table presents the incremental effect on production and
results of operations from entitlement production recorded in excess of actual
sales as a result of the PAA (dollars in thousands):
Years Ended December 31
--------------------------- January 1, 1991
1995 1994 1993 To Date
------- ------- ------- ---------------
Revenues accrued........... $ 4,260 $ 8,662 $ 5,145 $58,715
Costs and expenses accrued. (1,576) (3,075) (1,059) (16,145)
------- ------- ------- -------
Recorded to receivable..... 2,684 5,587 4,086 42,570
------- ------- ------- -------
Depreciation, depletion
and amortization......... (1,680) (3,713) (1,244) (25,142)
------- ------- ------- -------
Total................. $ 1,004 $ 1,874 $ 2,842 $17,428
======= ======= ======= =======
Production Accrued:
Natural gas (MMcf).... 1,155 2,386 740 15,887
Natural gas liquids
(MBbls)............. 171 355 106 2,275
At December 31, 1995, the long-term gas balancing receivable from CIG, net
of accrued costs, relating to the PAA was $42.6 million, which is included in
other assets in the consolidated balance sheet. The provisions of the PAA allow
for periodic and ultimate cash balancing to occur. The PAA also provides that
CIG may not take in excess of its 23% share of ultimate production.
Capital Resources and Liquidity
- -------------------------------
MESA is primarily in the business of exploring for, developing, producing,
processing and selling natural gas and oil. MESA owns and operates its oil and
gas properties and other assets through its direct and indirect subsidiaries
which include MOC, MHC and HCLP.
At December 31, 1995, MESA owned almost 1.9 trillion cubic feet of
estimated proved equivalent natural gas reserves. MESA's reserves are located
in the Hugoton field of southwest Kansas (64%), the West Panhandle field of
Texas (32%), the Gulf Coast (3%), and the Rocky Mountains (1%). MOC owns all of
MESA's interest in the West Panhandle field, the Gulf Coast and the Rocky
Mountains. HCLP owns substantially all of MESA's Hugoton field interests with
MOC holding the remaining portion of such interests. MHC owns no oil and gas
property interests, but does have a substantial amount of cash and investments.
MESA is highly leveraged with over $1.2 billion of long-term debt,
including current maturities. HCLP is the obligor on approximately $505 million
(41%) of MESA's debt which is secured by HCLP's Hugoton property interests. The
obligors on the remainder of MESA's debt are the Company and MOC; the majority
of such debt is secured by liens on the West Panhandle field properties and a
portion of MOC's equity interest in HCLP.
37
<PAGE> 38
The assets and cash flows of HCLP that are subject to the mortgage
securing HCLP's debt are dedicated to service HCLP's debt and are not available
to pay creditors of MESA or its subsidiaries other than HCLP.
The debt of MOC and the Company, more fully described below, consists
primarily of bank debt and secured and unsecured discount notes (the "Discount
Notes"). MESA's current financial forecasts indicate, assuming no changes in
its capital structure and no significant transactions are completed, that cash
generated by operating activities, together with cash and investments on hand,
will not be sufficient for MOC and the Company to make all of the debt
principal and interest obligations due in June 1996. In addition, certain
covenants related to MESA's bank debt and certain cross-default provisions of
the Discount Notes could result in the acceleration of approximately $656
million of long-term debt principal due in mid-1997 and mid-1998 to the first
half of 1996.
In an effort to address its liquidity issues, the Board approved and
implemented a proposal solicitation process which started in late 1994 and was
expanded in mid-1995. The process has included solicitation of proposals for a
sale of MESA, a stock-for-stock merger, joint ventures, asset sales, equity
infusions, and refinancing transactions. On February 28, 1996, MESA signed a
letter of intent with Rainwater to raise $265 million of equity in connection
with a refinancing of MESA's debt.
Set forth below and in Notes 2 and 4 to the consolidated financial
statements of the Company, is a more detailed discussion of MESA's debt, its
capital resources and liquidity, the Rainwater transaction, and the other
alternatives MESA may pursue to address its liquidity issues.
38
<PAGE> 39
Long-term Debt
--------------
The following table provides additional information as to MESA's long-term
debt at December 31, 1995 (in thousands):
Obligors
------------------
MOC HCLP Total
-------- -------- ----------
Debt:
HCLP Secured Notes(a)............ $ -- $504,674 $ 504,674
Credit Agreement(b).............. 61,131 -- 61,131
12-3/4% secured discount
notes(c)(e).................... 618,518 -- 618,518
12-3/4% unsecured discount
notes(d)(e)..................... 39,725 -- 39,725
Other............................. 12,695 -- 12,695
-------- -------- ----------
732,069 504,674 1,236,743
Current maturities..................... (67,530) (33,883) (101,413)
-------- -------- ----------
Long-term debt......................... $664,539 $470,791 $1,135,330
======== ======== ==========
- ----------
(a) These notes are secured by the Hugoton field properties and are due
in semiannual installments through August 2012, but may be repaid
earlier depending on the rate of production from the properties.
(b) The bank credit facility (the "Credit Agreement") is secured by a
first lien on MOC's West Panhandle field properties, MESA's equity
interest in MOC and a 76% limited partnership interest in HCLP and is
due in various installments through June 1997. At December 31, 1995,
the Credit Agreement also supported letters of credit totaling $11.4
million that are not included in the table above.
(c) These notes are due in June 1998 and are secured by second liens on
MOC's West Panhandle field properties and a 76% limited partnership
interest in HCLP.
(d) These notes are unsecured and are due on June 30, 1996.
(e) The Discount Notes began accruing interest, payable semiannually
beginning on December 31, 1995, at a rate of 12-3/4% per annum on
July 1, 1995.
39
<PAGE> 40
The following tables summarize MESA's 1995 actual and 1996 through 1999
forecast cash requirements, assuming no changes in capital structure, for
interest, debt principal and capital expenditures (in thousands):
Actual Forecast
-------- -----------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- --------
HCLP:
Interest payments,
net(a)................$ 45,399 $ 46,700 $ 44,300 $ 41,700 $ 38,900
Principal repayments(b). 15,507 33,900 33,300 36,100 37,100
Capital expenditures(c). 9,682 4,000 900 200 200
-------- -------- -------- -------- --------
$ 70,588 $ 84,600 $ 78,500 $ 78,000 $ 76,200
======== ======== ======== ======== ========
MOC and the Company:
Interest payments,
net(a)................$ 3,427 $132,800 $ 97,300 $ 98,100 $ 84,700
Principal repayments:
Credit Agreement(d). 10,000 22,500 38,600 -- --
12-3/4% unsecured
discount notes(e). -- 39,700 -- -- --
12-3/4% secured
discount notes(e). -- -- -- 617,400 --
13-1/2%
subordinated
notes............. -- -- -- -- 7,400
Other............... -- 5,300 -- -- --
Capital expenditures(c). 32,615 24,000 14,500 500 --
-------- -------- -------- -------- --------
$ 46,042 $224,300 $150,400 $716,000 $ 92,100
======== ======== ======== ======== ========
- ----------
(a) Cash interest payments, net of interest income. The interest payments
due on December 31, 1995, related to the Discount Notes, were made on
January 2, 1996, in accordance with the terms of the indentures and
are reflected as 1996 cash outflows.
(b) HCLP Secured Note principal payments are determined based on actual
or deemed production from the HCLP Hugoton properties. Such principal
payment could be greater under certain circumstances. See Note 4 to
the consolidated financial statements of the Company included
elsewhere in this Form 10-K.
(c) Forecast capital expenditures represent MESA's best estimate of
drilling and facilities expenditures required to attain projected
levels of production from its existing properties during the
forecast period and to fund its current exploration and
development program. Capital expenditures in 1996 include $9.5
million of committed capital expenditures. Capital expenditures
may be greater than or less than the amounts reflected in the
table.
40
<PAGE> 41
(d) Amounts due under the Credit Agreement may be accelerated if tangible
adjusted equity falls below $50 million. (See discussion below.)
Also, principal repayments set forth in the table do not include the
$11.4 million in letter of credit obligations currently outstanding
and required to be cash collateralized when final maturities under
the Credit Agreement are repaid.
(e) Amounts due under the Discount Notes may be accelerated if there is a
continuing Event of Default under the Credit Agreement.
The Credit Agreement requires MESA to maintain tangible adjusted equity,
as defined, of $50 million, and available cash, as defined, of $32.5 million.
At December 31, 1995, MESA's tangible adjusted equity was approximately $64.7
million and available cash was $139.5 million.
Assuming no changes in its capital structure and no significant
transactions are completed, the Company expects to continue to report
substantial net losses and expects its tangible adjusted equity to fall below
$50 million in the first half of 1996. If and when MESA determines that
tangible adjusted equity is below $50 million, an Event of Default would occur
under the Credit Agreement and the bank would have the right to accelerate the
payment of all outstanding principal and require cash collateralization of
letters of credit. Unless and until the Credit Agreement default were cured or
waived or the debt under the Credit Agreement were repaid or otherwise
discharged, an Event of Default under the Credit Agreement would cause a cross
default under the Discount Note indentures. Pursuant to the subordination
provisions of such indentures, MESA would be prohibited from making any
payments on the Discount Notes for specified periods upon and during the
continuance of any Event of Default under the Credit Agreement.
The Credit Agreement and the indentures governing the Discount Notes
restrict, among other things, MESA's ability to incur additional indebtedness,
create liens, pay dividends, acquire stock or make investments, loans and
advances.
41
<PAGE> 42
Company Resources and Cash Flows
--------------------------------
The following table sets forth certain of MESA's near-term resources as of
or for the year ended December 31, 1995 (in thousands):
MOC HCLP MHC Total
------- ------- ---------- --------
Cash and investments(a)........ $65,441 $47,613 $74,369 $187,423
Working capital (deficit)...... (37,530) 3,393 77,938 43,801
Restricted cash(b)............. -- 57,731 -- 57,731
Cash flows from operating activities:
Oil and gas sales, net
of production and
administrative costs..... $61,447 $63,810 $ -- $125,257
Interest payments, net(c). (7,988) (45,399) 4,561 (48,826)
Other..................... (2,702) 1,175 (5,663) (7,190)
------- ------- ------- --------
Net cash provided by
(used in) operating
activities............. $50,757 $19,586 $(1,102) $ 69,241
======= ======= ======= ========
- ----------
(a) Included in working capital. HCLP cash includes $40.2 million which
is subject to the HCLP Secured Note mortgage. On January 2, 1996, MOC
made a $42 million interest payment on its Discount Notes.
(b) Non-current asset in balance sheet. Represents a liquidity
reserve account established for the HCLP Secured Notes.
(c) Cash interest payments, net of interest income.
MESA's current financial forecasts indicate, assuming no changes in its
capital structure and no significant transactions are completed, that cash
generated by operating activities, together with available cash and investment
balances, will be not be sufficient to make all of its required debt principal
and interest obligations due in June 1996. If amounts outstanding under the
Credit Agreement were to be accelerated in the first half of 1996, MESA would
expect to have sufficient cash to meet the Credit Agreement obligations and
cure an Event of Default under the Credit Agreement and avoid, at that time,
cross defaults under the terms of its Discount Note indentures. However, such a
payment would substantially deplete MESA's remaining cash and investments
balances. MESA will make decisions regarding such payments on its debt as they
come due, taking into account the status at that time of the Rainwater
transaction discussed below.
42
<PAGE> 43
Exploration of Strategic Alternatives/
Proposed Transaction With Rainwater
--------------------------------------
In an effort to address its liquidity issues and to position MESA for
expansion through exploration and development, in December 1994 MESA announced
its intent to sell all or a portion of its interests in the Hugoton field. In
the first quarter of 1995 MESA began an auction process to sell such
properties. MESA's Board concluded the auction process in the second quarter of
1995 after no acceptable bids were received for the Hugoton properties.
On July 6, 1995, the Board approved and implemented a proposal
solicitation process which expanded its exploration of strategic alternatives
to include consideration of the sale of MESA, a stock-for-stock merger, joint
ventures, asset sales, equity infusions, and refinancing transactions. MESA
engaged an independent financial advisor to assist in these efforts and to
solicit proposals on its behalf. The proposal solicitation process commenced in
August 1995 and MESA received proposals beginning on November 20, 1995.
On February 28, 1996, MESA signed a letter of intent with Rainwater to
raise $265 million of equity in connection with a refinancing of MESA's debt.
Pursuant to the terms of the letter of intent, Rainwater will purchase in a
private placement approximately 58.8 million shares of a new class of
convertible preferred stock and MESA will offer approximately 58.4 million
shares of convertible preferred stock to MESA stockholders in a rights offering
(the "Rights Offering"). Rainwater will provide a standby commitment to
purchase any shares of preferred stock not subscribed to in the Rights
Offering. Rights will be distributed to common stockholders on a pro rata
basis. The rights will allow the stockholder to purchase, in respect of each
share of common stock, approximately .91 shares of preferred stock at $2.26 per
share, the same per share price at which Rainwater will purchase preferred
shares. The rights will be transferrable and holders of the rights will be
offered over-subscription privileges for shares not purchased by other rights
holders.
Each preferred share will be convertible into one share of MESA common
stock at any time prior to mandatory redemption in 2006. An annual 8%
pay-in-kind dividend will be paid on the preferred shares during the first four
years following issuance. Thereafter, the 8% dividend may, at the option of
MESA, be paid in cash or additional shares depending on whether certain
financial tests are met.
The preferred stock will represent 63.6% of the fully diluted common shares
at the time of issuance and 70.6% after the mandatory four-year pay-in-kind
period, assuming no other stock issuance by MESA. The preferred stock will have
a liquidation price equal to the purchase price. The preferred shares purchased
in the Rights Offering will vote with the common stock as a single class on all
matters, except as otherwise required by law and except for certain special
voting rights for shares held by Rainwater.
Rainwater will be entitled to elect two members of MESA's Board, which
will have seven directors. The Rainwater designees will constitute two of
the three members of a newly formed executive committee of the Board. The
43
<PAGE> 44
executive committee will act for the whole Board on matters which by law do not
need Board authorization and will have authority over major capital
transactions, stock issuances, financing arrangements, budgeting, and other
items.
During an interim 30-day period beginning February 28, 1996, MESA, with
assistance from Rainwater, will seek commitments for new bank loans plus
assurance of availability of new subordinated debt to be issued in conjunction
with the transaction. Proceeds from the new debt, when combined with proceeds
from the newly issued equity and MESA's available cash balances, would
refinance or repay all of MESA's existing debt.
The proposed transaction is subject to certain conditions, including
negotiation and execution of definitive agreements, arrangement of the new debt
financing, due diligence by Rainwater and MESA stockholder approval. The
parties anticipate executing definitive agreements in about 30 days. The
transaction will be submitted to a vote of stockholders at a special meeting
expected to take place in June 1996. The Rights Offering would commence
promptly after that meeting. There can be no assurance that this transaction
will be completed, or if completed, what the final terms or timing thereof will
be. Nor can there be any assurance regarding the availability or terms of any
refinancing debt.
The ability of MESA to continue as a going concern is dependent upon
several factors. The successful completion of the Rainwater transaction is
expected to position MESA to continue as a going concern and to pursue its
business strategies. The consolidated financial statements of MESA do not
include any adjustments reflecting any treatment other than going concern
accounting.
If the Rainwater transaction is not completed, MESA will pursue other
alternatives to address its liquidity issues and financial condition, including
other potential transactions arising from the proposal solicitation process,
the possibility of seeking to restructure its balance sheet by negotiating with
its current debt holders or seeking protection from its creditors under the
Federal Bankruptcy Code.
Other
- -----
See Note 9 to the consolidated financial statements of the Company
included elsewhere in this Form 10-K for information regarding the status of
certain pending litigation.
In March 1995 the Financial Accounting Standards Board (the "FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," which establishes accounting standards for the impairment of long-lived
assets, certain identifiable intangibles and goodwill. (See Note 1 to the
consolidated financial statements of the Company included elsewhere in this
Form 10-K for discussion of this accounting standard.)
MESA recognizes its ownership interest in natural gas production as
revenue. Actual production quantities sold may be different from MESA's
44
<PAGE> 45
ownership share of production in a given period. MESA records these differences
as gas balancing receivables or as deferred revenue. Net gas balancing
underproduction represented approximately 2% of total equivalent production for
the year ended December 31, 1995, compared with 5% during the same period in
1994 and 3% in 1993. The gas balancing receivable or deferred revenue component
of natural gas and natural gas liquids revenues in future periods is dependent
on future rates of production, field allowables and the amount of production
taken by MESA or by its joint interest partners.
MESA invests from time to time in marketable equity and other securities,
as well as in energy-related commodity futures contracts, which include NYMEX
futures contracts, price swaps and options. MESA also enters into natural gas
futures contracts as a hedge against natural gas price fluctuations.
Management does not anticipate that inflation will have a significant
effect on MESA's operations.
Item 8. Consolidated Financial Statements and Supplementary Data
=================================================================
The consolidated financial statements of the Company, and notes thereto,
together with the report of Arthur Andersen LLP, MESA's independent public
accountants, dated March 6, 1996, and supplementary data are included in this
Form 10-K under Item 14 on pages F-2 through F-8.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
========================================================================
None.
45
<PAGE> 46
PART III
Item 10. Directors and Executive Officers of the Registrant
============================================================
Directors
---------
The following table sets forth each person on the Board of Directors of the
Registrant, (i) his name and age, (ii) the period during which he has served as
a director, and (iii) his principal occupation over the last five years
(including other directorships and business experience):
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Boone Pickens, age 67.................. January 1992-Present, Chairman
of the Board of Directors and
Chief Executive Officer of the
Company; October 1985-December
1991, General Partner of Mesa
Limited Partnership (prede-
cessor to the Company and
hereinafter referred to as the
"Partnership") and Chief
Executive Officer and Director
of Pickens Operating Co., (the
corporate general partner of
the Partnership); 1964-January
1987, Chairman of the Board,
President, and founder of Mesa
Petroleum Co. (predecessor to
the Partnership, hereinafter
referred to as "Original
Mesa").
Paul W. Cain, age 57................... January 1992-Present, Director,
President and Chief Operating
Officer of the Company; August
1986-December 1991, President
and Chief Operating Officer of
Pickens Operating Co.; Director
of Bicoastal Corporation.
John S. Herrington, age 56............. January 1992-Present, Director
of the Company; December 1991
-Present, personal investments
and real estate activities; May
1990-November 1991, Chairman of
the Board of Harcourt Brace
Jovanovich, Inc. (publishing);
May 1989-May 1990, Director of
Harcourt Brace Jovanovich,
Inc.; February 1985-January
1989, Secretary of the
Department of Energy of the
United States.
46
<PAGE> 47
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Wales H. Madden, Jr., age 68........... January 1992-Present, Director
of the Company; December 1985
-December 1991, Member of the
Advisory Committee of the
Partnership; 1964-January 1987,
Director of Original Mesa; Self
-employed attorney and
businessman for more than the
last five years; Director of
Boatmen's First National Bank
of Amarillo.
Dorn Parkinson, age 49..................May 1995-Present, Director of the
Company; April 1986- Present,
President of Washington
Corporations (principal businesses
of Washington Corporations and its
affiliates include rail transport,
mining, ship berthing,
environmental remediation,
interstate trucking, and the
repair and sale of machinery and
equipment); January 1995- Present,
Chairman of the Board of Kasler
Holding Company (heavy
construction and contract mining);
July 1993- October 1994, President
and Chief Operating Officer of
Kasler Holding Company; Director
of Kasler Holding Company.
Joel L. Reed, age 45....................September 1995-Present,
Director of the Company;
August 1994-Present, partner
with Batchelder & Partners,
Inc.; October 1984-July 1994,
various capacities including
Chief Financial Officer,
President and Chief Executive
Officer of Wagner and Brown,
Ltd. and affiliates (privately
owned company consisting of
companies engaged in energy,
real estate, manufacturing,
agribusiness, and investment
services); Director of Magnetic
Delivered Therapeutics.
Fayez S. Sarofim, age 67............... January 1992-Present, Director
of the Company; Chairman of the
Board and President of Fayez
Sarofim & Co. (investment
adviser) for more than the last
five years; Director of
Teledyne, Inc., Unitrin, Inc.,
Argonaut Group, Inc., and
Imperial Holly Corporation.
47
<PAGE> 48
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Robert L. Stillwell, age 59............ January 1992-Present, Director
of the Company; December 1985
-December 1991, Member of the
Advisory Committee of the Part-
nership; 1969-January 1987,
Director of Original Mesa;
Partner in the law firm of
Baker & Botts, L.L.P., for more
than the last five years.
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<PAGE> 49
Executive Officers
------------------
The following table sets forth the name, age, and five-year employment
history of each Executive Officer of the Company:
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Boone Pickens, age 67.................. January 1992-Present, Chairman
of the Board of Directors and
Chief Executive Officer of the
Company; October 1985-December
1991, General Partner of the
Partnership and Chief Executive
Officer and Director of Pickens
Operating Co.; 1964-January
1987, Chairman of the Board,
President, and founder of
Original Mesa.
Paul W. Cain, age 57................... January 1992-Present, Director,
President and Chief Operating
Officer of the Company; August
1986-December 1991, President
and Chief Operating Officer of
Pickens Operating Co.; Director
of Bicoastal Corporation.
Dennis E. Fagerstone, age 47........... January 1992-Present, Vice
President-Exploration and
Production of the Company; May
1991-December 1991, Vice
President-Exploration and
Production of Pickens Operating
Co.; June 1988-May 1991, Vice
President-Operations of Pickens
Operating Co.
Stephen K. Gardner, age 36............. June 1994-Present, Vice
President and Chief Financial
Officer of the Company; January
1992-May 1994, Vice President
of BTC Partners Inc. (financial
consultant to the Company); May
1988-December 1991, Financial
Analyst of BTC Partners, Inc.;
June 1987-April 1988, Financial
Analyst of the Partnership;
Director of Bicoastal
Corporation.
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Andrew J. Littlefair, age 35........... January 1992-Present, Vice
President-Public Affairs of the
Company; August 1987-December
1991, Assistant to the General
Partner of the Partnership;
January 1984-August 1987, Staff
Assistant to the President of
the United States, Washington,
D.C.
William D. Ballew, age 37.............. January 1992-Present, Con-
troller of the Company; May
1991-December 1991, Controller
of the Partnership; January
1991-May 1991, Manager-
Accounting of Pickens Operating
Co.; December 1988-December
1990, Assistant to the
Controller of Pickens Operating
Co.; July 1986-December 1988,
Audit Manager for Price
Waterhouse, Dallas, Texas.
Item 11. Executive Compensation
================================
The table set forth below contains certain information regarding
compensation earned by, awarded to, or paid to the Chief Executive Officer and
the other four most highly compensated executive officers of the Company for
services rendered to the Company during the years 1993, 1994 and 1995.
49
<PAGE> 50
Summary Compensation Table
--------------------------
Annual Compensation
----------------------------------
Other Annual
Name and Principal Position Year Salary Bonus Compensation(1)
- -------------------------------- ---- -------- -------- ------------
Boone Pickens, 1995 $675,000 $ 0 $ --
Chairman of the Board of 1994 675,000 175,000 --
Directors and Chief Executive 1993 675,000 0 --
Officer
Paul W. Cain, 1995 400,020 0 --
President and Chief Operating 1994 400,020 150,000 --
Officer 1993 400,020 225,000 --
Dennis E. Fagerstone, 1995 199,980 50,000 --
Vice President-Exploration 1994 199,980 100,000 --
and Production 1993 199,980 75,000 --
Stephen K. Gardner, 1995 175,020 40,000 --
Vice President and Chief 1994(8) 92,095 60,000 --
Financial Officer 1993 -- -- --
Andrew J. Littlefair, 1995 139,980 40,000 --
Vice President-Public Affairs 1994 115,980 100,000 --
1993 115,980 75,000 --
Long-Term
Compensation
Awards-Number
of Shares
Underlying All Other
Name and Principal Position Year Options/SARs Compensation(2)
- -------------------------------- ---- --------------- ---------------
Boone Pickens, 1995 0 $ 35,914(3)
Chairman of the Board of 1994 200,000 1,094,500(4)
Directors and Chief Executive 1993 275,000 114,750
Officer
Paul W. Cain, 1995 0 22,165(5)
President and Chief Operating 1994 150,000 93,503
Officer 1993 100,000 106,253
Dennis E. Fagerstone, 1995 0 14,663(6)
Vice President-Exploration 1994 85,000 50,997
and Production 1993 10,000 46,747
Stephen K. Gardner, 1995 0 12,915(7)
Vice President and Chief 1994(8) 135,000 25,856
Financial Officer 1993 -- --
Andrew J. Littlefair, 1995 0 11,163(9)
Vice President-Public Affairs 1994 85,000 36,717
1993 25,000 32,467
(1) Apart from the compensation set forth in the summary compensation table
and under the plans and pursuant to the transactions described below,
other compensation paid for services during the years ended December
31, 1995, 1994, and 1993, respectively, to each individual named in the
summary compensation table aggregated less than 10% of the total salary
and bonus reported for such individual in the summary compensation
table, or $50,000, if lower.
(2) Except as reflected in other notes, "All Other Compensation" consists
of the following items. First, the Company maintains an Employees
Premium Plan and a Profit Sharing Plan, both of which are retirement
plans (the "Retirement Plans"), for all employees (see separate
discussion below). The Company declared contributions to the
Retirement Plans of 5% of each employee's compensation in 1995 and 17%
of each employee's compensation in 1994 and 1993. However, total
employer contributions to the Retirement Plans for the account of a
participant in any calendar year are limited as specified by the
Internal Revenue Code (the "Code") and the Retirement Plans. See
"Limitation on Contributions to Benefit Plans" below. The maximum
annual amount of employer contributions to a participant's accounts in
the Retirement Plans totaled $7,500 in 1995, $25,500 in 1994, and
$30,000 in 1993. Second, to the extent that 5% of an employee's total
compensation exceeded $7,500 in 1995, that 17% of an employee's total
compensation exceeded $25,500 in 1994 (in both cases, all employees
50
<PAGE> 51
with total compensation in excess of $150,000), and that 17% of an
employee's total compensation exceeded $30,000 in 1993 (all employees
with total compensation in excess of $176,470), the Company, as a
matter of policy, paid the excess amount in cash to such employee.
Third, in 1995 there was a reallocation to participant accounts of
forfeitures in the Profit Sharing Plan from unvested balances in the
accounts of employees who terminated during 1994.
(3) Includes the following: a $7,500 Retirement Plans contribution; a $2,164
reallocation of forfeitures in the Profit Sharing Plan; a $26,250 payment
in lieu of a Retirement Plans contribution in excess of the contribution
limitation as described in Note 2 above.
(4) Includes the following: a $25,500 Retirement Plans contribution; a
$119,000 payment in lieu of a Retirement Plans contribution in excess
of the contribution limitation as described in Note 2 above; a $950,000
bonus payment that has been deferred until Mr. Pickens' retirement and
that was subject to his continued employment (except in certain events)
through December 31, 1995, with respect to the Company's 1994
commodities and securities investment activities managed by him.
(5) Includes the following: a $7,500 Retirement Plans contribution; a $2,164
reallocation of forfeitures in the Profit Sharing Plan; a $12,501 payment
in lieu of a Retirement Plans contribution in excess of the contribution
limitation as described in Note 2 above.
(6) Includes the following: a $7,500 Retirement Plans contribution; a $2,164
reallocation of forfeitures in the Profit Sharing Plan; a $4,999 payment
in lieu of a Retirement Plans contribution in excess of the contribution
limitation as described in Note 2 above.
(7) Includes the following: a $7,500 Retirement Plans contribution; a $2,164
reallocation of forfeitures in the Profit Sharing Plan; a $3,251 payment
in lieu of a Retirement Plans contribution in excess of the contribution
limitation as described in Note 2 above.
(8) Mr. Gardner became an officer of the Company in June 1994.
(9) Includes the following: a $7,500 Retirement Plans contribution; a $2,164
reallocation of forfeitures in the Profit Sharing Plan; a $1,499 payment
in lieu of a Retirement Plans contribution in excess of the contribution
limitation as described in Note 2 above.
Employees Premium and Profit Sharing Plans
- ------------------------------------------
MESA maintains the Retirement Plans for the benefit of its employees. Each
year, the Company is required to contribute to the Employees Premium Plan 5% of
the total compensation (as defined in the plan) paid to participants and may
also contribute up to 12% of total compensation (as defined) to the Profit
Sharing Plan. In previous years, the Company had declared contributions of 17%
to the Retirement Plans. In 1995 the Company declared contributions of 5% to
the Retirement Plans.
Participants become 30% vested in their account balances in the Retirement
Plans after three years of service and 40% vested after four years of service.
Participants become vested an additional 20% for each
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<PAGE> 52
additional year of service through year seven. Effective December 31, 1991, in
conjunction with the conversion of the Partnership to the Company (the
"Corporate Conversion"), all participants were fully vested in their account
balances in the Retirement Plans as of that date as a result of certain
property dispositions consummated in 1990 and 1991. Participants remain fully
vested in their 1991 balances, but contributions in 1992 and later years under
the Retirement Plans are subject to the vesting schedule described above.
Prior years of service with the Company's predecessors are counted in the
vesting schedule. Amounts accumulated and vested are distributable only under
certain circumstances, including termination of the Retirement Plans.
Limitation on Contributions to Benefit Plans
- --------------------------------------------
Total employer contributions to the Retirement Plans for the account of a
participant in any calendar year are limited to the lesser of what is specified
by the Code or by the Retirement Plans. The Code provides that annual additions
to a participant's account may not exceed the lesser of $30,000 or 25% of the
amount of the participant's annual compensation. The Retirement Plans provide
that aggregate annual additions to a participant's account may not exceed 17%
of eligible compensation as defined by the Retirement Plans. The eligible
compensation per the Code was limited to $150,000 in 1995, $150,000 in 1994,
and $228,000 in 1993. The Company, in its discretion, may determine to make
cash payments of amounts attributable to an employee's participation in the
Retirement Plans to the extent such amounts exceed the Code limitations. As a
matter of general policy for employees of the Company, the Company makes annual
cash payments directly to employees to the extent that the annual additions to
the account of each such employee pursuant to the Retirement Plans would exceed
the Code limitations.
1991 Stock Option Plan
- ----------------------
The 1991 Stock Option Plan (the "Option Plan") was approved by
stockholders in 1991 and amended by stockholders in 1994. Its purpose is to
serve as an incentive to, and aid in the retention of, key executives and other
employees whose training, experience, and ability are considered important to
the operations and success of the Company. The Option Plan is administered by
the Stock Option Committee composed of non-employee directors of the Company
who meet the requirements of "disinterested person" in Rule 16b-3 (c)(2)(i) of
the Securities Exchange Act of 1934. Pursuant to the Option Plan, the Stock
Option Committee is given the authority to designate plan participants, to
determine the terms and provisions of options granted thereunder, and to
supervise the administration of the plan. A total of 4,000,000 shares of Common
Stock are currently subject to the plan, of which options for 3,062,950 shares
have been granted. At December 31, 1995, the following stock options were
outstanding:
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<PAGE> 53
Number of
Options
---------
Granted.................................................... 3,062,950
Exercised.................................................. (62,720)
Forfeited.................................................. (67,840)
---------
Outstanding at December 31, 1995........................... 2,932,390
=========
Shares of Common Stock subject to an option are awarded at an exercise
price that is equivalent to at least 100% of the fair market value of the
Common Stock on the date the option is granted. The purchase price of the
shares as to which the option is exercised is payable in full at exercise in
cash or in shares of Common Stock previously held by the optionee for more than
six months, valued at their fair market value on the date of exercise. Subject
to Stock Option Committee approval and to certain legal limitations, an
optionee may pay all or any portion of the purchase price by electing to have
the Company withhold a number of shares of Common Stock having a fair market
value equal to the purchase price. Options granted under the Option Plan
include a limited right of relinquishment that permits an optionee, in lieu of
purchasing the entire number of shares subject to purchase thereunder and
subject to consent of the Stock Option Committee, to relinquish all or part of
the unexercised portion of an option, to the extent exercisable, for cash
and/or shares of Common Stock in an amount representing the appreciation in
market value of the shares subject to such options over the exercise price
thereof. In its discretion, the Stock Option Committee may provide for the
acceleration of any unvested installments of outstanding options. The Board of
Directors may amend, alter, or discontinue the Option Plan, subject in certain
cases to stockholder approval.
The options granted and outstanding at December 31, 1995, have exercise
prices and vesting schedules as set forth in the following table:
Exercise Vesting Schedule
Number of Price Per --------------------------------------------
Options Share 30% 55% 80% 100%
- --------- --------- -------- -------- -------- --------
1,126,000 $ 6.8125 07/10/92 01/10/93 01/10/94 01/10/95
134,500 11.6875 04/02/93 10/02/93 10/02/94 10/02/95
101,890 5.8125 11/18/93 05/18/94 05/18/95 05/18/96
475,000 7.3750 05/10/94 11/10/94 11/10/95 11/10/96
75,000 6.1875 12/06/94 06/06/95 06/06/96 06/06/97
1,000,000 4.2500 06/01/95 12/01/95 12/01/96 12/01/97
20,000 5.6875 11/12/95 05/12/96 05/12/97 05/12/98
There were no options granted to the Chief Executive Officer or to the
other four most highly compensated executive officers of the Company during
1995.
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<PAGE> 54
Options exercised in 1995, and the number and value of exercisable and
unexercisable options at December 31, 1995, for the Chief Executive Officer and
the other four most highly compensated executive officers of the Company are as
follows:
Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year End
Option/SAR Values
-----------------------------------------------------------------------
Year Ended December 31, 1995
----------------------------------------------
Number of Shares Acquired
Name on Exercise Value Realized
- ------------------------- ------------------------- --------------
Boone Pickens -- $ --
Paul W. Cain -- --
Dennis E. Fagerstone -- --
Stephen K. Gardner -- --
Andrew J. Littlefair -- --
Value of Unexercised
Number of Shares Underlying In-the-Money
Unexercised Options/SARs at Options/SARs at
December 29, 1995 December 29, 1995
--------------------------- ------------------------
Exercisable Unexercisable Exercisable Unexercisable
- --------------------- ----------- ------------- ----------- ------------
Boone Pickens 1,130,000 145,000 $ 0 $ 0
Paul W. Cain 312,500 87,500 0 0
Dennis E. Fagerstone 104,750 40,250 0 0
Stephen K. Gardner 74,250 60,750 0 0
Andrew J. Littlefair 96,750 43,250 0 0
At December 29, 1995, the final trading day of the year, the Company's
Common Stock per share closed at $3.75. The exercise price of the four grants
of stock options reflected in the aggregate in the above tables are $6.8125,
$7.375, $6.1875, and $4.25, respectively, per share. Thus, no outstanding
options were in-the-money at such date.
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<PAGE> 55
Other
- -----
There were no awards made under any long-term incentive plans from January
1, 1995, through December 31, 1995; therefore, no disclosure is required in the
Long-Term Incentive Plan Awards table. From January 1, 1995, through December
31, 1995, no options or stock appreciation rights were repriced (as defined in
Item 402(i) of Regulation S-K of the Securities Act of 1933). Except as
described below under "Employee Retention Provisions," the Company does not
have any employment contracts or termination or change-in-control arrangements
with respect to a named executive officer of the Company that would require
disclosure pursuant to Item 402(h) of Regulation S-K.
Common Stock Purchase Plan
- --------------------------
The Company has established a Common Stock purchase program whereby
employees, except officers, can buy Common Stock through after-tax payroll
deductions. All other full-time employees of the Company and its participating
affiliates are eligible to participate. The Company pays the brokerage fees for
these open-market transactions.
Employee Retention Provisions
- -----------------------------
On August 22, 1995, the Board of Directors adopted the MESA Inc. Change in
Control Retention/Severance Plan, as amended, (the "Retention Plan"). Pursuant
to the Retention Plan, all regular employees of the Company (other than Mr.
Pickens) will be entitled to receive certain benefits upon the occurrence of
certain involuntary termination events (as described below) following a "Change
in Control" (as defined below) of the Company. The severance benefits consist
of 200% of defined pay for officers (which includes the highest salary and
highest bonus during the then-current and prior three calendar years before the
Retention Plan was adopted), 150% of defined pay for certain key employees
(which includes salary and bonus amounts) and a formula-based amount for all
other employees, plus, in each case, any other accrued or vested or earned but
deferred compensation, rights, options, or benefits otherwise owed to such
employee upon his termination. In addition, on the same date, the Board of
Directors' Stock Option Committee determined that all outstanding but unvested
stock options granted to an employee under the Company's 1991 Stock Option Plan
would immediately vest and become exercisable upon such a termination event
following a Change in Control.
The Company developed the Retention Plan in consultation with an
independent compensation consultant. That consulting firm advised the Board of
Directors that the Retention Plan is conservatively in line with common
practices. The independent firm noted, among other things, that most such plans
it surveyed provide officers with three times their defined pay, rather than
two.
For purposes of the Retention Plan, a "Change in Control" means (i) any
acquisition by an individual, entity or group resulting in such person's
obtaining beneficial ownership of 35% or more of the then outstanding Common
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<PAGE> 56
Stock or the combined voting power of the then outstanding voting securities of
the Company entitled to vote in an election of directors, provided certain
acquisitions, including the following, shall not in and of themselves
constitute a Change in Control hereunder: (a) any acquisition of securities of
the Company made directly from the Company and approved by a majority of the
directors then comprising the members of the Board of Directors as of May 16,
1995 (the "Incumbent Board"); or (b) any acquisition of beneficial ownership of
a higher percentage of the Common Stock outstanding of the Company or the
Voting Securities of the Company that results solely from the acquisition,
purchase or redemption of securities of the Company by the Company so long as
such action by the Company was approved by a majority of the directors then
comprising the Incumbent Board; (ii) a change in the membership of the
Incumbent Board, together with members elected subsequent to May 16, 1995,
whose election or nomination for election was approved by a majority of the
members of the Incumbent Board as then constituted (excluding for this purpose
any individual whose initial assumption of office occurred as a result of an
actual or threatened election contest), cease for any reason to constitute a
majority of the Board of Directors; (iii) a reorganization, merger,
consolidation or sale of all or substantially all of the assets of the Company,
subject to certain exceptions; or (iv) approval by the stockholders of the
Company of the complete liquidation or dissolution of the Company.
Following the occurrence of a Change in Control, an eligible employee
would be entitled to receive full severance benefits if, within 24 months of
the occurrence of a Change in Control: (i) the employee was terminated by the
Company without "Cause" (as defined below); or (ii) the employee's duties,
responsibilities or rate of pay as an employee were materially and adversely
diminished in comparison to the duties, responsibilities and rate of pay
enjoyed by the employee on the effective date of the Retention Plan; or (iii)
the employee was relocated to any location in excess of 35 miles from his
location immediately prior to the Change in Control. All severance benefits
with respect to an eligible employee are payable in a lump sum within ten days
after the termination date of such employee. Under the Retention Plan, "Cause"
means the willful and continued failure of an employee to perform substantially
the employee's duties with the Company following written demand for performance
or the willful engaging by the employee in illegal conduct or gross misconduct
that is materially and demonstrably injurious to the Company.
Director Compensation and Certain Relationships
- -----------------------------------------------
Each director of the Company serving throughout 1995 who was not also
an employee of the Company or its subsidiaries received compensation of
$20,000 allocated quarterly in 1995, except for Messrs. Parkinson, David H.
Batchelder and Reed (who succeeded Mr. Batchelder). Mr. Parkinson received
$15,000, Mr. Batchelder received $10,000, and Mr. Reed received $5,000 for
serving as directors for approximately seven months, four months, and three
months, respectively. Directors who are also employees of the Company
receive no remuneration for their services as directors.
Mr. Sarofim, a director and member of the Compensation and Stock Option
Committees, is Chairman of the Board, President, and owner of a majority of
the outstanding capital stock of Fayez Sarofim & Co., which acts as an
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<PAGE> 57
investment adviser to certain employee benefit plans of the Company. During the
year ended December 31, 1995, Fayez Sarofim & Co. received fees, paid by the
employee benefit plans, of $175,459 for such services and has been retained to
provide such services in 1996.
Mr. Stillwell, a director, is a partner in the law firm of Baker & Botts,
L.L.P. The Company retained Baker & Botts, L.L.P., and incurred legal fees for
such services in 1995. Baker & Botts, L.L.P., has been retained to provide
legal services in 1996.
Compensation Committee Interlocks and Insider Participation
- -----------------------------------------------------------
The Compensation Committee is composed of Messrs. Sarofim and Reed. The
Stock Option Committee, which administers the 1991 Stock Option Plan, is also
composed of Messrs. Sarofim and Reed. Mr. Sarofim is Chairman of the Board,
President, and owner of a majority of the outstanding capital stock of Fayez
Sarofim & Co., which acts as an investment adviser for certain amounts invested
in certain funds in the Retirement Plans. During the year ended December 31,
1995, Fayez Sarofim & Co. received fees, paid by the Retirement Plans, of
$175,459 for such services and has been retained to provide such services in
1996. Mr. Stillwell and former directors Jerry Walsh and David Batchelder
served on the committees during 1995, but ceased to serve on the committees
prior to the time the committees met to deliberate executive officer
compensation.
Indemnification Arrangements
- ----------------------------
The Company's Bylaws provide for the indemnification of its executive
officers and directors, and the advancement to them of expenses in connection
with proceedings and claims, to the fullest extent permitted by the Texas
Business Corporation Act. The Company has also entered into indemnification
agreements with its executive officers and directors that contractually provide
for indemnification and expense advancement and include related provisions
meant to facilitate the indemnitees' receipt of such benefits. In addition, the
Company purchased customary directors' and officers' liability insurance
policies for its directors and officers. The Bylaws and agreements with
directors and officers also provide for indemnification for amounts (i) in
respect of the deductibles for such insurance policies, (ii) that exceed the
liability limits of such insurance policies, and (iii) that would have been
covered by prior insurance policies of the Company or its predecessors. Such
indemnification may be made even though directors and officers would not
otherwise be entitled to indemnification under other provisions of the Bylaws
or such agreements.
Item 12. Security Ownership of Certain Beneficial Owners and Management
========================================================================
Security Ownership of Management
- --------------------------------
The following table presents certain information as to the beneficial
ownership of the Company's Common Stock as of March 6, 1996, by the
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<PAGE> 58
directors, director nominees, and officers of the Company, individually and
as a group:
Number of
Shares of Percentage
Common of Common
Stock(1) Stock
---------- ----------
Directors:
Paul W. Cain.............................. 322,639 *
John S. Herrington........................ 10,000 *
Wales H. Madden, Jr. ..................... 22,200 *
Boone Pickens(2).......................... 5,061,626 7.8%
Fayez S. Sarofim.......................... 1,400,000 2.2%
Robert L. Stillwell....................... 26,500 *
Dorn Parkinson(3)......................... - *
Joel L. Reed.............................. - *
Officers:
Dennis E. Fagerstone...................... 104,750 *
Stephen K. Gardner........................ 90,479 *
Andrew J. Littlefair(4)................... 113,438 *
William D. Ballew......................... 64,853 *
Directors, and Officers as a
group (12 persons)............................. 7,216,485 11.0%
* Less than 1.0%
(1) Includes shares issuable upon the exercise of options that are
exercisable within sixty days of March 6, 1996, as follows:
1,130,000 shares for Mr. Pickens; 312,500 for Mr. Cain; 104,750 for Mr.
Fagerstone; 74,250 for Mr. Gardner; 96,750 for Mr. Littlefair; 62,750
for Mr. Ballew; and 1,781,000 for all directors and officers as a
group.
(2) The above amount includes 7,545 shares of Common Stock owned by several
trusts for Mr. Pickens' children of which he is a trustee, and over
which shares he has sole voting and investment power, although he has
no economic interest therein. The above amounts exclude 2,798 shares
of Common Stock owned by Mrs. Pickens as her separate property, as to
which Mr. Pickens disclaims beneficial ownership and with respect to
which he does not have or share voting or investment power.
(3) Excludes 3,800 shares of Common Stock owned by Mr. Parkinson's son as
his separate property, as to which Mr. Parkinson disclaims beneficial
ownership and with respect to which he does not have or share voting or
investment power. Mr Parkinson is a member of a group consisting of
Dennis R. Washington, Marvin Davis, Davis Acquisition, L.P., Davis
Companies, the Marvin Davis and Barbara Davis Revocable Trust, David H.
Batchelder, and Dorn Parkinson (the "13D Group") which has filed a
Scheduled 13D stating that the 13D Group is the beneficial owner of
6,000,000 shares of Common Stock. See Note 3 to the table under
"Certain Beneficial Owners."
(4) Excludes 1,125 shares of Common Stock owned by Mrs. Littlefair as her
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<PAGE> 59
separate property, as to which Mr. Littlefair disclaims beneficial
ownership and with respect to which he does not have or share voting or
investment power.
Certain Beneficial Owners
- -------------------------
The table below sets forth certain information as of March 6, 1996,
regarding each person or "group" (as that term is used in Section 13(d)(3) of
the Securities Exchange Act of 1934) known by the Company to own beneficially
more than 5% of the Common Stock. Information is based on the most recent
Schedule 13D or 13G filed by such holder with the Securities and Exchange
Commission (the "SEC"), or other information provided by the holder to the
Company.
Amount and Nature of
Beneficial Ownership
-------------------------------
Number of Percentage
Name and Address of Shares of of Common
Beneficial Owner Common Stock Stock
------------------- ------------ ----------
Boone Pickens.......................... 5,061,626(1) 7.8%
1400 Williams Square West
5205 North O'Connor Boulevard
Irving, Texas 75039-3746
FMR Corp. ............................. 5,140,400(2) 8.0%
82 Devonshire Street
Boston, Massachusetts 02109
13D Group.............................. 6,000,000(3) 9.4%
c/o Dennis R. Washington
Washington Corporations
101 International Way
Missoula, Montana 59807
(1) See notes (1) and (2) to the table under "Security Ownership of
Management."
(2) The Schedule 13G filed with the SEC on February 14, 1996, by FMR Corp.
states that as of December 31, 1995, Fidelity Management & Research
Company ("Fidelity"), a wholly owned subsidiary of FMR Corp. and an
investment adviser registered under Section 203 of the Investment
Advisers Act of 1940, is the beneficial owner of 5,140,400 shares or
8.0% of Common Stock as a result of acting as investment adviser to
various investment companies registered under Section 8 of the
Investment Company Act of 1940.
The ownership of one investment company, Fidelity Capital Appreciation
Fund ("Fund"), amounted to 5,140,400 shares or 8.0% of Common Stock
outstanding. Edward C. Johnson, III, chairman of FMR Corp., FMR Corp.,
through its control of Fidelity, and the Fund each has sole power to
dispose of the 5,140,400 shares owned by the Fund.
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<PAGE> 60
(3) A Schedule 13D filed by the 13D Group on June 29, 1995, as amended,
states that such group beneficially owns 6,000,000 shares of Common
Stock. The Schedule 13D states that Dennis R. Washington has sole
voting power over 3,500,000 shares and that Davis Acquisition, L.P.,
Davis Companies, the Marvin Davis and Barbara Davis Revocable Trust,
and Marvin Davis have shared voting power over 2,500,000 of such
shares.
Item 13. Certain Relationships and Related Transactions
========================================================
The information in Item 11 above, "Executive Compensation," is
incorporated by reference herein. Except as described thereunder, no reportable
transaction occurred in 1995.
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PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
==========================================================================
(a)(1) Consolidated Financial Statements and Supplementary Data
- ----------------------------------------------------------------
Page in Form 10-K
-----------------
Report of Independent Public Accountants........... F-2
Consolidated Statements of Operations.............. F-3
Consolidated Balance Sheets........................ F-4
Consolidated Statements of Cash Flows.............. F-5
Consolidated Statements of Changes
in Stockholders' Equity.......................... F-6
Notes to Consolidated Financial Statements......... F-7
Supplemental Financial Data........................ F-8
(a)(2) Consolidated Financial Statement Schedules
- --------------------------------------------------
The consolidated financial statement schedules have been omitted because
they are not required, are not applicable or the information required has been
included elsewhere herein.
(a)(3) Exhibits
- ----------------
(Asterisk indicates exhibits are incorporated by reference herein).
*2.1 - Rainwater, Inc. letter of intent dated February 27, 1996,
between MESA Inc. and Rainwater, Inc.(Exhibit no. 2 to the
Company's Form 8-K filed March 1, 1996).
*3.1 - Amended and Restated Articles of Incorporation of MESA Inc.
dated December 31, 1991 (Exhibit 3[a] to the Company's Form 10-K
dated December 31, 1991).
*3.2 - Amended and Restated Bylaws of MESA Inc. (Exhibit 3[c] to
the Company's Registration Statement on Form S-4,
Registration No. 33-42102).
*4.1 - Indenture dated as of May 1, 1993, among MESA Inc., MESA
Operating Limited Partnership, Mesa Capital Corporation and
Harris Trust and Savings Bank, as Trustee, relating to the
secured discount notes and including (a) a form of Secured
Notes, (b) a form of Deed of Trust, Assignment of
Production, Security Agreement and Financing Statement,
dated as of May 1, 1993, between Mesa Operating Limited
Partnership and Harris Trust and Savings Bank, as trustee,
securing the Secured Notes, and (c) a form of Security
Agreement, Pledge and Financing Statement dated as of May 1,
1993, between Mesa Operating Limited Partnership and Harris
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Trust and Savings Bank, as trustee, securing the Secured
Notes (Exhibit 4[f] to the Company's Form 10-Q/A dated June
30, 1993).
*4.2 - First Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
and Harris Trust and Savings Bank, as Trustee (Exhibit 4.2 to
the Company's Registration Statement on Form S-1, Registration
No. 33-51909).
*4.3 - First Supplement to Security Agreement, Pledge and Financing
Statement dated as of March 2, 1994, by Mesa Operating Co. in
favor of Harris Trust and Savings Bank, as Trustee for the pro
rata benefit of the Noteholders under the Indenture (Exhibit 4.9
to the Company's Form 10-Q dated March 31, 1994).
*4.4 - Indenture dated as of May 1, 1993, among MESA Inc., MESA
Operating Limited Partnership, Mesa Capital Corporation and
American Stock Transfer & Trust Company, as Trustee, relating to
the unsecured discount notes (Exhibit 4[g] to the Company's Form
10-Q/A dated June 30, 1993).
*4.5 - First Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
and American Stock Transfer & Trust Company, as Trustee (Exhibit
4.4 to the Company's Registration Statement on Form S-1,
Registration No. 33-51909).
*4.6 - Indenture dated May 1, 1989, among Mesa Capital Corporation,
Mesa Limited Partnership, Mesa Operating Limited Partnership,
and Texas Commerce Bank National Association, as Trustee
(Exhibit 4[c] to the Partnership's Form 10-Q dated March 31,
1989).
*4.7 - First Supplemental Indenture dated as of December 31, 1991,
among Mesa Capital Corporation, MESA Inc., Mesa Operating
Limited Partnership, as Issuers, and Texas Commerce Bank
National Association, as Trustee (Exhibit 4[e] to the Company's
Form 10-K dated December 31, 1991).
*4.8 - Second Supplemental Indenture dated as of April 30, 1992,
among Mesa Capital Corporation, MESA Inc., Mesa Operating
Limited Partnership and Texas Commerce Bank National
Association, as Trustee (Exhibit 4[k] to the Company's Form 10-Q
dated June 30, 1992).
*4.9 - Third Supplemental Indenture dated as of August 26, 1993,
among Mesa Capital Corporation, MESA Inc., Mesa Operating
Limited Partnership and Texas Commerce Bank National
Association, as Trustee (Exhibit 4[l] to the Company's Form
10-Q/A dated June 30, 1993).
*4.10 - Fourth Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
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and Texas Commerce Bank National Association, as Trustee
(Exhibit 4.16 to the Company's Registration Statement on Form
S-1, Registration No. 33-51909).
*4.11 - Indenture dated as of May 30, 1991, among Hugoton Capital
Limited Partnership, Hugoton Capital Corporation and Bankers
Trust Company (Exhibit 4[e] to the Partnership's Form 10-Q dated
June 30, 1991).
*4.12 - First Supplemental Indenture dated September 1, 1991, among
Hugoton Capital Limited Partnership, Hugoton Capital Corporation
and Bankers Trust Company, as Trustee (Exhibit 4[h] to the
Company's Registration Statement on Form S-4, Registration No.
33-42102).
*4.13 - Amended and Restated Mortgage, Assignment, Security Agreement
and Financing Statement dated June 12, 1991, from Hugoton
Capital Limited Partnership to Bankers Trust Company, as
Collateral Agent (Exhibit 4[f] to the Partnership's Form 10-Q
dated June 30, 1991).
*4.14 - Third Amended and Restated Credit Agreement dated as of
November 29, 1994, among the Company, Mesa Operating Co., and
the Banks named in this Credit Agreement and Societe Generale,
Southwest Agency, as Agent (Exhibit 4.7 to the Company's Form
10-K dated December 31, 1994).
*4.15 - Intercreditor Agreement dated as of August 26, 1993, among
Societe Generale, Southwest Agency, as agent for the Banks
under the Company's Credit Agreement, Harris Trust and
Savings Bank, as trustee with respect to the Secured Notes,
and American Stock Transfer & Trust Company, as trustee with
respect to the Unsecured Notes (Exhibit 4.18 to the Company's
Registration Statement on Form S-4, Registration No.
33-53706).
The Registrant agrees to furnish to the Commission upon request
any instruments defining the right of holders of long-term debt
with respect to which the total amount outstanding does not
exceed 10% of the total assets of the Registrant and its
subsidiaries on a consolidated basis.
*4.16 - Rights Agreement dated as of July 6, 1995, as amended,
between MESA Inc. and American Stock Transfer and Trust
Company (Exhibit 1 to the Company's Registration Statement on
Form 8-A dated July 6, 1995).
*10.1 - Form of First Amendment to Deferred Compensation Agreement and
Life Insurance Agreement between MESA Petroleum Co. and certain
officers and key employees (Exhibit 10[i] to the Company's Form
10-K dated December 31, 1980).
*10.2 - Contract dated January 3, 1928, between Colorado Interstate
Gas Company and Amarillo Oil Company (the "B" Contract) (Exhibit
10.1 to Pioneer Corporation's Form 10-K dated
63
<PAGE> 64
December 31, 1985).
*10.3 - Amendments to the "B" Contract (Exhibit 10.2 to Pioneer
Corporation's Form 10-K dated December 31, 1985).
*10.4 - Gathering Charge Agreement dated January 20, 1984, as amended,
with respect to the "B" Contract (Exhibit 10.3 to Pioneer
Corporation's Form 10-K dated December 31, 1985).
*10.5 - Agreement of Compromise and Settlement dated May 29, 1987,
between the Partnership and Colorado Interstate Gas Company
(Confidential Treatment Requested) (Exhibit 10[s] to the
Partnership's Form 10-K dated December 31, 1987).
*10.6 - Agreement of Sale between Pioneer Corporation and Cabot
Corporation dated August 29, 1984 (Exhibit 10.5 to Pioneer
Corporation's Form 10-K dated December 31, 1985).
*10.7 - Settlement Agreement dated March 15, 1989, by and among MESA
Operating Limited Partnership and Mesa Limited Partnership, et
al, Energas Company and the City of Amarillo (Exhibit 10[k] to
the Partnership's Form 10-K dated December 31, 1990).
*10.8 - Gas Purchase Agreement dated December 1, 1989, between
Williams Natural Gas Company and Mesa Operating Limited
Partnership acting on behalf of itself and as agent for MESA
Midcontinent Limited Partnership (Exhibit 10.1 to Registration
Statement of the Partnership on Form S-3,
Registration No. 33-32978).
*10.9 - "B" Contract Production Allocation Agreement dated July 29,
1991, and effective as of January 1, 1991, between Colorado
Interstate Gas Company and Mesa Operating Limited Partnership
(Exhibit 10[r] to the Company's Form 10-K dated
December 31, 1991).
*10.10 - Amendment to "B" Contract Production Allocation Agreement
effective as of January 1, 1993, between Colorado Interstate Gas
Company and Mesa Operating Limited Partnership (Exhibit 10.24 to
the Company's Registration Statement on Form S-1, Registration
No. 033-51909).
*10.11 - Amended Supplemental Stipulation and Agreement between
Colorado Interstate Gas Company and Mesa Operating Limited
Partnership dated June 19, 1991 (Exhibit 10[w] to the Company's
Registration Statement on Form S-4, Registration No. 33-42102).
*10.12 - Amended Peak Day Gas Purchase Agreement dated effective June
19, 1991, between Colorado Interstate Gas Company and MESA
Operating Limited Partnership (Exhibit 10[t] to the Company's
Form 10-K dated December 31, 1991).
64
<PAGE> 65
*10.13 - Omnibus Amendment to Collateral Instruments to Supplemental
Stipulation and Agreement dated June 19, 1991, between Colorado
Interstate Gas Company and Mesa Operating Limited Partnership
(Exhibit 10[u] to the Company's Form 10-K dated December 31,
1991).
10.14 - Amarillo Supply Agreement between Mesa Operating Limited
Partnership, Seller, and Energas Company, a division of Atmos
Energy Corporation, Buyer, dated effective January 2, 1993.
10.15 - Gas Gathering Agreement-Interruptible between Colorado
Interstate Gas Company, Transporter, and Mesa Operating
Limited Partnership, Shipper, dated effective October 1,
1993, as amended by agreements dated January 1, 1994, January
5, 1994, and June 1, 1994.
10.16 - Gas Supply Agreement dated May 11, 1994, between Mesa
Operating Co., as successor to Mesa Operating Limited
Partnership, acting on behalf of itself and as agent for
Hugoton Capital Limited Partnership, and Williams Gas
Marketing Company, and Gas Supply Guarantee dated May 11,
1994.
*10.17 - Gas Transportation Agreement dated June 14, 1994, between
Western Resources, Inc. and Mesa Operating Co., acting on behalf
of itself and as agent for Hugoton Capital Limited Partnership
(Exhibit 10.24 to the Company's Form 10-K dated December 31,
1994).
*10.18 - Incentive Bonus Plan of Mesa Operating Limited Partnership, as
amended, dated effective January 1, 1986 (Exhibit 10[s] to the
Partnership's Form 10-K dated December 31, 1990).
*10.19 - Performance Bonus Plan of Mesa Operating Limited Partnership
dated effective January 1, 1990 (Exhibit 10[t] to the
Partnership's Form 10-K dated December 31, 1990).
*10.20 - 1991 Stock Option Plan of MESA (Exhibit 10[v] to the Company's
Form 10-K dated December 31, 1991).
*10.21 - Split-Dollar Insurance Agreements dated June 29, 1992, by and
between Mesa Operating Limited Partnership and Boone Pickens and
Paul Cain, respectively, and Collateral Assignments dated as of
June 29, 1992, by Boone Pickens and Paul Cain, respectively
(Exhibit 10[aa] to the Company's Form 10-K dated December 31,
1992).
10.22 - Interruptible Gas Transportation and Sales Agreement dated
January 1, 1991, between Mesa Operating Limited Partnership and
Energas Company and Amendment dated January 1, 1995.
10.23 - "B" Contract Operating Agreement dated January 1, 1988,
between Mesa Operating Limited Partnership and Colorado
Interstate Gas Company.
65
<PAGE> 66
10.24 - "B" Contract Agreement of Compromise and Settlement dated May
29, 1987, between Mesa Operating Limited Partnership and
Colorado Interstate Gas Company, and Amendment to Gathering
Agreement dated July 15, 1990.
10.25 - Gas Purchase Agreement dated January 1, 1996, between Mesa
Operating Co., as Seller, and KN Marketing L.P., as Buyer, and
Amendment dated August 1, 1995.
10.26 - Change in Control Retention/Severance Plan adopted August 22,
1995, and Amendment dated October 20, 1995.
22 - List of Subsidiaries of the Company.
27 - Article 5 of Regulation S-X Financial Data Schedule
for Year-End 1995 Form 10-K.
28 - Summary Report of the Company relating to proved oil and gas
reserves at December 31, 1995.
(b) Reports on Form 8-K
- ------------------------
Current Report on Form 8-K dated February 28, 1996, and filed March 1,
1996, regarding a letter of intent between the Company and Rainwater, Inc.,
relating to an equity investment to be made in connection with the refinancing
of all the Company's debt.
66
<PAGE> 67
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.
MESA INC.
By: /s/ Boone Pickens
------------------------------------
Date: May 24, 1996 (Boone Pickens,
------------- Chief Executive Officer)
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Boone Pickens
- ------------------------- Chief Executive Officer and May 24, 1996
(Boone Pickens) Chairman of the Board of
Directors
(Principal Executive Officer)
/s/ Paul W. Cain
- ------------------------- President, Chief Operating May 24, 1996
(Paul W. Cain) Officer and Director
/s/ Stephen K. Gardner
- ------------------------- Vice President and Chief May 24, 1996
(Stephen K. Gardner) Financial Officer
(Principal Financial Officer)
/s/ William D. Ballew
- ------------------------- Controller May 24, 1996
(William D. Ballew) (Principal Accounting Officer)
/s/ John S. Herrington
- ------------------------- Director May 24, 1996
(John S. Herrington)
/s/ Wales H. Madden, Jr.
- ------------------------- Director May 24, 1996
(Wales H. Madden, Jr.)
- ------------------------- Director
(Dorn Parkinson)
- ------------------------- Director
(Joel L. Reed)
/s/ Fayez S. Sarofim
- ------------------------- Director May 24, 1996
(Fayez S. Sarofim)
/s/ Robert L. Stillwell
- ------------------------- Director May 24, 1996
(Robert L. Stillwell)
67
<PAGE> 68
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
--------------------------------------------------------
Page in Form 10-K
-----------------
Report of Independent Public Accountants................ F-2
Consolidated Statements of Operations................... F-3
Consolidated Balance Sheets............................. F-4
Consolidated Statements of Cash Flows................... F-5
Consolidated Statements of Changes
in Stockholders' Equity............................... F-6
Notes to Consolidated Financial Statements.............. F-7
Supplemental Financial Data............................. F-8
F-1
<PAGE> 69
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To MESA Inc.:
We have audited the accompanying consolidated balance sheets of MESA Inc. (a
Texas corporation) and subsidiaries as of December 31, 1995 and 1994, and the
related consolidated statements of operations, cash flows and changes in
stockholders' equity for each of the three years in the period ended December
31, 1995. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of MESA Inc. and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed further in Note 2 to the
consolidated financial statements, the Company's current financial forecasts
indicate that cash generated by operating activities, together with available
cash and investment balances, will not be sufficient for the Company to make
all of its required debt principal and interest obligations due in June 1996.
Also, as discussed in Notes 2 and 4 to the consolidated financial statements,
certain covenants related to the Company's bank debt and certain cross-default
provisions of the Discount Notes could result in the acceleration of
approximately $656 million of long-term debt principal (due in mid-1997 and
mid-1998) to the first half of 1996. As a result, there is substantial doubt
about the Company's ability to continue as a going concern. Management's plans
in regard to these matters are also described in Note 2 to the consolidated
financial statements. The consolidated financial statements do not include any
adjustments relating to the recoverability and classification of asset carrying
amounts or the amount and classification of liabilities that might result
should the Company be unable to continue as a going concern.
/s/ Arthur Andersen LLP
-----------------------
ARTHUR ANDERSEN LLP
Houston, Texas
March 6, 1996
F-2
<PAGE> 70
MESA Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
-------------------------------------
(in thousands, except per share data)
Years Ended December 31
-------------------------------
1995 1994 1993
Revenues: --------- --------- ---------
Natural gas........................... $ 129,534 $ 139,580 $ 141,798
Natural gas liquids................... 75,321 72,771 61,427
Oil and condensate.................... 19,594 7,877 12,428
Other................................. 10,510 8,509 6,551
--------- --------- ---------
234,959 228,737 222,204
--------- --------- ---------
Costs and Expenses:
Lease operating....................... 51,815 52,655 51,819
Production and other taxes............ 18,403 21,306 20,332
Exploration charges................... 6,604 5,157 2,705
General and administrative............ 26,749 28,649 25,237
Depreciation, depletion and
amortization........................ 83,423 92,287 100,099
--------- --------- ---------
186,994 200,054 200,192
--------- --------- ---------
Operating Income........................... 47,965 28,683 22,012
--------- --------- ---------
Other Income (Expense):
Interest income....................... 15,922 13,457 10,704
Interest expense...................... (148,630) (144,757) (142,002)
Gains from investments................ 18,420 6,698 3,954
Gains from collections from
Bicoastal Corporation............... 6,352 16,577 18,450
Gains on dispositions of oil
and gas properties.................. -- -- 9,600
Litigation settlement................. -- -- (42,750)
Gain from adjustment of contingency
reserve............................. -- -- 24,000
Other................................. 2,403 (4,011) (6,416)
--------- --------- ---------
(105,533) (112,036) (124,460)
--------- --------- ---------
Net Loss................................... $ (57,568) $ (83,353) $(102,448)
========= ========= =========
Net Loss Per Common Share.................. $ (.90) $ (1.42) $ (2.61)
========= ========= =========
Weighted Average Common Shares Outstanding. 64,050 58,860 39,272
========= ========= =========
(See accompanying notes to consolidated financial statements.)
F-3
<PAGE> 71
MESA Inc.
CONSOLIDATED BALANCE SHEETS
---------------------------
(in thousands, except share data)
December 31
----------------------
ASSETS 1995 1994
---------- ----------
Current Assets:
Cash and cash investments..................... $ 149,143 $ 143,422
Investments................................... 38,280 19,112
Accounts and notes receivable................. 44,734 38,938
Other......................................... 4,590 3,372
---------- ----------
Total current assets..................... 236,747 204,844
---------- ----------
Property, Plant and Equipment:
Oil and gas properties, wells
and equipment, using the successful
efforts method of accounting................ 1,900,163 1,867,842
Office and other.............................. 41,603 43,836
Accumulated depreciation, depletion
and amortization............................ (859,077) (781,230)
---------- ----------
1,082,689 1,130,448
---------- ----------
Other Assets:
Restricted cash of subsidiary partnership..... 57,731 61,299
Gas balancing receivable...................... 56,020 54,971
Other......................................... 31,509 32,397
---------- ----------
145,260 148,667
---------- ----------
$1,464,696 $1,483,959
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities on long-term debt.......... $ 101,413 $ 30,537
Accounts payable and accrued liabilities...... 31,068 40,468
Interest payable.............................. 60,465 18,184
---------- ----------
Total current liabilities................ 192,946 89,189
---------- ----------
Long-Term Debt..................................... 1,135,330 1,192,756
---------- ----------
Deferred Revenue................................... 17,578 21,900
---------- ----------
Other Liabilities.................................. 51,838 55,542
---------- ----------
Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, authorized
10,000,000 shares; no shares issued and
outstanding................................. -- --
Common stock, $.01 par value, authorized
100,000,000 shares; outstanding 64,050,009
and 64,050,009 shares, respectively......... 640 640
Additional paid-in capital.................... 398,965 398,965
Accumulated deficit........................... (332,601) (275,033)
---------- ----------
67,004 124,572
---------- ----------
$1,464,696 $1,483,959
========== ==========
(See accompanying notes to consolidated financial statements.)
F-4
<PAGE> 72
MESA Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(in thousands)
Years Ended December 31
-----------------------------
1995 1994 1993
-------- --------- --------
Cash Flows From Operating Activities:
Net loss................................ $(57,568) $ (83,353)$(102,448)
Adjustments to reconcile net loss
to net cash provided by
operating activities:
Depreciation, depletion and
amortization..................... 83,423 92,287 100,099
Gains on dispositions of
oil and gas properties........... -- -- (9,600)
Accreted interest on discount notes 38,957 79,352 49,160
Accrued interest exchanged for
discount notes................... -- -- 15,395
Litigation settlement.............. -- (42,750) 42,750
Gain from adjustment of
contingency reserves............. -- -- (24,000)
Decrease (increase) in gas
balancing receivables............ 1,516 (7,840) (4,942)
Decrease in deferred natural gas
revenue.......................... (4,219) (785) (3,370)
Settlement of prior year tax claims -- -- (12,931)
Natural gas hedging activities..... (9,715) 9,715 324
Sales of investments............... 48,555 18,771 39,283
Purchases of investments........... (49,003) (19,866) (34,711)
Gains from investments............. (18,420) (6,698) (3,954)
(Increase) decrease in
accounts receivable.............. (12,047) 5,934 1,986
Increase (decrease) in payables
and accrued liabilities.......... 45,243 (3,142) (15,887)
Other.............................. 2,519 6,972 (4,662)
-------- -------- --------
Net cash provided by
operating activities............. 69,241 48,597 32,492
-------- -------- --------
Cash Flows From Investing Activities:
Capital expenditures.................... (42,297) (32,590) (29,636)
Proceeds from dispositions of
oil and gas properties................ -- -- 26,118
Collection of notes receivable.......... -- -- 47,501
Other................................... 860 (7,660) (6,461)
-------- -------- --------
Net cash provided by (used in)
investing activities............. (41,437) (40,250) 37,522
-------- -------- --------
Cash Flows From Financing Activities:
Issuance of common stock................ -- 93,067 --
Repayments of long-term debt............ (25,507) (175,107) (80,102)
Long-term borrowings.................... -- 77,754 --
Debt issuance costs..................... -- -- (9,651)
Other................................... 3,424 652 1,251
-------- -------- --------
Net cash used in
financing activities............. (22,083) (3,634) (88,502)
-------- -------- --------
Net Increase (Decrease) in Cash and
Cash Investments........................... 5,721 4,713 (18,488)
Cash and Cash Investments
at Beginning of Year....................... 143,422 138,709 157,197
-------- -------- --------
Cash and Cash Investments at End of Year..... $149,143 $143,422 $138,709
======== ======== ========
(See accompanying notes to consolidated financial statements.)
F-5
<PAGE> 73
MESA Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
----------------------------------------------------------
(in thousands)
Common Stock Additional
-------------- Paid-in Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance, December 31, 1992.......... 38,571 $386 $273,198 $ (89,232)
Net loss....................... -- -- -- (102,448)
Common stock issued for
0% convertible notes......... 7,523 75 29,239 --
Common stock issued for the
partial conversion of
the General Partner
minority interest............ 417 4 907 --
------ ---- -------- ---------
Balance, December 31, 1993.......... 46,511 465 303,344 (191,680)
Net loss....................... -- -- -- (83,353)
Common stock issued for the
conversion of the remaining
General Partner minority
interest..................... 1,251 13 2,716 --
Common stock issued in
secondary public offering.... 16,288 162 92,905 --
------ ---- -------- ---------
Balance, December 31, 1994.......... 64,050 640 398,965 (275,033)
Net loss....................... -- -- -- (57,568)
------ ---- -------- ---------
Balance, December 31, 1995.......... 64,050 $640 $398,965 $(332,601)
====== ==== ======== =========
(See accompanying notes to consolidated financial statements.)
F-6
<PAGE> 74
MESA Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
(1) Organization and Summary of Significant Accounting Policies
===========================================================
MESA Inc., a Texas corporation, was formed in 1991 in connection with a
transaction (the "Corporate Conversion") which reorganized the business of Mesa
Limited Partnership (the "Partnership"). The Partnership was formed in 1985 to
succeed to the business of Mesa Petroleum Co. ("Original Mesa"). Unless the
context otherwise requires, as used herein the term "Company" refers to MESA
Inc. and its subsidiaries taken as a whole and includes its predecessors.
The Company is primarily in the business of exploring for, developing,
producing, processing and selling natural gas and oil in the United States.
Over 60% of the Company's annual equivalent production is natural gas and the
balance is principally natural gas liquids. The Company's primary producing
areas are the Hugoton field of southwest Kansas, the West Panhandle field of
Texas and the Gulf of Mexico offshore Texas and Louisiana. Production from the
Company's properties has access to a substantial portion of the major
metropolitan markets in the United States, primarily in the midwest and
northeast, through numerous pipelines and other purchasers.
The preparation of the consolidated financial statements of the Company 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 consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from the
estimates.
Principles of Consolidation
- ---------------------------
The Company owns and operates its oil and gas properties and other assets
through various direct and indirect subsidiaries. Pursuant to the Corporate
Conversion, the Company obtained a 95.86% limited partnership interest and
Boone Pickens (the "General Partner") obtained a 4.14% general partner interest
in three direct subsidiary partnerships. The general partner interest was
convertible into a total of 1,667,560 shares of common stock of the Company. On
December 31, 1993, the General Partner converted approximately one-fourth of
his general partner interests into common stock. In early 1994 the Company
effected a series of merger transactions which resulted in the conversion of
each of its direct subsidiary partnerships to corporate form (see Note 13).
Pursuant to these mergers, the remaining general partner interests in the
Company's subsidiary partnerships held directly or indirectly by the General
Partner were converted into common stock, thereby eliminating the minority
interest.
F-7
<PAGE> 75
The accompanying consolidated financial statements reflect the
consolidated accounts of the Company and its subsidiaries after elimination of
intercompany transactions.
Certain reclassifications have been made to amounts reported in previous
years to conform to 1995 presentation.
Statements of Cash Flows
- ------------------------
For purposes of the statements of cash flows, the Company classifies all
cash investments with original maturities of three months or less as cash and
cash investments.
Investments
- -----------
On January 1, 1994, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 115, "Accounting for Certain Investments in Debt and
Equity Securities," which addresses the accounting and reporting for
investments in equity securities that have readily determinable fair values and
for all investments in debt securities. The Company's portfolio of securities
is classified as "trading securities" under the provisions of SFAS No. 115 and
is reported at fair value, with unrealized gains and losses included in net
income (loss) for the current period. The cost of securities sold is determined
on the first-in, first-out basis. Prior to January 1, 1994, investments in
marketable securities were stated at the lower of cost or market. The adoption
of SFAS No. 115 did not have a material effect on the financial position or
results of operations of the Company.
The Company enters into various energy futures contracts including New
York Mercantile Exchange ("NYMEX") futures contracts, commodity price swaps and
options which are not intended to be hedges of future natural gas or crude oil
production. Investments in such contracts are adjusted to market prices at the
end of each reporting period and gains and losses are included in gains from
investments in the statements of operations.
Oil and Gas Properties
- ----------------------
Under the successful efforts method of accounting, all costs of acquiring
unproved oil and gas properties and drilling and equipping exploratory wells
are capitalized pending determination of whether the properties have proved
reserves. If an exploratory well is determined to be nonproductive, the
drilling and equipment costs of the well are expensed at that time. All
development drilling and equipment costs are capitalized. Capitalized costs of
proved properties and estimated future dismantlement and abandonment costs are
amortized on a property-by-property basis using the unit-of-production method
whereby the ratio of annual production to beginning of period proved oil and
gas reserves is applied to the remaining net book value of such properties. Oil
and gas reserve quantities represent estimates only and there are numerous
uncertainties inherent in the estimation process. Actual future production may
be materially different from amounts estimated and such differences could
materially affect future
F-8
<PAGE> 76
amortization of proved properties. Geological and geophysical costs and
delay rentals are expensed as incurred.
Unproved properties are periodically assessed for impairment of value and
a loss is recognized at the time of impairment. The aggregate carrying value of
proved properties is periodically compared with the undiscounted future net
cash flows from proved reserves, determined in accordance with Securities and
Exchange Commission (the "Commission") regulations, and a loss is recognized if
permanent impairment of value is determined to exist. A loss is recognized on
proved properties expected to be sold in the event that carrying value exceeds
expected sales proceeds.
In March 1995 the Financial Accounting Standards Board (the "FASB") issued
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," which establishes accounting standards
for the impairment of long-lived assets, certain identifiable intangibles and
goodwill. SFAS No. 121 requires a review for impairment whenever circumstances
indicate that the carrying amount of an asset may not be recoverable. In
performing the review for recoverability, the Company would estimate future
cash flows (undiscounted and without interest charges) expected to result from
use of an asset and its eventual disposition. Impairment is recognized only if
the carrying amount of an asset is greater than the expected future cash flows.
The amount of impairment is based on the fair value of the asset. Under SFAS
No. 121, each field is individually evaluated for impairment. The Company will
adopt the provisions of SFAS No. 121 in 1996 and has estimated that impairment
of approximately $10 to $12 million will be charged to operations in the first
quarter of 1996. Such impairment relates primarily to a Gulf Coast oil and gas
property.
Net Loss Per Common Share
- -------------------------
The computations of net loss per common share are based on the weighted
average number of common shares outstanding during each period.
Fair Value of Financial Instruments
- -----------------------------------
The Company's financial instruments consist of cash, marketable
securities, commodity price swaps, options, short-term trade receivables and
payables, restricted cash, notes receivable, and long-term debt. The carrying
values of cash, marketable securities, notes receivable, short-term trade
receivables and payables, and restricted cash approximate fair value. The
carrying values of the commodity price swaps and options represent their
required cash deposits plus or minus unrealized gains and losses (see Note 3).
The fair value of long-term debt is estimated based on the market prices for
the Company's publicly traded debt and on current rates available for similar
debt with similar maturities and security for the Company's remaining debt (see
Note 4).
F-9
<PAGE> 77
Gas Revenues
- ------------
The Company recognizes its ownership interest in natural gas production as
revenue. Actual production quantities sold by the Company may be different than
its ownership share of production in a given period. If the Company's sales
exceed its ownership share of production, the differences are recorded as
deferred revenue. Gas balancing receivables are recorded when the Company's
ownership share of production exceeds sales. The Company also accrues
production expenses related to its ownership share of production. At December
31, 1995, the Company had produced and sold a cumulative net 21.9 billion cubic
feet ("Bcf") of natural gas less than its ownership share of production and had
recorded gas balancing receivables, net of deferred revenues, of approximately
$38.8 million. Substantially all of the Company's gas balancing receivables and
deferred revenue are classified as long-term.
The Company periodically enters into NYMEX natural gas futures contracts
as a hedge against natural gas price fluctuations. Gains or losses on such
futures contracts are deferred and recognized as natural gas revenue when the
hedged production occurs. The Company recognized net gains of $12.7 million and
$895,000 in 1995 and 1994, respectively, and a net loss of $324,000 in 1993
related to hedging activities.
Taxes
- -----
The Company provides for income taxes using the asset and liability method
under which deferred income taxes are recognized for the tax consequences of
"temporary differences" by applying enacted statutory tax rates applicable to
future years to differences between the financial statement carrying amounts
and the tax bases of existing assets and liabilities. The effect on deferred
taxes of a change in tax laws or tax rates is recognized in income in the
period that includes the enactment date.
(2) Resources and Liquidity
=======================
Long-term Debt and Cash Flows
- -----------------------------
The Company is highly leveraged with over $1.2 billion of long-term debt,
including current maturities. The major components of the Company's debt are
(1) $504.7 million of secured notes due in installments through 2012 at Hugoton
Capital Limited Partnership ("HCLP"), an indirect, wholly owned subsidiary, (2)
$61.1 million (plus $11.4 million in letter of credit obligations) outstanding
under a bank credit facility, due in installments through 1997, with the
majority of such debt due on June 23, 1997, (3) $39.7 million of unsecured
discount notes due on June 30, 1996, and (4) $617.4 million of secured discount
notes due on June 30, 1998. Both the secured and unsecured discount notes are
subordinate to the bank credit facility. See Note 4 for a complete description
of the Company's long-term debt.
F-10
<PAGE> 78
The Company is required to make significant principal and interest
payments on its debt during the first six months of 1996. Including the $42
million of interest paid on its discount notes on January 2, 1996, the Company
is required to make $123.5 million of principal and interest payments related
to its discount notes and $22.5 million of principal payments related to its
bank credit facility by June 30, 1996.
The Company's bank credit facility contains a covenant requiring the
Company to maintain tangible adjusted equity, as defined, of at least $50
million. At December 31, 1995, tangible adjusted equity was $64.7 million.
Assuming no changes in its capital structure and no significant transactions
are completed, the Company expects to continue to report substantial net losses
and expects its tangible adjusted equity to fall below $50 million in the first
half of 1996. If and when the Company determines that tangible adjusted equity
is below $50 million, an Event of Default, as defined, would occur under the
bank credit facility and the bank would have the right to accelerate the
payment of all outstanding principal and require cash collateralization of
letters of credit. An Event of Default under the bank credit facility would
cause a cross default under the Company's secured and unsecured discount note
indentures unless and until the bank credit facility default were cured or
waived or the debt under the bank credit facility were repaid or otherwise
discharged. The Events of Default, if they occur and are not waived, could
result in acceleration of approximately $656 million of long-term debt
principal due in mid-1997 and mid-1998 to the first half of 1996. Pursuant to
the subordination provisions of the discount note indentures, the Company would
be prohibited from making any payments on such notes for specified periods upon
and during the continuance of any Event of Default under the bank credit
facility.
The assets and cash flows of HCLP that are subject to the mortgage
securing HCLP's debt are dedicated to service HCLP's debt and are not available
to pay creditors of the Company or its subsidiaries other than HCLP.
The Company's current financial forecasts indicate, assuming no changes in
its capital structure and no significant transactions are completed, that cash
generated by operating activities, together with available cash and investment
balances will not be sufficient to make all of its required debt principal and
interest obligations due in June 1996. If amounts outstanding under the Credit
Agreement were to be accelerated in the first half of 1996, the Company would
expect to have sufficient cash to meet the Credit Agreement obligations and
cure an Event of Default under the Credit Agreement and avoid, at that time,
cross defaults under the terms of its Discount Note indentures. However, such a
payment would substantially deplete the Company's remaining cash and
investments balances. The Company will make decisions regarding such payments
on its debt as they come due, taking into account the status at that time of
the Rainwater transaction discussed below.
F-11
<PAGE> 79
Exploration of Strategic Alternatives/
Proposed Transaction With Rainwater
--------------------------------------
In an effort to address its liquidity issues and to position the Company
for expansion through exploration and development, in December 1994 the Company
announced its intent to sell all or a portion of its interests in the Hugoton
field. In the first quarter of 1995 the Company began an auction process to
sell such properties. The Company's Board of Directors (the "Board") concluded
the auction process in the second quarter of 1995 after no acceptable bids were
received for the Hugoton properties.
On July 6, 1995, the Board approved and implemented a proposal
solicitation process which expanded its exploration of strategic alternatives
to include consideration of the sale of the Company, a stock-for-stock merger,
joint ventures, asset sales, equity infusions, and refinancing transactions.
The Company engaged an independent financial advisor to assist in these efforts
and to solicit proposals on its behalf. The proposal solicitation process
commenced in August 1995 and the Company received proposals beginning on
November 20, 1995.
On February 28, 1996, the Company signed a letter of intent with
Rainwater, Inc. ("Rainwater"), an independent investment company owned by Ft.
Worth, Texas, investor Richard Rainwater, to raise $265 million of equity in
connection with a refinancing of the Company's debt. Pursuant to the terms of
the letter of intent, Rainwater will purchase in a private placement
approximately 58.8 million shares of a new class of convertible preferred stock
and the Company will offer approximately 58.4 million shares of convertible
preferred stock to the Company stockholders in a rights offering (the "Rights
Offering"). Rainwater will provide a standby commitment to purchase any shares
of preferred stock not subscribed to in the Rights Offering. Rights will be
distributed to common stockholders on a pro rata basis. The rights will allow
the stockholder to purchase, in respect of each share of common stock,
approximately .91 shares of preferred stock at $2.26 per share, the same per
share price at which Rainwater will purchase preferred shares. The rights will
be transferrable and holders of the rights will be offered over-subscription
privileges for shares not purchased by other rights holders.
Each preferred share will be convertible into one share of the Company
common stock at any time prior to mandatory redemption in 2006. An annual 8%
pay-in-kind dividend will be paid on the preferred shares during the first four
years following issuance. Thereafter, the 8% dividend may, at the option of the
Company, be paid in cash or additional shares depending on whether certain
financial tests are met.
The preferred stock will represent 63.6% of the fully diluted common
shares at the time of issuance and 70.6% after the mandatory four-year
pay-in-kind period, assuming no other stock issuance by the Company. The
preferred stock will have a liquidation price equal to the purchase price.
The preferred shares purchased in the Rights Offering will vote with the common
stock as a single class on all matters, except as otherwise required by law and
except for certain special voting rights for shares held by Rainwater.
F-12
<PAGE> 80
Rainwater will be entitled to elect two members of the Company's Board,
which will have seven directors. The Rainwater designees will constitute two of
the three members of a newly formed executive committee of the Board. The
executive committee will act for the whole Board on matters which by law do not
need Board authorization and will have authority over major capital
transactions, stock issuances, financing arrangements, budgeting, and other
items.
During an interim 30-day period beginning February 28, 1996, the Company,
with assistance from Rainwater, will seek commitments for new bank loans plus
assurance of availability of new subordinated debt to be issued in conjunction
with the transaction. Proceeds from the new debt, when combined with proceeds
from the newly issued equity and the Company's available cash balances, would
refinance or repay all of the Company's existing debt.
The proposed transaction is subject to certain conditions, including
negotiation and execution of definitive agreements, arrangement of the new debt
financing, due diligence by Rainwater and the Company stockholder approval. The
parties anticipate executing definitive agreements in about 30 days. The
transaction will be submitted to a vote of stockholders at a special meeting
expected to take place in June 1996. The Rights Offering would commence
promptly after that meeting. There can be no assurance that this transaction
will be completed, or if completed, what the final terms or timing thereof will
be. Nor can there be any assurance regarding the availability or terms of any
refinancing debt.
The ability of the Company to continue as a going concern is dependent
upon several factors. The successful completion of the Rainwater transaction is
expected to position the Company to operate and continue as a going concern and
to pursue its business strategies. The consolidated financial statements of the
Company do not include any adjustments reflecting any treatment other than
going concern accounting.
If the Rainwater transaction is not completed, the Company will pursue
other alternatives to address its liquidity issues and financial condition,
including other potential transactions arising from the proposal solicitation
process, the possibility of seeking to restructure its balance sheet by
negotiating with its current debt holders or seeking protection from its
creditors under the Federal Bankruptcy Code.
F-13
<PAGE> 81
(3) Investments
===========
The value of investments are as follows (in thousands):
December 31
--------------------
1995 1994
------- -------
Equity securities:
Cost...................................... $10,719 $9,489
Unrealized loss........................... (162) (1,381)
NYMEX Futures Contracts:
Margin Cash............................... 17,498 1,337
Unrealized gain in hedge contracts........ -- 6,823
Unrealized gain in trading contracts...... 7,558 2,844
Commodity Price Swaps:
Margin Cash............................... 2,434 --
Unrealized loss in price swaps............ (811) --
Natural Gas Options:
Premiums.................................. 66 --
Unrealized gain in trading options........ 978 --
------- -------
Total market value........................ $38,280 $19,112
======= =======
In 1995 the Company recognized net gains of approximately $18.4 million
from its investments compared with net gains in 1994 of $6.7 million and in
1993 of $4.0 million. These gains do not include gains or losses from natural
gas futures contracts accounted for as a hedge of natural gas production. Hedge
gains or losses are included in natural gas revenue in the period in which the
hedged production occurs (see Note 1).
The net investment gains and losses recognized during a period include
both realized and unrealized gains and losses. The Company realized net gains
from investments of $12.3 million in 1995, $4.7 million in 1994, and $2.3
million in 1993. At December 31, 1995, the Company had recognized but not
realized approximately $7.6 million of gains associated primarily with natural
gas futures. Subsequent to year end, the Company closed some of its positions
which were open on December 31, 1995. As of March 6, 1996, the Company had
closed substantially all of the positions open at December 31, 1995, at a
realized loss of $156,000. Positions which were open at December 31, 1995, and
remain open had unrealized gains of $1.7 million at March 6, 1996.
In 1995 the Company invested in certain over-the-counter commodity price
swap agreements for trading purposes. The Company is required to make payments
to (or receive payments from) a counter party based on the differential between
a fixed and a variable price for specified natural gas volumes. The Company's
agreements expire on the last day of trading for April, May and June 1996
natural gas futures contracts as determined by the NYMEX. The Company is the
fixed price payor on a notional quantity of 10.1
F-14
<PAGE> 82
million British thermal units of natural gas with a fair value of $18.3 million
at December 31, 1995. The average fair value of such commodity price swaps
during 1995 was $18.4 million. In 1995 the Company also entered into
over-the-counter natural gas futures call and put options contracts. At
December 31, 1995, the open quantity of options was 1,800 contracts (each
contract represents 10,000 MMBtu of natural gas) with a fair value of $1.0
million. The average fair value of such option contracts during 1995 was $.4
million. The counter party to these instruments is a credit-worthy financial
institution which is a recognized market-maker. The Company believes the risk
of incurring losses related to credit risk of the counter party is remote.
(4) Long-term Debt
==============
Long-term debt and current maturities are as follows (in thousands):
December 31
------------------------
1995 1994
---------- ----------
HCLP Secured Notes.......................... $ 504,674 $ 520,180
Credit Agreement............................ 61,131 71,131
12-3/4% secured discount notes.............. 618,518 581,942
12-3/4% unsecured discount notes............ 39,725 37,345
13-1/2% subordinated notes.................. 7,390 7,390
Other....................................... 5,305 5,305
---------- ----------
1,236,743 1,223,293
Current maturities.......................... (101,413) (30,537)
---------- ----------
Long-term debt.............................. $1,135,330 $1,192,756
========== ==========
HCLP Secured Notes
- ------------------
In 1991 HCLP issued $616 million of secured notes (the "HCLP Secured
Notes") in a private placement with a group of institutional lenders. The
issuance also funded a $66 million restricted cash balance within HCLP, which
is available to supplement cash flows from the HCLP properties in the event
such cash flows are not sufficient to fund principal and interest payments on
the HCLP Secured Notes when due. As the HCLP Secured Notes are repaid, the
required restricted cash balance is reduced. HCLP holds substantially all of
the Company's Hugoton field natural gas properties.
The HCLP Secured Notes were issued in 15 series and have final stated
maturities extending through 2012 but can be retired earlier. The HCLP Secured
Notes outstanding at December 31, 1995, bear interest at fixed rates ranging
from 8.80% to 11.30% per annum (weighted average 10.31%). Principal and
interest payments are made semiannually. Provisions in the HCLP Secured Note
agreements require interest rate premiums to be paid to the noteholders in the
event that the HCLP Secured Notes are repaid more rapidly or slowly than under
the initial scheduled amortization. Beginning in August 1994,
F-15
<PAGE> 83
HCLP elected to make principal payments on the HCLP Secured Notes based on
actual production, rather than according to the initial scheduled amortization.
As a result, interest rate premiums at a rate of 1.5% per annum will be applied
to those principal amounts not paid according to the initial scheduled
amortization and .35% per annum will be applied to the remaining notes. Such
premiums have increased the effective weighted average interest rate payable on
the remaining HCLP Secured Notes outstanding to 10.79% per annum at December
31, 1995.
The HCLP Secured Note agreements contain various covenants which, among
other things, limit HCLP's ability to sell or acquire oil and gas property
interests, incur additional indebtedness, make unscheduled capital
expenditures, make distributions of property or funds subject to the mortgage,
or enter into certain types of long-term contracts or forward sales of
production. The agreements also require HCLP to maintain separate existence
from the Company and its other subsidiaries. The assets of HCLP that are
subject to the mortgage securing the HCLP Secured Notes are dedicated to
service HCLP's debt and are not available to pay creditors of the Company or
its subsidiaries other than HCLP. Any cash not subject to the mortgage is
available for distribution to the Company's subsidiaries which own HCLP's
equity.
The HCLP Secured Note agreements also contain a provision which requires
calculation and payment of premiums on early retirement of the HCLP Secured
Notes. The actual premiums due in the event of a redemption of the HCLP Secured
Notes will depend on prevailing interest rates at the date of redemption and
the amount of debt redeemed. In the aggregate, such premiums would have totaled
$79 million as of December 31, 1995.
Revenues received from production from HCLP's Hugoton properties are
deposited in a collection account maintained by a collateral agent (the
"Collateral Agent"). The Collateral Agent releases or reserves funds, as
appropriate, for the payment of royalties, taxes, operating costs, capital
expenditures and principal and interest on the HCLP Secured Notes. Only after
all required payments have been made may any remaining funds held by the
Collateral Agent be released from the mortgage.
By April 29, 1996, HCLP is required to obtain a reserve report as of
December 31, 1995, covering its Hugoton field properties prepared by an
independent engineering consultant. HCLP is required to compare the reserve
quantities in such reserve report to the initial reserve quantities set forth
in the HCLP Secured Note agreements, adjusted for production. If the quantities
in such reserve report are less than the adjusted initial quantities, a Deficit
Reserve Amount ("DRA"), as defined, is determined to exist. To the extent a DRA
exists, the Collateral Agent is required to retain additional funds in the
collection account subject to the mortgage for the repayment of the HCLP
Secured Notes. The Company is not obligated to fund any principal payments at
HCLP from sources other than HCLP's Hugoton field properties. The independent
reserve report has not been completed, but HCLP has received preliminary
indications that the independent engineers' estimates of reserve quantities
related to the Hugoton field properties will reflect a downward revision from
previous years. Although HCLP has not determined whether a DRA will result from
such downward revisions, preliminary estimates indicate that a DRA, if any,
will not be material.
F-16
<PAGE> 84
The restricted cash balance and cash held by the Collateral Agent for
payment of interest and principal on the HCLP Secured Notes are invested by the
Collateral Agent under the terms of a guaranteed investment contract (the
"GIC") with Morgan Guaranty Trust Co. of New York ("Morgan"). Morgan was paid
$13.9 million at the date of issuance of the HCLP Secured Notes to guarantee
that funds invested under the GIC would earn an interest rate equivalent to the
weighted average coupon rate on the outstanding principal balance of the HCLP
Secured Notes (10.31% at December 31, 1995). A portion of this amount may be
refunded if the HCLP Secured Notes are repaid earlier than if HCLP had produced
according to its scheduled production, depending primarily on prevailing
interest rates at that time.
HCLP's cash balances were as follows (in thousands):
December 31
----------------
1995 1994
------- -------
Subject to the mortgage.............................. $40,163 $48,087
Not subject to the mortgage.......................... 7,450 1,551
------- -------
Cash included in current assets...................... $47,613 $49,638
======= =======
Restricted cash included in noncurrent assets........ $57,731 $61,299
======= =======
Refundable GIC fee included in noncurrent assets..... $ 9,010 $10,295
======= =======
Mesa Operating Co. ("MOC"), a Company subsidiary which owns 99% of the
limited partnership interests of HCLP, is party to a services agreement with
HCLP. MOC provides services necessary to operate the Hugoton field properties
and market production therefrom, processes remittances of production revenues
and performs certain other administrative functions in exchange for a services
fee. The fee totaled approximately $13.2 million in 1995, $12.8 million in
1994, and $11.4 million in 1993.
Credit Agreement
- ----------------
As of December 31, 1995, the Company had outstanding borrowings of
approximately $61.1 million and letter of credit obligations of $11.4 million
under its $82.5 million bank credit facility, as amended (the "Credit
Agreement"). The Credit Agreement requires principal payments of $22.5 million
in the first half of 1996 with the remainder due in June 1997 (including cash
collateralization of letters of credit outstanding at that time).
The rate of interest payable on borrowings under the amended Credit
Agreement is the lesser of the Eurodollar rate plus 2-1/2% or the prime rate
plus 1/2%. Obligations under the Credit Agreement are secured by a first lien
on the Company's West Panhandle field properties, the Company's equity interest
in MOC and a 76% limited partner interest in HCLP.
F-17
<PAGE> 85
The amended Credit Agreement requires the Company to maintain tangible
adjusted equity, as defined, of at least $50 million and available cash, as
defined, of at least $32.5 million. At December 31, 1995, the Company's
tangible adjusted equity, as defined, was approximately $64.7 million and
available cash, as defined, was $139.5 million. See Note 2 for discussion of
the tangible adjusted equity covenant and its potential effect on the Company's
liquidity.
The Credit Agreement also restricts, among other things, the Company's
ability to incur additional indebtedness, create liens, pay dividends, acquire
stock or make investments, loans and advances.
Discount Notes
- --------------
In conjunction with a debt exchange transaction consummated on August 26,
1993, (the "Debt Exchange"), the Company issued approximately $435.5 million
initial accreted value, as defined, of 12-3/4% secured discount notes due June
30, 1998 and $136.9 million initial accreted value, as defined, of 12-3/4%
unsecured discount notes due June 30, 1996 (together, the "Discount Notes") in
exchange for $293.7 million aggregate principal amount of 12% subordinated
notes and $292.6 million aggregate principal amount of 13-1/2% subordinated
notes (together with the $28.6 million of accrued interest claims thereon). The
Company also issued $29.3 million principal amount of 0% convertible notes due
June 30, 1998, which were converted into approximately 7.5 million shares of
common stock by the end of 1993. The Discount Notes, which rank pari passu with
each other, are senior in right of payment to the remaining 13-1/2%
subordinated notes due 1999 and subordinate to all permitted first lien debt,
as defined, including obligations under the Credit Agreement.
On March 2, 1994, the Company issued $48.2 million face amount of
additional 12-3/4% secured discount notes due June 30, 1998. The proceeds of
$42.8 million were used to pay the settlement amount arising from the 1994
settlement of a lawsuit with Unocal Corporation ("Unocal"). The additional
indebtedness incurred to settle the Unocal lawsuit was specifically permitted
under the terms of the indentures governing the Discount Notes and under the
Credit Agreement. (See Note 9 for additional discussion of the Unocal
litigation.)
The Discount Notes did not accrue interest through June 30, 1995; however,
the accreted value, as defined, of both series increased at a rate of 12-3/4%
per year, compounded semiannually, until June 30, 1995. Beginning July 1, 1995,
each series began to accrue interest at an annual rate of 12-3/4%, payable in
cash semiannually in arrears, with the first payment due on December 31, 1995.
In the second quarter of 1994 the Company completed a public offering in
which 16.3 million shares of the Company's common stock were sold for net
proceeds of $93 million ($6 per share) (the "Equity Offering"). The Company
used approximately $87 million of the proceeds to redeem or repurchase $87
million accreted value ($99.1 million face amount at maturity) of 12-3/4%
unsecured discount notes which were due in 1996.
F-18
<PAGE> 86
In the fourth quarter of 1994 the Company used proceeds from increased
borrowings under its amended Credit Agreement to redeem $37.6 million accreted
value ($40.0 million face amount at maturity) of 12-3/4% unsecured discount
notes which were due in 1996.
The 12-3/4% secured discount notes are secured by second liens on the
Company's West Panhandle field properties and a 76% limited partner interest in
HCLP, both of which also secure obligations under the Credit Agreement. The
Company's right to maintain first lien debt, as defined, is limited by the
terms of the Discount Notes to $82.5 million.
See Note 2 for a discussion of certain cross-default provisions in the
Discount Note indentures which could become effective if the Company defaults
under the terms of the tangible adjusted equity covenant of the Credit
Agreement.
The indentures governing the Discount Notes restrict, among other things,
the Company's ability to incur additional indebtedness, pay dividends, acquire
stock or make investments, loans and advances.
Subordinated Notes
- ------------------
The 13-1/2% subordinated notes are unsecured and mature in 1999. Interest
on these notes is payable semiannually in cash.
Interest and Maturities
- -----------------------
The aggregate interest payments, net of amounts capitalized, made during
1995, 1994, and 1993 were $63.8 million, $62.1 million and $86.5 million,
respectively. In addition, on January 2, 1996, according to terms of the
Discount Notes, the Company made a $42 million interest payment related to its
Discount Notes which was due December 31, 1995. Payment of approximately $39.0
million, $70.6 million and $64.6 million of interest incurred during 1995, 1994
and 1993, respectively, has been deferred under the terms of the Debt Exchange
until the repayment dates of the Discount Notes. Such interest is included in
interest expense in the 1995, 1994 and 1993 consolidated statements of
operations.
F-19
<PAGE> 87
The scheduled principal repayments on long-term debt for the next five
years are as follows (in millions):
1996 1997 1998 1999 2000
------ ------ ------ ------ ------
HCLP Secured Notes(a).............. $ 33.9 $ 33.3 $ 36.1 $ 37.1 $ 36.0
Credit Agreement(b)(c)............. 22.5 38.6 -- -- --
12-3/4% secured discount notes(d).. -- -- 617.4 -- --
12-3/4% unsecured discount notes(d) 39.7 -- -- -- --
13-1/2% subordinated notes......... -- -- -- 7.4 --
Other.............................. 5.3 -- -- -- --
------ ------ ------ ------ ------
Total......................... $101.4 $ 71.9 $653.5 $ 44.5 $ 36.0
====== ====== ====== ====== ======
- ----------
(a) Principal payment requirements could be greater, in the aggregate, in
1996 through 1998 if a DRA is determined to exist.
(b) Excludes approximately $11.4 million in letter of credit obligations
currently outstanding and required to be cash collateralized in June
1997.
(c) Maturities may be accelerated if tangible adjusted equity falls
below $50 million. (See Note 2).
(d) Maturities may be accelerated if an Event of Default occurs and
continues under the Credit Agreement. (See Note 2).
Fair Value of Long-term Debt
- ----------------------------
The following is a summary of estimated fair value of the Company's
long-term debt as of the years ended (in thousands):
1995 1994
------------------ ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
HCLP Secured Notes.............. $504,674 $568,641 $520,180 $535,135
Credit Agreement................ 61,131 61,131 71,131 71,131
12-3/4% secured discount notes.. 618,518 541,905 581,942 528,688
12-3/4% unsecured discount notes 39,725 35,262 37,345 37,591
13-1/2% subordinated notes...... 7,390 7,390 7,390 7,390
The fair value of long-term debt is estimated based on the market prices
for the Company's publicly traded debt and on current rates available for
similar debt with similar maturities and security for the Company's remaining
debt. Based on the current financial condition of the Company, there is no
assurance that the Company could obtain borrowings under long-term debt
agreements with terms similar to those described above and receive proceeds
approximating the estimated fair values.
F-20
<PAGE> 88
(5) Income Taxes
============
The Company provides for income taxes using the asset and liability method
under which deferred tax assets and liabilities are recognized by applying the
enacted statutory tax rates applicable to future years to temporary differences
between the financial statement and tax bases of existing assets and
liabilities. The tax basis of the Company's consolidated net assets is greater
than the financial basis of those net assets; therefore a net deferred tax
asset has been recorded. However, due to the Company's history of net operating
losses and its current financial condition, a valuation allowance has been
recorded which offsets the entire net deferred tax asset. A summary of the
Company's net deferred tax asset is as follows (in millions):
December 31
---------------
1995 1994
------ ------
Deferred tax asset................................... $ 261 $ 240
Deferred tax liability............................... -- --
Valuation allowance.................................. (261) (240)
------ ------
Net deferred tax asset.......................... $ -- $ --
====== ======
The principal components of the Company's net deferred tax asset
(utilizing a 39% combined federal and state income tax rate) and the valuation
allowance are as follows (in millions):
December 31
---------------
1995 1994
------ ------
Tax basis of oil and gas properties in
excess of financial basis.......................... $ 75 $ 80
Regular tax net operating loss carryforward.......... 184 156
Other, net........................................... 2 4
Valuation allowance.................................. (261) (240)
------ ------
Net deferred tax asset.......................... $ -- $ --
====== ======
At December 31, 1995, the Company had a regular tax net operating loss
carryforward of approximately $470 million. Additionally, the Company had an
alterative minimum tax loss carryforward available to offset future alternative
minimum taxable income of approximately $450 million. If not used, these
carryforwards will expire between 2007 and 2010.
The Internal Revenue Service Code of 1986 (the "Code") contains numerous
provisions which restrict or limit the use of corporate tax attributes in
conjunction with corporate acquisitions, dispositions, and reorganizations.
Included among these restrictive provisions is Code Section 382 which, in
general, limits the utilization of net operating loss carryovers subsequent to
a substantial change (generally more than 50%) in corporate stock ownership.
The Section 382 ownership change (as defined for tax purposes) is considered on
a cumulative basis over a specified time
F-21
<PAGE> 89
period, normally three years. Successful completion of the Rainwater
transaction (see Note 2) is expected to result in a Section 382 ownership
change which will limit the utilization of the Company's tax carryforwards
prior to their expiration.
The Company assumed from the Partnership any tax liabilities or refunds
which may arise as a result of any changes to Original Mesa's taxable income or
loss for open tax years. During 1993, the Internal Revenue Service (the "IRS")
completed two field examinations of the tax returns filed by Original Mesa for
the tax years 1984 through 1987. In December 1993 the Company made a payment to
the IRS of approximately $13 million, which payment includes interest, in full
settlement of all claims for these years. The Company was fully reserved for
the additional tax assessment relating to the tax years 1984 through 1987. As
of January 1, 1995, there are no remaining open tax years for Original Mesa for
federal income tax purposes.
(6) Property Sales
==============
In April 1993 the Company sold a portion of its Rocky Mountain area
properties for approximately $7.1 million, after adjustments, and recorded a
gain on the sale of approximately $4.1 million. The Company also retained a
reversionary interest in the properties under which the Company will receive a
50% net profits interest in the properties after the purchaser has recovered
its investment and certain other costs and expenses.
In June 1993 the Company sold its interest in the deep portion of the
Hugoton field not owned by HCLP for approximately $19.0 million, after
adjustments, and recorded a gain on the sale of approximately $5.5 million.
(7) Stockholders' Equity
====================
At December 31, 1995, the Company had outstanding 64.1 million shares of
common stock. In 1993 the Company issued 7.5 million shares of common stock in
conjunction with the Debt Exchange (see Note 4). In late 1993 and 1994 the
Company issued a total of approximately 1.7 million shares of common stock in
exchange for the General Partner's 4.14% interest in the subsidiary
partnerships of the Company (see Note 1). In 1994 the Company completed the
Equity Offering which resulted in the issuance of an additional 16.3 million
shares of common stock. Proceeds from the Equity Offering increased
stockholders' equity by approximately $93 million and were used to reduce
long-term debt (see Note 4).
The Company has authorized 10 million shares of preferred stock. No shares
of preferred stock have been issued as of December 31, 1995.
In July 1995, in conjunction with the determination of the Board of
Directors of the Company to include the possible sale or merger of the Company
among its strategic alternatives, the Board approved a proposal that the
Company adopt a limited-term stockholder rights plan (the "Rights Plan"). The
provisions of the Rights Plan would be triggered if a person or group acquired
beneficial ownership of 10% or more of the Company's common stock after July 6,
1995, except pursuant to a "permitted offer" - a tender or exchange offer that
meets certain criteria, whether or not approved by
F-22
<PAGE> 90
the Board. However, if any person or group beneficially owned more than 10% of
the common stock on July 6, 1995, the Rights Plan would not be triggered unless
that person or group were to obtain beneficial ownership of more than 100,000
additional shares. If triggered, the Rights Plan would allow all stockholders,
other than the person or group exceeding the beneficial ownership threshold, to
purchase common stock at a 50% discount.
(8) Notes Receivable
================
Prior to 1992 the Company had notes receivable totaling $68 million,
exclusive of interest, from Bicoastal Corporation ("Bicoastal") which was in
bankruptcy. Because of the uncertainty of collection, the Company did not
record interest on these notes. A plan of reorganization for Bicoastal was
approved by the Bankruptcy Court in September 1992. During 1992 and 1993, the
Company collected a total of approximately $74 million from Bicoastal,
representing all of the Company's principal amount of allowed claims in the
bankruptcy reorganization plan, plus an additional amount representing a
portion of its interest claims. As a result, the Company recorded gains of
$18.5 million in 1993 relating to collections in excess of the recorded
receivable. In 1995 and 1994 the Company recorded gains of $6.4 million and
$16.6 million, respectively, from additional interest claims collected from
Bicoastal.
(9) Contingencies
=============
Masterson
- ---------
In February 1992 the current lessors of an oil and gas lease (the "Gas
Lease") dated April 30, 1955, between R. B. Masterson, et al., as lessor, and
Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in Federal
District Court in Amarillo, Texas, claiming that CIG had underpaid royalties
due under the Gas Lease. Under the agreements with CIG, the Company has an
entitlement to gas produced from the Gas Lease. In August 1992 CIG filed a
third-party complaint against the Company for any such royalty underpayments
which may be allocable to the Company's interest in the Gas Lease. The
plaintiffs alleged that the underpayment was the result of CIG's use of an
improper gas sales price upon which to calculate royalties and that the proper
price should have been determined pursuant to a "favored-nations" clause in a
July 1, 1967, amendment to the Gas Lease (the "Gas Lease Amendment"). The
plaintiffs also sought a declaration by the court as to the proper price to be
used for calculating future royalties.
The plaintiffs alleged royalty underpayments of approximately $500 million
(including interest at 10%) covering the period from July 1, 1967, to the
present. In March 1995 the court made certain pretrial rulings that eliminated
approximately $400 million of the plaintiffs' claims (which related to periods
prior to October 1, 1989), but which also reduced a number of the Company's
defenses. The Company and CIG filed stipulations with the court whereby the
Company would have been liable for between 50% and 60%, depending on the time
period covered, of an adverse judgment against CIG for post-February 1988
underpayments of royalties.
F-23
<PAGE> 91
On March 22, 1995, a jury trial began and on May 4, 1995, the jury
returned its verdict. Among its findings, the jury determined that CIG had
underpaid royalties for the period after September 30, 1989, in the amount of
approximately $140,000. Although the plaintiffs argued that the
"favored-nations" clause entitled them to be paid for all of their gas at the
highest price voluntarily paid by CIG to any other lessor, the jury determined
that the plaintiffs were estopped from claiming that the "favored-nations"
clause provides for other than a pricing-scheme to pricing-scheme comparison.
In light of this determination, and the plaintiffs' stipulation that a
pricing-scheme to pricing-scheme comparison would not result in any "trigger
prices" or damages, defendants asked the court for a judgment that plaintiffs
take nothing. The court, on June 7, 1995, entered final judgment that
plaintiffs recover no monetary damages. The Company cannot predict whether the
plaintiffs will appeal. However, based on the jury verdict and final judgment,
the Company does not expect the ultimate resolution of this lawsuit to have a
material adverse effect on its financial position or results of operations.
Lease Termination
- -----------------
In 1991 the Company sold certain producing oil and gas properties to
Seagull Energy Company ("Seagull"). In 1994 two lawsuits were filed against
Seagull in the 100th District Court in Carson County, Texas, by certain land
and royalty owners claiming that certain of the oil and gas leases owned by
Seagull have terminated due to cessation in production and/or lack of
production in paying quantities occurring at various times from first
production through 1994. In the third quarter of 1995 Seagull filed third-party
complaints against the Company claiming breach of warranty and false
representation in connection with the sale of such properties to Seagull. The
Company believes it has several defenses to these lawsuits including a two-year
limitation on indemnification set forth in the purchase and sale agreement.
Seagull filed a similar third-party complaint against the Company covering
a different lease in the 69th District Court in Moore County, Texas. The
Company believes it has similar defenses in this case.
The plaintiffs in the cases against Seagull are seeking to terminate the
leases. Seagull, in its complaint against the Company, is seeking unspecified
damages relating to any leases which are terminated.
The Company does not expect the resolution of this lawsuit to have a
material adverse effect on its financial position or results of operations.
Unocal
- ------
The Company was subject to a lawsuit relating to a 1985 investment in
Unocal which asserted that certain profits allegedly realized by the Company
and other defendants upon the disposition of Unocal common stock in 1985 were
recoverable by Unocal pursuant to Section 16(b) of the Securities Exchange Act
of 1934. On January 11, 1994, the Company and other defendants entered into a
settlement agreement (the "Settlement Agreement") whereby they agreed to pay
Unocal an aggregate of $47.5 million, of which $42.75
F-24
<PAGE> 92
million was to be paid by the Company and $4.75 million by the other
defendants. The Settlement Agreement was approved by the court on February 28,
1994. The Company funded its share of the settlement amount with proceeds from
issuance of additional long-term debt. (See Note 4 for discussion of the
issuance of the additional long-term debt.) As a result of the settlement, the
Company recognized a $42.8 million loss in the fourth quarter of 1993.
Other
- -----
The Company is also a defendant in other lawsuits and has assumed
liabilities relating to Original Mesa and the Partnership. The Company does not
expect the resolution of these other matters to have a material adverse effect
on its financial position or results of operations.
The Company assumed certain litigation and tax-related obligations from
Original Mesa and the Partnership and also recorded certain contingent
liabilities relating to various matters, including litigation, office space
leases and retirement benefit obligations, in conjunction with the 1986
acquisition of Pioneer Corporation ("Pioneer") and the 1988 acquisition of
Tenneco Inc.'s midcontinent division. During the fourth quarter of 1993, the
Company settled certain claims with the IRS (see Note 5) and resolved or
revalued certain other contingent liabilities to reflect actual or estimated
liabilities. The Company had previously reserved for the IRS claims and certain
other contingencies in excess of the actual or estimated liabilities. As a
result, the Company recorded a net gain of $24 million in the fourth quarter of
1993.
(10) Employee Benefit Plans
======================
Retirement Plans
- ----------------
The Company maintains two defined contribution retirement plans for the
benefit of its employees. The Company expensed $.8 million in 1995, $3.3
million in 1994, and $3.2 million in 1993 in connection with these plans. The
Company determines the contributions to such plans based on a percentage of
each employee's compensation, subject to limitations specified by the Code. The
Company declared contributions of 5% of each employee's compensation in 1995
and 17% of each employee's compensation in 1994 and 1993.
Option Plan
- -----------
In December 1991 the stockholders of the Company approved the 1991 Stock
Option Plan of the Company (the "Option Plan"), which authorized the grant of
options to purchase up to two million shares of common stock to officers and
key employees. In May 1994 the stockholders of the Company approved an
amendment to the Option Plan which increased the number of shares of common
stock authorized from two million to four million. The exercise price for each
share of common stock placed under option cannot be less than 100% of the fair
market value of the common stock on the date the
F-25
<PAGE> 93
option is granted. Upon exercise, the grantee may elect to receive either
shares of common stock or, at the discretion of the Option Committee of the
Board of Directors, cash or certain combinations of stock and cash in an amount
equal to the excess of the fair market value of the common stock at the time of
exercise over the exercise price. At December 31, 1995, the following stock
options were outstanding:
Number of
Options
---------
Outstanding at December 31, 1994............................ 2,926,460
Granted................................................ 20,000
Exercised.............................................. --
Forfeited.............................................. (14,070)
---------
Outstanding at December 31, 1995............................ 2,932,390
=========
The outstanding options at December 31, 1995, are detailed as follows:
Number of Date of Exercise Price
Options Grant Per Share Exercisable
--------- -------- -------------- -----------
1,126,000 .................. 01/10/92 $ 6.8125 1,126,000
134,500 .................. 10/02/92 11.6875 134,500
101,890 .................. 05/18/93 5.8125 81,512
475,000 .................. 11/10/93 7.3750 380,000
75,000 .................. 06/06/94 6.1875 41,250
1,000,000 .................. 12/01/94 4.2500 550,000
20,000 .................. 05/12/95 5.6875 6,000
--------- ---------
2,932,390 2,319,262
========= =========
Options are exercisable from the date of grant as follows: after six
months, 30%; after one year, 55%; after two years, 80%; and after three years,
100%. At December 31, 1995, options for 1,004,890 shares were available for
grant.
In October 1995 the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which establishes accounting and reporting standards for
stock-based employee compensation plans. SFAS No. 123 defines a fair
value-based method of accounting for stock options or similar equity
instruments, but allows companies to continue to measure compensation cost
using the intrinsic value-based method prescribed by Accounting Principles
Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees." Under
the fair value-based method, compensation cost is measured at the grant date
based on the value of the award and is recognized over the service period
(generally, the vesting period). Under the intrinsic value-based method,
compensation cost is the excess, if any, of the quoted market price of the
stock at the date of grant over the exercise price.
F-26
<PAGE> 94
Under the provisions of SFAS No. 123, a company may elect to measure
compensation cost associated with its stock option and similar plans as a
component of compensation expense in its statement of operations. Companies may
also elect to continue to measure compensation cost under the provisions of APB
No. 25. Companies which elect to continue measurement under APB No. 25 are
required to provide pro forma disclosure in the notes to financial statements
reflecting the difference, if any, between compensation cost included in net
income and the cost if the fair value-based method were used including effects
on earnings per share. Since the inception of the Option Plan, the Company has
not recognized any compensation cost related to grants of stock options. The
disclosure requirements of this statement are effective for financial
statements for fiscal years beginning after December 15, 1995. At this time,
the Company does not expect to adopt the fair value-based method of accounting
for its stock option plans and, accordingly, adoption of this statement will
have no impact on the Company's results of operations.
Postretirement Benefits
- -----------------------
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which requires
that the costs of such benefits be recorded over the periods of employee
service to which they relate. For the Company, this standard primarily applies
to postretirement medical benefits for retired and current employees. The
liability for benefits existing at the date of adoption (the "Transition
Obligation") will be amortized over the remaining life of the retirees or 20
years, whichever is shorter.
The Company maintains two separate plans for providing postretirement
medical benefits. One plan covers the Company's retirees and current employees
(the "MESA Plan"). The other plan relates to the retirees of Pioneer which was
acquired by the Company in 1986 (the "Pioneer Plan"). Under the MESA Plan,
employees who retire from the Company and who have had at least ten years of
service with the Company after attaining age 45 are eligible for postretirement
health care benefits. These benefits may be subject to deductibles, copayment
provisions, retiree contributions and other limitations and the Company has
reserved the right to change the provisions of the plan. The Pioneer Plan is
maintained for Pioneer retirees and dependents only and is subject to
deductibles, copayment provisions and certain maximum payment provisions. The
Company does not have the right to change the Pioneer Plan or to require
retiree contributions. Both plans are self-insured indemnity plans and both
coordinate benefits with Medicare as the primary payer. Neither plan is funded.
F-27
<PAGE> 95
The following table reconciles the status of the two plans with the amount
included under other liabilities in the consolidated balance sheet at December
31, 1995, (in thousands):
MESA Pioneer
Plan Plan Total
------ ------- -------
Accumulated Postretirement Benefit
Obligation ("APBO"):
Retirees and dependents............ $1,080 $11,289 $12,369
Actives - fully eligible........... 353 -- 353
Other actives...................... 731 -- 731
------ ------- -------
Total APBO.................... 2,164 11,289 13,453
Unrecognized Transition Obligation...... (1,420) (2,310) (3,730)
------ ------- -------
Accrued Postretirement
Benefit Obligation.................... $ 744 $ 8,979(a) $ 9,723
====== ======= =======
- ----------
(a) The Company established an accrued liability associated with the
Pioneer Plan in conjunction with its acquisition of Pioneer in 1986.
For measurement purposes, the 1995 annual rate of increase in per capita
cost of covered health care benefits was assumed to be 10% for those
participants under age 65 and 9% for those participants over age 65. The rates
were assumed to decrease gradually to 5.0% by the year 2000 and to remain at
that level thereafter. The health care cost trend rate assumption affects the
amount of the Transition Obligation and periodic cost reported. An increase in
the assumed health care cost trend rates by 1% in each year would increase the
APBO as of December 31, 1995, by approximately $735,000 and the net periodic
postretirement benefit cost for the year ended December 31, 1995, by
approximately $77,000. The net periodic postretirement benefit cost for the
year ended December 31, 1995, was approximately $1.4 million based on the
assumptions used.
The discount rate used in determining the APBO as of December 31, 1995,
was 8%.
The following table presents the Company's cost of postretirement benefits
other than pensions for the years ended December 31 (in thousands):
1995 1994 1993
------ ------ ------
Net periodic postretirement benefit cost:
Service cost............................ $ 124 $ 110 $ 96
Interest cost........................... 1,005 988 988
Amortization of Transition Obligation... 276 276 276
------ ------ ------
$1,405 $1,374 $1,360
====== ====== ======
Actual costs of providing benefits:
MESA Plan............................... $ 4 $ 120 $ 123
Pioneer Plan............................ 918 666 909
------ ------ ------
$ 922 $ 786 $1,032
====== ====== ======
F-28
<PAGE> 96
(11) Major Customers
===============
In 1995 revenues include sales to Mapco Petroleum, Inc. ("Mapco") of $75.0
million (34.4%) and Western Resources, Inc. ("WRI") of $21.9 million (10.0%).
In 1994 revenues included sales to Mapco of $70.9 million (31.4%), WRI of $37.4
million (16.6%), and Energas Company of $22.8 million (10.1%). In 1993 revenues
included sales to Mapco of $60.2 million (27.5%), WRI of $51.8 million (23.6%)
and Natural Gas Clearinghouse of $23.1 million (10.5%).
(12) Concentrations of Credit Risk
=============================
Substantially all of the Company's accounts receivable at December 31,
1995, result from oil and gas sales and joint interest billings to third party
companies in the oil and gas industry. This concentration of customers and
joint interest owners may impact the Company's overall credit risk, either
positively or negatively, in that these entities may be similarly affected by
changes in economic or other conditions. In determining whether or not to
require collateral from a customer or joint interest owner, the Company
analyzes the entity's net worth, cash flows, earnings, and credit ratings.
Receivables are generally not collateralized. Historical credit losses incurred
by the Company on receivables have not been significant.
(13) Condensed Consolidating Financial Statements
============================================
Subsidiaries and assets
- -----------------------
The Company conducts its operations through various direct and indirect
subsidiaries. On December 31, 1995, the Company's direct subsidiaries were MOC,
Mesa Holding Co. ("MHC") and Hugoton Management Co. ("HMC"), all of which were
wholly owned by the Company. MOC owns all of the Company's interest in the West
Panhandle field of Texas, the Gulf Coast and the Rocky Mountain areas, as well
as a 98.6% limited partnership interest in HCLP. MHC owns cash and securities,
a 0.9% limited partnership interest in HCLP and 100% of Mesa Environmental
Ventures Co. ("Mesa Environmental"), a company established to compete in the
natural gas vehicle market. HMC owns the 0.5% general partner interest in HCLP.
HCLP owns substantially all of the Company's Hugoton field natural gas
properties.
In early 1994 the Company effected a series of merger transactions which
resulted in the conversion of the predecessors of MOC, MHC, and the other
subsidiary partnerships, other than HCLP, to corporate form and eliminated all
of the General Partner's minority interests in the subsidiaries.
Subsidiary Debt
- ---------------
HCLP, together with its wholly owned subsidiary Hugoton Capital
Corporation (a single purpose financing subsidiary of HCLP), are jointly and
F-29
<PAGE> 97
severally liable as co-obligors under the HCLP Secured Notes (see Note 4). The
assets and cash flows of HCLP that are subject to the mortgage securing the
HCLP Secured Notes are dedicated to service the HCLP Secured Notes and are not
available to pay creditors of the Company or its subsidiaries other than HCLP.
Hugoton Capital Corporation, which has insignificant assets and results of
operations, is included within HCLP in the condensed consolidating financial
statements. MOC is the borrower and primary obligor under, and the Company has
unconditionally guaranteed MOC's obligations under, the Credit Agreement. The
Company, MOC and Mesa Capital Corp. ("Mesa Capital") are jointly and severally
liable as co-obligors under the 13-1/2% subordinated notes and the Discount
Notes. Mesa Capital is a wholly owned financing subsidiary of MOC. Mesa
Capital, which has insignificant assets and results of operations, is included
with MOC in the condensed consolidating financial statements.
Other Company subsidiaries in the condensed consolidating financial
statements include MHC, HMC, and Mesa Environmental. No such Other Company
subsidiary is an obligor or guarantor under any long term debt.
Intercompany Debt
- -----------------
As of December 31, 1993, MHC had intercompany payables to MOC of
approximately $123 million. On February 28, 1994, MHC assigned an 18% limited
partnership interest in HCLP (out of its total interest of 18.9%) to MOC in
satisfaction of $90 million of intercompany payables. Provisions of the
Discount Note indentures required the repayment of intercompany indebtedness to
specified levels and provided that any HCLP limited partnership interests
transferred in satisfaction of intercompany debt would be valued at $5 million
for each one percent of interest assigned. MHC repaid an additional $33 million
of intercompany debt to MOC in cash during 1994. As a result of these
transactions, MOC now owns a 98.6% limited partnership interest in HCLP, and
all of MHC's intercompany debt to MOC which was outstanding at December 31,
1993, was eliminated.
Condensed Consolidating Financial Statements
- --------------------------------------------
The following are condensed consolidating financial statements of MESA
Inc., HCLP, MOC, and the Company's other subsidiaries combined (in millions).
These statements are presented to provide financial information with respect to
the obligors under the Company's debt for the benefit of the holders of such
debt. Separate financial statements of the obligors under the Company's debt
are not presented because they are not required and because the Company
believes that they would not be material to investors. See Note 4 for
additional information regarding the Company's long term debt.
F-30
<PAGE> 98
Condensed Consolidating Balance Sheets
- --------------------------------------
Other Consol. The
MESA Company and Company
December 31, 1995 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Assets:
Cash and cash
investments....... $ - $ 47 $ 38 $ 64 $ - $ 149
Other current
assets............ - 20 53 15 - 88
------ ------ ------ ------ ------ ------
Total current
assets.......... - 67 91 79 - 237
------ ------ ------ ------ ------ ------
Property, plant
and equipment,
net............... - 602 478 3 - 1,083
Investment in
subsidiaries...... 76 - 115 10 (201) -
Intercompany
receivables....... - - 9 - (9) -
Other noncurrent
assets............ - 82 58 5 - 145
------ ------ ------ ------ ------ ------
$ 76 $ 751 $ 751 $ 97 $ (210) $1,465
====== ====== ====== ====== ====== ======
Liabilities and
Equity:
Current
liabilities....... $ - $ 64 $ 128 $ 1 $ - $ 193
Long-term debt..... - 471 665 - - 1,136
Intercompany
payables.......... 9 - - - (9) -
Other noncurrent
liabilities....... - - 66 3 - 69
Partners'/Stock-
holders' equity
(deficit)......... 67 216 (108) 93 (201) 67
------ ------ ------ ------ ------ ------
$ 76 $ 751 $ 751 $ 97 $ (210) $1,465
====== ====== ====== ====== ====== ======
F-31
<PAGE> 99
Other Consol. The
MESA Company and Company
December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Assets:
Cash and cash
investments....... $ - $ 50 $ 24 $ 70 $ - $ 144
Other current
assets............ - 16 39 6 - 61
------ ------ ------ ------ ------ ------
Total current
assets.......... - 66 63 76 - 205
------ ------ ------ ------ ------ ------
Property, plant
and equipment,
net............... - 626 503 1 - 1,130
Investment in
subsidiaries...... 134 - 126 10 (270) -
Intercompany
receivables....... - - 9 - (9) -
Other noncurrent
assets............ - 88 58 3 - 149
------ ------ ------ ------ ------ ------
$ 134 $ 780 $ 759 $ 90 $ (279) $1,484
====== ====== ====== ====== ====== ======
Liabilities and
Equity:
Current
liabilities....... $ - $ 47 $ 41 $ 1 $ - $ 89
Long-term debt..... - 505 688 - - 1,193
Intercompany
payables.......... 9 - - - (9) -
Other noncurrent
liabilities....... - - 73 4 - 77
Partners'/Stock-
holders' equity
(deficit)......... 125 228 (43) 85 (270) 125
------ ------ ------ ------ ------ ------
$ 134 $ 780 $ 759 $ 90 $ (279) $1,484
====== ====== ====== ====== ====== ======
F-32
<PAGE> 100
Condensed Consolidating Statements of Operations
- ------------------------------------------------
Years Ended:
- ------------
Other Consol. The
MESA Company and Company
December 31, 1995 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 97 $ 137 $ 1 $ - $ 235
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 28 49 - - 77
General and
administrative.... - - 24 3 - 27
Depreciation,
depletion and
amortization...... - 34 49 - - 83
------ ------ ------ ------ ------ ------
- 62 122 3 - 187
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 35 15 (2) - 48
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (47) (91) 5 - (133)
Equity in loss of
subsidiaries........ (58) - (11) - 69 -
Other................ - - 21 6 - 27
------ ------ ------ ------ ------ ------
Net Income (Loss).... $ (58) $ (12) $ (66) $ 9 $ 69 $ (58)
====== ====== ====== ====== ====== ======
F-33
<PAGE> 101
Other Consol. The
MESA Company and Company
December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 113 $ 116 $ - $ - $ 229
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 30 49 - - 79
General and
administrative.... - - 26 3 - 29
Depreciation,
depletion and
amortization...... - 37 55 - - 92
------ ------ ------ ------ ------ ------
- 67 130 3 - 200
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 46 (14) (3) - 29
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (47) (87) 3 - (131)
Losses on
dispositions of
oil and gas
properties.......... - - - (91)(d) 91 -
Equity in loss of
subsidiaries........ (83) - (1) - 84 -
Other................ - - 22 15 (18) 19
------ ------ ------ ------ ------ ------
Net Loss............. $ (83) $ (1) $ (80) $ (76) $ 157 $ (83)
====== ====== ====== ====== ====== ======
F-34
<PAGE> 102
Other Consol. The
MESA Company and Company
December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 103 $ 120 $ (1) $ - $ 222
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 27 48 - - 75
General and
administrative.... - - 23 2 - 25
Depreciation,
depletion and
amortization...... - 35 65 - - 100
------ ------ ------ ------ ------ ------
- 62 136 2 - 200
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 41 (16) (3) - 22
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (50) (83) 2 - (131)
Intercompany interest
income (expense).... - - 16 (16) - -
Gains of dispositions
of oil and gas
properties.......... - - 10 - - 10
Equity in loss of
subsidiaries........ (102) - (7) (2) 111 -
Other................ - - (42) 29 10 (3)
------ ------ ------ ------ ------ ------
Net Income (Loss).... $ (102) $ (9) $ (122) $ 10 $ 121 $ (102)
====== ====== ====== ====== ====== ======
F-35
<PAGE> 103
Condensed Consolidating Statements of Cash Flows
- ------------------------------------------------
Years Ended:
- ------------
Other Consol. The
MESA Company and Company
December 31, 1995 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 20 $ 50 $ (1) $ - $ 69
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (10) (30) (2) - (42)
Other.............. - - 4 (3) - 1
------ ------ ------ ------ ------ ------
- (10) (26) (5) - (41)
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Repayments of
long-term debt.... - (16) (10) - - (26)
Other.............. - 4 - - - 4
------ ------ ------ ------ ------ ------
- (12) (10) - - (22)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ (2) $ 14 $ (6) $ - $ 6
====== ====== ====== ====== ====== ======
F-36
<PAGE> 104
Other Consol. The
MESA Company and Company
December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 41 $ (15) $ 23 $ - $ 49
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (7) (26) - - (33)
Contributions to
subsidiaries...... (93) - (5) (1) 99 -
Distributions from
subsidiaries...... - - 10 - (10) -
Other.............. - - 28 (2) (33) (7)
------ ------ ------ ------ ------ ------
(93) (7) 7 (3) 56 (40)
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Issuance of
common stock...... 93 - - - - 93
Repayments of
long-term debt.... - (21) (154) - - (175)
Long-term
borrowings........ - - 78 - - 78
Contributions from
equity holders.... - 6 93 - (99) -
Distribution to
partners.......... - (10) - - 10 -
Other.............. - 1 (1) (33) 33 -
------ ------ ------ ------ ------ ------
93 (24) 16 (33) (56) (4)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ 10 $ 8 $ (13) $ - $ 5
====== ====== ====== ====== ====== ======
F-37
<PAGE> 105
Other Consol. The
MESA Company and Company
December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 21 $ 16 $ (4) $ - $ 33
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (8) (21) (1) - (30)
Proceeds from
dispositions of
oil and gas
properties........ - - 26 - - 26
Other.............. - - 30 46 (35) 41
------ ------ ------ ------ ------ ------
- (8) 35 45 (35) 37
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Repayments of
long-term debt.... - (39) (41) - - (80)
Other.............. - 2 (10) (35) 35 (8)
------ ------ ------ ------ ------ ------
- (37) (51) (35) 35 (88)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ (24) $ - $ 6 $ - $ (18)
====== ====== ====== ====== ====== ======
Notes to Condensed Consolidating Financial Statements
- -----------------------------------------------------
(a) These condensed consolidating financial statements should be read in
conjunction with the consolidated financial statements of the Company
and notes thereto of which this note is an integral part.
(b) As of December 31, 1995, the Company owns 100% interest in each of
MOC, MHC, and HMC. These condensed consolidating financial
statements present the Company's investment in its subsidiaries
and MOC's and MHC's investments in HCLP using the equity method.
Under this method, investments are recorded at cost and adjusted
for the parent company's ownership share of the subsidiary's
cumulative results of operations. In addition, investments
increase in the amount of contributions to subsidiaries and
decrease in the amount of distributions from subsidiaries.
(c) The consolidation and elimination entries (i) eliminate the equity
method investment in subsidiaries and equity in income (loss) of
subsidiaries, (ii) eliminate the intercompany payables and
receivables, (iii) eliminate other transactions between
subsidiaries including contributions and distributions, and (iv)
establish the General Partner's minority interest in the
consolidated results of operations and financial position of the
Company.
(d) The condensed consolidating statement of operations of MHC for the
year ended December 31, 1994, reflects a $91 million loss from its
F-38
<PAGE> 106
disposition of an 18% equity interest in HCLP. The HCLP equity
interest was used to repay a portion of MHC's intercompany payable
to MOC and was valued, in accordance with the provisions of the
Discount Note indentures, at $5 million for each one percent of
interest assigned. A loss was recognized for the difference
between the carrying value of the HCLP interest assigned to MOC
and the $90 million value attributed to such interests which
reduced the intercompany payable. The loss recognized by MHC is
eliminated in consolidation.
F-39
<PAGE> 107
SUPPLEMENTAL FINANCIAL DATA
===========================
Oil and Gas Reserves and Cost Information
- -----------------------------------------
(Unaudited)
Net proved oil and gas reserves as of December 31, 1995 and 1994, were
estimated by Company engineers. Net proved oil and gas reserves as of December
31, 1993, associated with the Company's two most significant natural gas
producing fields were estimated by independent petroleum engineering
consultants. These two fields, the Hugoton and West Panhandle fields,
represented over 95% of the Company's net proved equivalent natural gas
reserves as of the date estimated by the independent petroleum engineers. All
of the Company's reserves at December 31, 1995, 1994, and 1993, were in the
United States. In accordance with regulations established by the Commission,
the reserve estimates were based on economic and operating conditions existing
at the end of the respective years.
Future prices for natural gas were based on market prices as of each year
end and contract terms, including fixed and determinable price escalations.
Market prices received as of each year end were used for future sales of oil,
condensate and natural gas liquids. Future operating costs, production and ad
valorem taxes and capital costs were based on current costs as of each year
end, with no escalation.
Approximately 65% of the Company's equivalent proved reserves (based on a
factor of six thousand cubic feet ["Mcf"] of gas per barrel of liquids) at
December 31, 1995, is natural gas. The natural gas prices in effect at December
31, 1995, (having a weighted average of $1.95 per Mcf) were used in accordance
with Commission regulations but may not be the most appropriate or
representative prices to use for estimating reserves since such prices were
influenced by the seasonal demand for natural gas and contractual arrangements
at that date. The average price received by the Company for sales of natural
gas in 1995 was $1.48 per Mcf. Assuming all other variables used in the
calculation of reserve data are held constant, the Company estimates that each
$.10 change in the price per Mcf for natural gas production would affect the
Company's estimated future net cash flows and present value thereof, both
before income taxes, by $109 million and $44 million, respectively. At December
31, 1995, the Company's standardized measure of future net cash flows from
proved reserves (the "Standardized Measure") and the pretax Standardized
Measure were less than the net book
F-40
<PAGE> 108
value of oil and gas properties by approximately $100 million and $25 million,
respectively. The Company believes that the ultimate value to be received for
production from its oil and gas properties will be greater than the current net
book value of its oil and gas properties.
At December 31, 1993, the Company's internal estimates of proved reserves
for the Hugoton and West Panhandle properties were greater than the estimates
prepared by independent petroleum engineers as of such date. In the Hugoton
field, the primary difference reflects increased reserves for properties on
which the Company drilled 382 infill wells since 1987 resulting from the
Company's internal interpretation of pressure and cumulative production data.
In the West Panhandle field, the reserve differences result from the
interpretation of cumulative production data on producing wells and in the
estimates of proved undeveloped reserves.
Oil and gas reserve quantities estimated as of December 31, 1995, reflect
a net increase over 1994, after production, of approximately 171 Bcfe of
natural gas. Equivalent natural gas reserves increased in each of the Company's
major production areas. Increases in Hugoton field reserves reflect alignment
of the assumptions used in preparing the proved reserve estimates with the
Company's practice of recovering ethane at the Satanta Plant. In previous years
Hugoton proved reserve estimates were prepared assuming that the Company would
not recover ethane which resulted in slightly higher natural gas volumes, lower
natural gas liquids volumes and lower total equivalent volumes than if ethane
recovery were assumed. The decision as to whether or not to recover ethane is
based on the relative value of ethane as a liquid versus the energy-equivalent
value of such ethane if left in the residue natural gas. In the future, if
economic conditions warrant, the Company may revise proved reserves to reflect
any changes in such relative values. In the West Panhandle field, reserves were
revised upward to reflect the development drilling results over the past year
and the planned upgrade of the Fain Plant for a higher rate of liquids recovery
per Mcf of gas produced from the field. In the Gulf Coast, reserve additions
resulted from exploratory and development drilling in 1994 and 1995.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures. Reserve data represent estimates only and should not
be construed as being exact. Estimates prepared by other engineers might be
materially different from those set forth herein. Moreover, the Standardized
Measure should not be construed as the current market value of the proved oil
and gas reserves or the costs that would be incurred to obtain equivalent
reserves. A market value determination would include many additional factors
including (i) anticipated future changes in oil and gas prices, and production
and development costs; (ii) an allowance for return on investment; (iii) the
value of additional reserves, not considered proved at present, which may be
recovered as a result of further exploration and development activities; and
(iv) other business risks.
F-41
<PAGE> 109
Capitalized Costs and Costs Incurred
- ------------------------------------
(Unaudited)
Capitalized costs relating to oil and gas producing activities at December
31, 1995, 1994, and 1993 and the costs incurred during the years then ended are
set forth below (in thousands):
1995 1994 1993
Capitalized Costs: ---------- ---------- ----------
Proved properties................ $1,897,168 $1,865,004 $1,845,483
Unproved properties.............. 2,995 2,838 754
Accumulated depreciation,
depletion and amortization..... (834,304) (753,827) (670,706)
---------- ---------- ----------
Net......................... $1,065,859 $1,114,015 $1,175,531
========== ========== ==========
Costs Incurred:
Exploration and development:
Proved properties........... $ 269 $ 523 $ 73
Unproved properties......... 157 2,425 17
Exploration costs........... 8,167 5,157 2,705
Development costs........... 14,572 14,043 2,381
---------- ---------- ----------
Total exploration and
development.......... 23,165 22,148 5,176
---------- ---------- ----------
Plants and facilities:
Processing plants........... 1,850 3,248 17,501
Field compression facilities 10,561 3,129 4,387
Other....................... 3,354 5,168 2,257
---------- ---------- ----------
Total plants and
facilities........... 15,765 11,545 24,145
---------- ---------- ----------
Total costs incurred............. $ 38,930 $ 33,693 $ 29,321
========== ========== ==========
Depreciation, depletion
and amortization............... $ 80,513 $ 89,413 $ 96,774
========== ========== ==========
F-42
<PAGE> 110
Estimated Quantities of Reserves
- --------------------------------
(Unaudited) Years Ended December 31
------------------------------------
Natural Gas (MMcf) 1995 1994 1993
- ----------- ---------- ---------- ----------
Proved Reserves:
Beginning of year................ 1,303,187 1,202,444 1,276,049
Extensions and discoveries.. 29,728 6,211 5,132
Purchases of producing
properties................ 1,000 822 166
Revisions of previous
estimates................. (38,574) 176,049 7,284
Sales of producing
properties................ -- -- (6,367)
Production.................. (77,312) (82,339) (79,820)
---------- ---------- ----------
End of year...................... 1,218,029 1,303,187 1,202,444
========== ========== ==========
Proved Developed Reserves:
Beginning of year................ 1,257,883 1,159,453 1,223,672
========== ========== ==========
End of year...................... 1,160,751 1,257,883 1,159,453
========== ========== ==========
Years Ended December 31
Natural Gas Liquids, Oil ------------------------------------
and Condensate (MBbls) 1995 1994 1993
- ------------------------ ---------- ---------- ----------
Proved Reserves:
Beginning of year................ 89,428 82,446 87,392
Extensions and discoveries.. 3,121 491 778
Purchases of producing
properties................ 5 1 --
Revisions of previous
estimates................. 26,630 13,947 3,083
Sales of producing
properties................ -- -- (3,019)
Production.................. (7,766) (7,457) (5,788)
---------- ---------- ----------
End of year...................... 111,418 89,428 82,446
========== ========== ==========
Proved Developed Reserves:
Beginning of year................ 85,656 79,294 82,439
========== ========== ==========
End of year...................... 105,197 85,656 79,294
========== ========== ==========
* Proved natural gas liquids, oil and condensate reserve quantities include
oil and condensate reserves at December 31 of the respective years as
follows: 1995, 9,521 MBbls; 1994, 5,031 MBbls; and 1993, 3,296 MBbls.
F-43
<PAGE> 111
* In addition to the proved reserves disclosed above, the Company owned proved
helium and carbon dioxide ("CO2") reserves at December 31 of the respective
years as follows: 1995, 3,670 MMcf of helium and 46,459 MMcf of CO2; 1994,
4,457 MMcf of helium and 46,459 MMcf of CO2; and 1993, 5,198 MMcf of helium
and 46,376 MMcf of CO2.
F-44
<PAGE> 112
Standardized Measure of Future Net Cash Flows from Proved Reserves
- ------------------------------------------------------------------
(Unaudited)
December 31
------------------------------------
1995 1994 1993
---------- ---------- ----------
(in thousands)
Future cash inflows................... $3,804,371 $3,513,282 $3,723,760
Future production and
development costs:
Operating costs and
production taxes............... (1,257,957) (1,192,005) (1,337,224)
Development and
abandonment costs.............. (96,594) (95,441) (80,310)
Future income taxes................... (296,987) (211,076) (240,017)
---------- ---------- ----------
Future net cash flows................. 2,152,833 2,014,760 2,066,209
Discount at 10% per annum........ (1,186,644) (1,080,578) (1,079,278)
---------- ---------- ----------
Standardized Measure.................. $ 966,189 $ 934,182 $ 986,931
========== ========== ==========
Future net cash flows
before income taxes................. $2,449,820 $2,225,836 $2,306,226
========== ========== ==========
Standardized Measure
before income taxes................. $1,040,413 $ 988,325 $1,068,740
========== ========== ==========
- ----------
* The estimate of future income taxes is based on the future net cash flows
from proved reserves adjusted for the tax basis of the oil and gas
properties but without consideration of general and administrative and
interest expenses.
F-45
<PAGE> 113
Changes in Standardized Measure
- -------------------------------
(Unaudited)
Years Ended December 31
------------------------------------
1995 1994 1993
---------- ---------- ----------
(in thousands)
Standardized Measure at
beginning of year................... $ 934,182 $ 986,931 $1,037,181
---------- ---------- ----------
Revisions of reserves proved in prior years:
Changes in prices and
production costs............... 52,724 (121,300) 6,178
Changes in quantity estimates.... 71,673 151,538 17,616
Changes in estimates of
future development and
abandonment costs.............. (18,424) (27,343) 8,054
Net change in income taxes....... (20,081) 27,666 48,703
Accretion of discount............ 98,833 106,874 116,769
Other, primarily timing
of production.................. (94,511) (80,650) (108,371)
---------- ---------- ----------
Total revisions............. 90,214 56,785 88,949
Extensions, discoveries and
other additions, net of future
production and development costs.... 61,259 8,075 4,456
Purchases of proved properties........ 1,692 463 138
Sales of oil and gas produced,
net of production costs............. (154,231) (146,267) (143,502)
Sales of producing properties......... - - (26,907)
Previously estimated development
and abandonment costs incurred
during the period................... 33,073 28,195 26,616
---------- ---------- ----------
Net changes in Standardized Measure... 32,007 (52,749) (50,250)
---------- ---------- ----------
Standardized Measure at end of year... $ 966,189 $ 934,182 $ 986,931
========== ========== ==========
F-46
<PAGE> 114
Quarterly Results
- -----------------
(Unaudited)
Quarters Ended
-------------------------------------------------
March 31 June 30 September 30 December 31
-------- -------- ------------ -----------
(in thousands, except per share data)
1995:
- ----
Revenues............ $ 62,247 $ 59,174 $ 48,967 $ 64,571
======== ======== ======== ========
Gross profit(1)..... $ 44,928 $ 44,066 $ 29,926 $ 45,821
======== ======== ======== ========
Operating income.... $ 15,974 $ 17,080 $ 219 $ 14,692
======== ======== ======== ========
Net loss............ $ (7,894) $(13,953) $(32,473) $ (3,248)(2)
======== ======== ======== ========
Net loss per
common share...... $ (.12) $ (.22) $ (.51) $ (.05)
======== ======== ======== ========
1994:
- ----
Revenues............ $ 61,084 $ 53,361 $ 45,725 $ 68,567
======== ======== ======== ========
Gross profit(1)..... $ 42,214 $ 34,462 $ 28,713 $ 49,387
======== ======== ======== ========
Operating income
(loss)............ $ 10,176 $ 4,867 $ (2,065) $ 15,705
======== ======== ======== ========
Net loss............ $(17,766) $(25,338) $(25,907) $(14,342)
======== ======== ======== ========
Net loss per
common share...... $ (.37) $ (.43) $ (.40) $ (.22)
======== ======== ======== ========
- ----------
(1) Gross profit consists of total revenues less lease operating expenses
and production and other taxes.
(2) In the fourth quarter of 1995 results of operations included net
gains from investments of $18.4 million. (See Note 3 to the
consolidated financial statements of the Company.)
F-47
<PAGE> 115
INDEX TO EXHIBITS
-----------------
Exhibit No. Description
----------- -----------
10.14 - Amarillo Supply Agreement between Mesa Operating Limited
Partnership, Seller, and Energas Company, a division of Atmos
Energy Corporation, Buyer, dated effective January 2, 1993.
10.15 - Gas Gathering Agreement-Interruptible between Colorado
Interstate Gas Company, Transporter, and Mesa Operating
Limited Partnership, Shipper, dated effective October 1,
1993, as amended by agreements dated January 1, 1994, January
5, 1994, June 1, 1994, and March 1, 1996.
10.16 - Gas Supply Agreement dated May 11, 1994, between Mesa
Operating Co., as successor to Mesa Operating Limited
Partnership, acting on behalf of itself and as agent for
Hugoton Capital Limited Partnership, and Williams Gas
Marketing Company, and Gas Supply Guarantee dated May 11,
1994.
10.22 - Interruptible Gas Transportation and Sales Agreement dated
January 1, 1991, between Mesa Operating Limited Partnership and
Energas Company and Amendment dated January 1, 1995.
10.23 - "B" Contract Operating Agreement dated January 1, 1988,
between Mesa Operating Limited Partnership and Colorado
Interstate Gas Company.
10.24 - "B" Contract Agreement of Compromise and Settlement dated May
29, 1987, between Mesa Operating Limited Partnership and
Colorado Interstate Gas Company, and Amendment to Gathering
Agreement dated July 15, 1990.
10.25 - Gas Purchase Agreement dated January 1, 1996, between Mesa
Operating Co., as Seller, and KN Marketing L.P., as Buyer, and
Amendment dated August 1, 1995.
10.26 - Change in Control Retention/Severance Plan adopted August 22,
1995, and Amendment dated October 20, 1995.
22 - List of Subsidiaries of the Company.
27 - Article 5 of Regulation S-X Financial Data Schedule
for Year-End 1995 Form 10-K.
28 - Summary Report of the Company relating to proved oil and gas
reserves at December 31, 1995.
