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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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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, 1994
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (No Fee Required)
Commission File Number 1-9041
MESA Inc.
=========
(Exact Name of Registrant as Specified In Its Charter)
Texas 75-2394500
----- ----------
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Number)
5205 North O Connor Boulevard
Suite 1400
Irving, Texas (214) 444-9001 75039-3746
----------------------------- ----------------- ----------
(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
------------------------------------------- -----------------------
Common stock, $.01 par value........................ 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. [ ]
Number of shares outstanding as of the close of business on March 22,
1995: 64,050,009.
Aggregate market value of 56,097,104 shares held by non-affiliates of
Registrant at the closing price on March 22, 1995, of $6.00: $336,582,624
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 1995 Annual
Meeting of Stockholders are incorporated by reference into Part III hereof.
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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 and Reports on Form 8-K
Signatures
<PAGE>
PART I
Item 1. Business
=================
The Company
-----------
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 exploration, development, production, and processing of
domestic oil and gas.
As of December 31, 1994, Mesa owned approximately 1.8 trillion cubic
feet of equivalent proved natural gas reserves ("Tcfe"). Over 70% of Mesa's
total equivalent proved reserves are natural gas and the balance are
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 6 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 natural gas liquids 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 natural gas as a transportation fuel, including the
construction and operation of natural gas fueling stations and the
development and marketing of natural gas fuel equipment for the
transportation market.
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 5205 North O Connor Boulevard, Suite 1400, Irving,
Texas 75039-3746, where its telephone number is (214) 444-9001. At December
31, 1994, Mesa employed 399 employees.
Recent Events
-------------
Mesa has a highly leveraged capital structure with long-term debt
totaling approximately $1.2 billion at December 31, 1994. Cash flows from
the production and sale of oil and gas at current prices are not expected to
be sufficient during the next few years to service Mesa's obligations,
including its long-term debt. Furthermore, Mesa's ability to develop and
increase its reserves and production is limited by its leveraged capital
structure.
Mesa has considered numerous alternatives for reducing its long-term
debt and in late 1994 announced its intention to sell all or a portion of
its interests in the Hugoton field of Kansas. During the first quarter of
1995, Mesa began an auction process intended to result in the sale of all
its Hugoton interests. At December 31, 1994, Mesa's proved reserves in the
Hugoton field totaled 1.2 Tcfe. During 1994, Mesa produced 73 billion cubic
feet of equivalent natural gas ("Bcfe") from these properties. Proceeds
from a sale would be used to retire long-term debt. Excluding the Hugoton
properties, Mesa had proved reserves of 648 Bcfe at December 31, 1994, and
produced 55 Bcfe during 1994. There can be no assurance that Mesa will sell
its Hugoton properties. If Mesa does not sell these properties, it intends
to seek other means to refinance or retire its debt.
Properties
----------
Approximately 96% 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's capital budget has been directed principally
toward the construction of NGL processing facilities and improvements in its
compression and gathering systems. While Mesa expects to direct additional
capital expenditures toward exploration in 1995 and in future years, Mesa
does not expect that the amounts presently budgeted will be sufficient to
replace annual production with new reserve additions.
Over the past several 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. In the West Panhandle
field, development activities have included well workovers and deepenings,
adding compression facilities, and the expansion and upgrading of natural
gas processing facilities. 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. Mesa has also
negotiated new natural gas sales contracts over the past several years to
provide market-based pricing on most of its production. Two significant gas
sales contracts will expire in May 1995, thus giving Mesa a substantial
amount of uncommitted deliverability available for sale after that date.
Mesa's strategies for replacing production with new reserve additions
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 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 and extent of its capital-raising and deleveraging
activities.
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
-------------
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 over 1,300 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 over 260 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, Mesa has
available to market over 175 MMcf of residue (processed) gas and 14 thousand
barrels ("MBbls") of NGLs on a peak production day. Production in the
Hugoton field is limited by allowables set by state regulators. Mesa
attempts to shift as much of its production as is practicable into the
heating season, when prices are generally higher. Mesa believes that its
ability to aggregate significant volumes of natural gas and NGLs at central
delivery points enhances its marketing opportunities and competitive
position within the industry.
Mesa's Hugoton properties accounted for approximately 65% of its
equivalent proved reserves and 66% of the present value of estimated future
net cash flows before income taxes, determined as of December 31, 1994, in
accordance with Securities and Exchange Commission (the "Commission")
guidelines. The Hugoton properties accounted for approximately 53%, 48%,
and 40% of Mesa's oil and gas revenues for the years ended December 31,
1994, 1993, and 1992, 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 and to lower production levels caused by
allowable restrictions. See "Production--Hugoton Field."
West Panhandle Field
--------------------
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 579 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. A recent 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, 1994, Mesa's West Panhandle properties represented
approximately 31% of Mesa's equivalent proved reserves, and approximately
33% of the present value of estimated future net cash flows before income
taxes, determined in accordance with Commission guidelines. Production from
the West Panhandle properties accounted for approximately 36%, 40%, and 39%
of Mesa's oil and gas revenues for the years ended December 31, 1994, 1993,
and 1992, 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 40% 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 over 11 MBbls of NGLs at its Fain
Plant from an inlet gas volume of 120 MMcf.
In the last four years Mesa has deepened, redrilled, or reworked 350
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 anticipates development of the
reserves over the next two to three years, in anticipation of its
contractual right to increase its share of West Panhandle production in 1997
(see -- "Production--West Panhandle Production").
Gulf Coast
----------
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 410 Bcfe (net to Mesa's interest). Mesa currently owns
interests in 45 blocks in the Gulf of Mexico. As of December 31, 1994,
these properties had an estimated 39 Bcfe of remaining proved reserves. In
addition, Mesa has over 100,000 miles of two-dimensional ("2-D") seismic
data and about 300 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 four years, Mesa has evaluated a number of its offshore
producing properties utilizing well information, 2-D seismic and production
data, combined with new 3-D seismic surveys to identify further development
and exploration potential. Mesa currently has nine 3-D seismic surveys
under analysis. New well locations were identified on nine producing leases
in 1994 and four exploratory blocks were acquired as a result of
interpreting 3-D seismic data surveys. In 1994 Mesa drilled four successful
wells in one producing field based on 3-D seismic data. Mesa intends to
continue its evaluation and identification of additional prospects for
drilling in 1995, depending on the success of its initial 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
-----
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.
Reserves
--------
The following table summarizes the estimated proved reserves and
estimated future cash flows associated with Mesa's oil and gas properties as
of December 31, 1994, estimated in accordance with Commission guidelines by
Mesa s engineers (dollar amounts in thousands):
Proved reserves:
Natural gas (MMcf)................................... 1,303,187
Natural gas liquids, oil and condensate (MBbls)...... 89,428
Future cash flows:
Future cash inflows.................................. $3,513,282
Operating costs...................................... (876,450)
Production and ad valorem taxes...................... (315,555)
Development and abandonment costs.................... (95,441)
Future income taxes.................................. (211,076)
----------
Future net cash flows........................... $2,014,760
==========
Present value of future net cash flows discounted
at 10% ("Present Value") after income taxes ............. $ 934,182
==========
Present Value before income taxes......................... $ 988,325
==========
The following table summarizes estimated proved reserves as of December
31, 1994, by major areas of operation:
Natural Natural Gas
Gas NGLs Oil Equivalents
--------- -------- ------- -----------
(MMcf) (MBbls) (MBbls) (MMcfe)
Hugoton......................... 950,684 40,108 -- 1,191,332
West Panhandle.................. 296,415 44,218 2,104 574,347
Other........................... 56,088 71 2,927 74,076
--------- ------ ----- ---------
Total....................... 1,303,187 84,397 5,031 1,839,755
========= ====== ===== =========
The proved reserve estimates set forth above were prepared by Mesa's
engineers. In previous years the proved reserve estimates reported by Mesa
for its Hugoton and West Panhandle properties (approximately 96% of total
proved reserves) were prepared by an independent petroleum engineering firm.
Mesa's internal estimates of proved reserves for the Hugoton and West
Panhandle properties in such years were greater than the estimates prepared
by the independent petroleum engineers. In the Hugoton field, the primary
difference reflects increased reserves for properties on which Mesa has
drilled 381 infill wells since 1987, resulting from Mesa's 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 the estimates of proved undeveloped reserves.
Mesa's proved reserve estimates as of December 31, 1994, for the Hugoton and
West Panhandle fields are approximately 241 Bcfe greater than the reserves
reported at December 31, 1993, adjusted for 1994 production, for the same
properties. Mesa operates the producing wells and the natural gas
processing plants on each of these properties and, based on its knowledge of
the properties, believes that its proved reserve estimates are more
reflective of future production than the estimates prepared by independent
petroleum engineers in previous years.
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 necessarily 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 results. 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 1994, Mesa filed Form EIA-23, which included reserve estimates
as of December 31, 1993, 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 five percent 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, 1994,
are included under "Supplemental Financial Data" in the consolidated
financial statements of the Company located elsewhere in this Form 10-K.
Production
----------
Mesa's Hugoton and West Panhandle fields are both mature reservoirs
that are substantially developed and have long-life production profiles.
Assuming the continuation of existing economic and operating conditions
(including the Hugoton field regulatory changes discussed below), Mesa
expects to be able to maintain annual productive capacity from its existing
properties in these two fields through the end of this decade that
approximates such properties' 1994 equivalent production.
Natural gas production is subject to numerous state and federal laws
and Federal Energy Regulation Commission (the "FERC") regulations.
Certain factors affecting production in Mesa's various fields are
discussed in greater detail below.
Hugoton Field
-------------
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 6,200 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 1994 was 613 Bcf of wellhead gas.
On February 2, 1994, the KCC issued an order, effective as of April 1,
1994, establishing new field rules which modified the formulas used to
allocate allowables among wells in the 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, which resulted in an increase to Mesa in assignable
allowables for 1994. The new field rules also allow Hugoton producers to
make up pre-1994 cancelled underages over a 10-year period. Mesa's share of
the allowables from the field increased from approximately 10% in 1993 to
14% in 1994 as a result of the new field rules.
Mesa's net Hugoton field production increased to approximately 73 Bcfe
in 1994 compared with 57 Bcfe in 1993 as a result of the new Hugoton field
rules, the increased yield of NGLs from the Satanta Plant, and certain other
factors. Assuming continuation of existing economic, operating, and
regulatory conditions, Mesa expects its existing Hugoton properties to be
able to produce an average of 74 Bcfe per year through the year 2000.
Excluding reserve acquisitions, Mesa has invested over $125 million in
capital expenditures in its Hugoton properties since 1986 to drill 381
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's entitled wet gas production
was 35 Bcf for 1993 and 32 Bcf for 1994. Mesa will be entitled to 32 Bcf of
wet production per year for 1995 and 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 market and sell 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 37 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, 1994, Mesa had produced less than its 77% entitlement since
January 1, 1991, and a long-term gas balancing receivable of $39.9 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.
Natural Gas Processing
----------------------
Mesa processes its natural gas production for the extraction of NGLs
and helium to enhance the market value of the gas stream. Mesa has recently
made substantial capital investments to enhance its natural gas processing
and helium extraction capabilities in the Hugoton and West Panhandle fields.
Mesa owns and operates its own processing facilities so that it can (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, and
(ii) control the quality of the residue gas stream, permitting it to market
gas directly to pipelines for delivery to end users. In addition, 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
------------------------------------
Historically, approximately one-half of Mesa's Hugoton production was
processed through Mesa's Ulysses natural gas processing plant for the
extraction of NGLs. In the third quarter of 1993 Mesa started processing at
the Satanta Plant. The Satanta Plant has the capacity to process 250 MMcf
of natural gas per day, and enables Mesa to extract natural gas liquids from
substantially all of the gas produced from its Hugoton field properties.
The Satanta Plant also has the ability to extract helium from the gas
stream. In 1994 the Satanta Plant averaged 143 MMcf per day of inlet gas
(net to Mesa's interests) and produced a daily average of 9.4 MBbls of NGLs,
473 Mcf of crude helium, and 107 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 1994 the Fain Plant averaged 75 MMcf per day of inlet gas (net to
Mesa's interests), and produced a daily average of 8.4 MBbls of NGLs, 102
Mcf of crude helium, and 65 MMcf of residue natural gas.
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
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.
The following tables show Mesa's natural gas, natural gas liquids, and
oil and condensate production and prices by area for the past three years:
Production 1994 1993 1992
---------- ------ ------ ------
Natural gas (MMcf)
Hugoton.................................... 51,986 47,476 48,592
West Panhandle............................. 22,983 23,786 26,380
Other...................................... 7,370 8,558 14,555
------ ------ ------
Total................................. 82,339 79,820 89,527
====== ====== ======
Natural gas liquids (MBbls)
Hugoton.................................... 3,430 1,481 898
West Panhandle............................. 3,423 3,480 3,794
Other...................................... 58 89 148
------ ------ ------
Total................................. 6,911 5,050 4,840
====== ====== ======
Oil and condensate (MBbls)
Hugoton.................................... -- 104 249
West Panhandle............................. 164 153 --
Other...................................... 382 481 735
------ ------ ------
Total................................. 546 738 984
====== ====== ======
Prices
------
Weighted average sales price:
Natural gas (per Mcf)
Hugoton............................... $ 1.57 $ 1.78 $ 1.56
West Panhandle........................ 1.80 1.72 1.80
Other................................. 1.81 2.04 1.74
------ ------ ------
Average.......................... $ 1.67 $ 1.79 $ 1.72
====== ====== ======
Natural gas liquids (per Bbl)
Hugoton............................... $10.03 $12.35 $13.98
West Panhandle........................ 11.06 12.04 11.92
Other................................. 11.40 12.55 12.50
------ ------ ------
Average.......................... $10.55 $12.14 $12.32
====== ====== ======
Oil and condensate (per Bbl)
Hugoton............................... $ -- $18.21 $18.80
West Panhandle........................ 13.38 15.04 --
Other................................. 15.09 16.79 18.88
------ ------ ------
Average.......................... $14.58 $16.63 $18.86
====== ====== ======
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 thousand cubic feet of
natural gas equivalent ["Mcfe"] data):
1994 1993 1992
---------------- ---------------- ----------------
Total Per Mcfe Total Per Mcfe Total Per Mcfe
------- -------- ------- -------- ------- --------
Hugoton......... $30,054 $ .41 $25,406 $ .45 $22,353 $ .40
West Panhandle.. 31,446 .71 34,478 .76 27,794 .57
Other........... 12,461 1.24 12,267 1.02 12,343 .62
------- ------- -------
Total/
Average.. $73,961 $ .58 $72,151 $ .63 $62,490 $ .50
======= ======= =======
Hugoton Sales Contracts
-----------------------
A substantial portion of Mesa's Hugoton field production is subject to
two gas purchase contracts with Western Resources, Inc. ("WRI"). The WRI
contracts expire in May 1995. Effective February 1, 1994, WRI assigned a
portion of one contract to Missouri Gas Energy ("MGE"). Under the
contracts, WRI and MGE had the right to purchase 37.5 Bcf in 1994 and may
purchase an aggregate of 19.9 Bcf during the first five months of 1995.
These volumes are subject to minimum seasonal purchase volumes. WRI and MGE
pay market prices for volumes purchased as determined monthly based on a
price index published by a third party. In 1994 WRI and MGE together
purchased 29.1 Bcf of gas from Mesa at an average price of $1.56 per Mcf
under these contracts.
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. Any Hugoton production not taken
under the applicable contracts by WRI and MGE is released for sale to other
parties. Mesa markets such production to marketers, pipelines, local
distribution companies, and end-users, generally under short-term contracts
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 10 Bcf per year of residue natural gas is sold to a gas
utility that serves residential, commercial, and industrial customers in
Amarillo, Texas, under the terms of a long-term agreement dated January 2,
1993, which supercedes the original contract that was in effect since 1949.
The agreement contains a pricing formula for the five-year period from 1993
through 1997. Beginning in 1993, 70% of the volumes sold to the gas utility
under the contract were sold at fixed prices of $2.71 in 1993 and $2.85 in
1994. Such prices escalate at 5% per annum in 1995 and then at 7-1/2% per
annum in 1996 and 1997. The other 30% of volumes sold under this contract
are priced at a regional market index based on spot prices plus $.10 per
Mcf. 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 1994 was $2.55 per Mcf.
Mesa's principal industrial customer for West Panhandle field gas is 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 the power
generation facility. The contract provides for minimum annual volumes of
8.4 Bcf in 1994 and 8.4 Bcf in 1995 at fixed prices per million British
Thermal Units ("MMBtu") of $1.71 and $1.79 for the respective years. Mesa
has periodically made sales to the pipeline company in excess of the minimum
volumes specified in the contract at market prices. In 1994 Mesa sold
approximately 10.5 Bcf of residue natural gas to the pipeline for an average
price of $1.56 per Mcf.
Other industrial customers purchase natural gas from Mesa under short-
to intermediate-term contracts. These sales totaled approximately 3.6 Bcf
in 1994. Mesa intends to continue to seek new customers for additional
sales of West Panhandle field natural gas production.
Prior to 1993, Mesa's right to market natural gas produced from the
West Panhandle field was limited to 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. Through 1995, a substantial
portion of Mesa's West Panhandle field production is under contract to
customers in Amarillo as described above. Mesa expects to continue to focus
its marketing efforts in the Amarillo area. 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.
NGL and Helium 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.
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.
Drilling Activities
-------------------
The following table shows the results of Mesa's drilling activities for
the last five years:
1994 1993 1992 1991 1990
----------- ----------- ----------- ----------- -----------
Gross Net Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Exploratory
Wells:
Productive.... -- -- -- -- 5 4.1 6 4.7 -- --
Dry........... -- -- 1 1.0 1 .4 1 .2 5 3.1
Development
Wells:
Productive.... 31 24.5 43 29.1 22 16.5 26 10.9 146 120.8
Dry........... 1 .8 -- -- -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total....... 32 25.3 44 30.1 28 21.0 33 15.8 151 123.9
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
At December 31, 1994, the Company was participating in the drilling of
one gross (.77 net) well in the West Panhandle field.
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, 1994, is set
forth in the table below.
Producing Producing Undeveloped
Acreage Wells Acreage
---------------- -------------- --------------
Gross Net Gross Net Gross Net
------- ------- ----- ------- ------ ------
Onshore U.S.:
Kansas................ 258,979 231,360 1,390 991.4 5,280 5,280
Texas................. 241,354 185,655 598 448.5 2,030 1,574
Wyoming............... 11,715 4,603 2 -- 16,503 10,941
North Dakota.......... 4,661 3,467 23 6.0 3,932 2,572
Other................. 2,826 2,139 13 1.2 24,007 14,217
------- ------- ----- ------- ------ ------
Total Onshore.... 519,535 427,224 2,026 1,447.1 51,752 34,584
------- ------- ----- ------- ------ ------
Offshore U.S.:
Louisiana............. 87,025 45,710 189 41.6 16,831 15,894
Texas................. 73,808 16,544 58 9.8 17,280 17,280
------- ------- ----- ------- ------ ------
Total Offshore... 160,833 62,254 247 51.4 34,111 33,174
------- ------- ----- ------- ------ ------
Grand Total................ 680,368 489,478 2,273 1,498.5 85,863 67,758
======= ======= ===== ======= ====== ======
Mesa has interests in 2,085 gross (1,471.2 net) producing gas wells and
188 gross (27.3 net) producing oil wells in the United States. Mesa also
owns approximately 86,100 net acres of producing minerals and 40,652 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. In recent years Mesa has engaged in
developing its natural gas vehicle ("NGV") business and is a leader in the
development of natural gas conversion equipment for automobiles and natural
gas fueling stations for fleet vehicles. Mesa believes that the 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 vehicles to operate on natural gas. Mesa's present strategies are
(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.
Conversion Equipment
--------------------
Since 1991 Mesa has invested approximately $17 million in its indirect,
wholly owned subsidiary, MESA Environmental Ventures Co. ("Mesa
Environmental"), to fund its acquisitions, capital investments, and
overhead. 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. Mesa Environmental is a start-up business in a newly
developing industry, and the ultimate capital investment required to ensure
its viability is uncertain. In addition, Mesa cannot predict when, or if,
Mesa Environmental's operations will begin to earn a profit.
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. In December 1994 Mesa opened a natural gas
fueling station near the Phoenix, Arizona, airport and expects to open two
stations in Los Angeles during 1995.
Organizational Structure
------------------------
In order to simplify its organizational and capital structure, Mesa
effected a series of mergers in early 1994 which resulted in the conversion
of each of Mesa's subsidiary partnerships, other than Hugoton Capital
Limited Partnership ("HCLP"), into corporate form. Pursuant to these
mergers, Mesa Operating Limited Partnership was merged into Mesa Operating
Co. ("MOC"), Mesa Midcontinent Limited Partnership, and Mesa Holding Limited
Partnership were merged into Mesa Holding Co. ("MHC"), and Mesa
Environmental Ventures Limited Partnership was merged into Mesa
Environmental. Pursuant to certain of these mergers, all of the general
partner interests in Mesa's subsidiary partnerships held directly or
indirectly by Boone Pickens were converted into approximately 1.7 million
shares of common stock of Mesa, as contemplated by a conversion agreement
dated December 31, 1991, between Mesa and Mr. Pickens. As a result, all of
Mesa's subsidiaries are now wholly owned by Mesa. Unless the context
otherwise requires, the terms "MOC," "MHC," and "Mesa Environmental" include
their respective predecessors. Mesa's significant subsidiaries are
described below.
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, as well as helium and certain NGLs produced from 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, compression and gas processing facilities, but excluding
certain NGL and helium reserves) 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, Hugoton Management Co. ("HMC"), is a wholly owned subsidiary of the
Company. 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.
MHC
---
MHC principally conducts various investment activities. At December
31, 1994, MHC held approximately $71 million of cash and securities, 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.
Mesa is currently pursuing a sale of its interests in the Hugoton field
and intends to use the proceeds to retire debt. See "Recent Events."
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. Mesa's major gas sales contracts (see "-- Sales and Marketing")
allow production not sold to the contract purchaser to be sold to other
purchasers in the spot market. 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.
Natural Gas Regulations
-----------------------
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 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,
requires each pipeline company, among other things, to "unbundle" its
traditional wholesale 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 in direct competition with all other
sellers pursuant to private contracts; however, pipeline companies and their
affiliates were not required to remain "merchants" of gas, and several 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. In addition, and following the conclusion of individual
restructuring proceedings for each interstate pipeline pursuant to Order
636, the FERC has approved, with modifications, all of the restructuring
plans, and has generally accepted rate filings implementing Order 636 on
every interstate pipeline as of the end of 1994. Order 636, as well as the
FERC orders approving the individual pipeline rate filings implementing
Order 636, are the subject of numerous appeals to the United States Courts
of Appeals. Mesa cannot predict whether the latest orders will be affirmed
on appeal or what the effects will be on its business.
State and Other Regulation
--------------------------
All of the jurisdictions in which Mesa owns producing oil and gas
properties have statutory provisions regulating the production and sale of
crude oil and natural gas. The regulations often require permits for the
drilling of wells, but extend also to the spacing of wells, the prevention
of waste of oil and gas resources, the rate of production, prevention and
clean-up of pollution, and other matters. In Texas, the Railroad Commission
regulates the amount of oil and gas produced within the state by assigning
to each well or proration unit an allowable rate of production. Certain
other jurisdictions, including Kansas, impose similar restrictions. See "--
Production" for a discussion of recent changes to Mesa's allowables in the
Hugoton field.
Certain producing states, including Texas, Louisiana, Oklahoma, and
Kansas, have in recent years adopted or considered adopting measures that
alter the methods previously used to prorate gas production from wells
located in these states. For example, the recently modified Texas rules
provide for reliance on information filed monthly by well operators, in
addition to historical production data for the well during comparable past
periods, to arrive at an allowable. This is in contrast to historic
reliance on forecasts of upcoming takes filed monthly by purchasers of
natural gas in formulating allowables, a procedure which resulted in
substantial excess allowables over volumes actually produced. Mesa cannot
predict what ultimate effect any of these recently adopted prorationing
regulations will have on its production of gas, or whether other states will
adopt similar or other gas prorationing procedures.
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 "gathering." Mesa transports its own gas through
these facilities. Mesa also has gas that is transported through gathering
facilities owned by others, including interstate pipelines. 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
with existing customers. Several petitions for rehearing 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 that an interstate pipeline must not only seek authority
under Section 7(b) of the NGA to abandon certificated facilities, but also
must file for 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 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 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 as the pipeline restructuring under Order 636 continues. For
example, Oklahoma enacted a prohibition against discriminatory gathering
rates, and certain Texas regulatory officials have expressed interest in
evaluating similar rules in Texas.
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
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 has been
transferred to the United States District Court in Washington, D.C. While
the Washington litigation is pending, on February 13, 1995, 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. 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. Because the Washington litigation remains pending and the
Kentucky decision may be 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, if anything, 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
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. 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.
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
response 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 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 1986 Mesa, through MOC, acquired rights in certain properties
located in the West Panhandle field of Texas when it acquired the assets of
Pioneer Corporation. In particular, Mesa acquired an interest in gas
production from an oil and gas lease (the "Gas Lease") dated April 30, 1955,
between R. B. Masterson, et al., as lessor, and CIG, as lessee.
In February 1992 the current lessors of the Gas Lease sued CIG in
Federal District Court in Amarillo, Texas, claiming that CIG had underpaid
royalties due under the Gas Lease. The plaintiffs alleged that the
underpayment was the result of CIG's using 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 complaint did not specify the damages
sought and appeared to relate only to royalties for periods after October 1,
1989. The plaintiffs also sought a declaration by the court as to the
proper price to be used for calculating future royalties. In August 1992
CIG filed a third party complaint against Mesa for any such royalty
underpayments which may be allocable to Mesa's interest in the Gas Lease.
On December 22, 1992, the plaintiffs filed a Second Amended Complaint,
including both CIG and Mesa as defendants, again alleging that the "favored
nations" clause resulted in underpayments of royalties, but for the first
time alleging that the underpayments amounted to approximately $250 million
(including interest) and covered the period July 1, 1967, to present. Mesa
was subsequently dismissed by the plaintiffs for procedural reasons, but
remains in the case as a defendant in CIG's third party complaint.
The plaintiffs later filed court papers alleging royalty underpayments
of over $500 million (including interest at 10%) covering the period from
July 1, 1967, to the present. In addition, the plaintiffs seek exemplary
damages. Management believes that Mesa has several defenses to plaintiffs'
claims, including: (i) that the royalties for all periods were properly
computed and paid; (ii) that plaintiffs' claims with respect to all periods
prior to October 1, 1989, (which account for approximately $400 million of
the claims) were explicitly released by a 1988 settlement agreement among
plaintiffs, CIG and Mesa and are further barred by the statute of
limitations; and (iv) from October 1, 1989, to the present, the "favored
nations" provision was suspended because the plaintiffs had agreed to be
paid certain other royalty rates in lieu of the "favored nations" rate.
In March 1995 the court ruled (1) that all claims for royalty
underpayments for the periods prior to October 1, 1989, were released by the
plaintiffs in the 1988 settlement agreement, (2) that plaintiffs are not
entitled to exemplary damages, and (3) that the "favored nations" clause in
the 1967 Gas Lease Amendment has not been eliminated or suspended by the "in
lieu of" provision to the 1988 royalty agreements. The court has also made
certain other rulings adverse to the defendants covering certain other
defenses. The Company and CIG have filed stipulations with the court
whereby the Company would be liable for between 50% and 60%, depending upon
the time period covered, of any adverse judgment against CIG for post-
February 1988 underpayment of royalties. The court's rulings have
eliminated approximately $400 million of the plaintiff's original $500
million of claims but have also reduced a number of CIG's and the Company's
defenses.
The trial began March 22, 1995.
Preference Unitholders
----------------------
Mesa and Mr. Pickens are defendants in lawsuits filed in early 1992
related to the conversion of the Partnership into MESA Inc., styled Odmark,
et al. v. Mesa Limited Partnership, et al., Gerardo, et al. v. Mesa Limited
Partnership, et al., and McBride Trust, et al. v. Mesa Limited Partnership,
et al., pending in the U.S. District Court for the Northern District of
Texas--Dallas Division. The first two lawsuits were consolidated and
certified as a class action and the third is an individual action by or on
behalf of former holders of preference units of the Partnership. All three
allege substantially the same claims under the federal securities laws and
common law. Plaintiffs allege, among other things, that (i) the proxy
materials delivered to unitholders in connection with the conversion of the
Partnership into MESA Inc. (the "Corporate Conversion") contained material
misstatements and omissions, (ii) the general partners of the Partnership
breached fiduciary duties to the preference unitholders in structuring the
transaction and allocating the common stock of Mesa, and (iii) the Corporate
Conversion was implemented in breach of the partnership agreement of the
Partnership because the defendant allegedly did not obtain the requisite
opinion of independent counsel regarding the tax effects of the transaction.
Mesa and the other defendants have denied the allegations and believe they
are without merit. Plaintiffs seek a declaration declaring the Corporate
Conversion void and rescinding it, an order requiring payment to the former
preference unitholders of $164 million in respect of the preferential
distribution rights of their units, unspecified compensatory and punitive
damages and other relief. Mesa and the other defendants have denied the
plaintiffs' allegations.
On August 12, 1994, the court entered an order denying plaintiff's
motion for a summary judgment and granted Mesa's motion for a summary
judgment. A final judgment was entered dismissing the case. A notice of
appeal was filed August 19, 1994, by plaintiffs. Oral arguments in the case
have been scheduled before the Fifth Circuit Court of Appeals in May 1995.
Other
-----
See "Item 1. Business-Environmental Matters" for a discussion of legal
proceedings relating to environmental matters that are pending or known to
be contemplated by governmental authorities to which Mesa or a subsidiary is
a party.
Mesa is also a defendant in various other lawsuits and legal
proceedings and, as the successor entity to the Partnership and Original
Mesa, has assumed certain other obligations from those entities. Mesa does
not expect the resolution of any of these other matters to have a material
adverse effect on its results of operations or financial position.
Item 4. Submission of Matters to a Vote of Security Holders
============================================================
None.
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
------ ------
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
1993:
First Quarter........................................ $6-1/4 $4
Second Quarter....................................... 7 3-1/2
Third Quarter........................................ 8-1/8 6
Fourth Quarter....................................... 7-7/8 4-7/8
----------
* Mesa's common stock trades on the New York Stock Exchange under the
symbol MXP. At December 31, 1994, 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 22, 1994, there were 20,284 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.
As of or for the Years Ended December 31
----------------------------------------------------------
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
(in thousands, except per share data)
Revenues........ $ 228,737 $ 222,204 $ 237,112 $ 249,546 $ 329,597
========== ========== ========== ========== ==========
Operating income $ 28,683 $ 22,012 $ 26,221 $ 34,128 $ 43,389
========== ========== ========== ========== ==========
Net loss........ $ (83,353) $(102,448) $ (89,232) $ (79,163) $ (200,276)
========== ========== ========== ========== ==========
Net loss per
common share... $ (1.42) $ (2.61) $ (2.31) $ (2.05) $ (5.19)
========== ========== ========== ========== ==========
Dividends per
share.......... $ -- $ -- $ -- $ -- $ .85
========== ========== ========== ========== ==========
Total assets.... $1,483,959 $1,533,382 $1,676,523 $1,832,816 $2,168,002
========== ========== ========== ========== ==========
Long-term debt,
including
current
maturities..... $1,223,293 $1,241,294 $1,286,155 $1,310,705 $1,521,740
========== ========== ========== ========== ==========
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
========================================================================
Results of Operations
---------------------
The following table presents a summary of the results of operations of
Mesa for the years indicated:
Years Ended December 31
-------------------------------
1994 1993 1992
--------- --------- ---------
(in thousands)
Revenues.............................. $ 228,737 $ 222,204 $ 237,112
Operating and administrative costs.... (107,767) (100,093) (96,958)
Depreciation, depletion and
amortization........................ (92,287) (100,099) (113,933)
--------- --------- ---------
Operating income...................... 28,683 22,012 26,221
Interest expense, net of
interest income..................... (131,300) (131,298) (129,888)
Other................................. 19,264 6,838 14,435
--------- --------- ---------
Net loss.............................. $ (83,353) $(102,448) $ (89,232)
========= ========= =========
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
----------------------------
1994 1993 1992
-------- -------- --------
Revenues (in thousands):
Natural gas......................... $139,580 $141,798 $157,672
Natural gas liquids................. 72,771 61,427 59,669
Oil and condensate.................. 7,877 12,428 18,701
-------- -------- --------
Total.......................... $220,228 $215,653 $236,042
======== ======== ========
Natural Gas Production (MMcf):
Hugoton............................. 51,986 47,476 48,592
West Panhandle...................... 22,983 23,786 26,380
Other............................... 7,370 8,558 14,555
-------- -------- --------
Total.......................... 82,339 79,820 89,527
======== ======== ========
Natural Gas Liquids Production (MBbls):
Hugoton............................. 3,430 1,481 898
West Panhandle...................... 3,423 3,480 3,794
Other............................... 58 89 148
-------- -------- --------
Total.......................... 6,911 5,050 4,840
======== ======== ========
Oil and Condensate Production (MBbls):
Hugoton............................. -- 104 249
West Panhandle...................... 164 153 --
Other............................... 382 481 735
-------- -------- --------
Total.......................... 546 738 984
======== ======== ========
Average Prices:
Natural gas (per Mcf)............... $ 1.67 $ 1.79 $ 1.72
Natural gas liquids (per Bbl)....... $ 10.55 $ 12.14 $ 12.32
Oil and condensate (per Bbl)........ $ 14.58 $ 16.63 $ 18.86
The increase in total revenues from sales of natural gas, natural gas
liquids and oil and condensate from 1993 to 1994 is primarily due to
increased natural gas and natural gas liquids production in 1994, partially
offset by the decrease in prices from 1993 to 1994. Total revenues
decreased from 1992 to 1993 primarily due to lower natural gas production in
1993.
Natural gas revenues decreased from 1992 to 1993 and from 1993 to 1994.
Total natural gas production increased by 3% from 1993 to 1994 substantially
due to higher allowables in the Hugoton field partially offset by slightly
lower West Panhandle and Gulf Coast production. Average natural gas prices
in 1994 were 7% lower than 1993 average prices due to lower market prices.
(See "Natural Gas Prices" below.) Natural gas production in 1993 decreased
due primarily to lower West Panhandle and Gulf Coast production.
Natural gas liquids production increased by approximately 43% from 1992
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 plant which could process
up to 160 MMcf per day.
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
--------------------------
1994 1993 1992
------ ------ ------
Natural Gas Production (MMcf):
Sold under fixed price contracts.......... 13,935 19,467 19,051
Sold at market prices..................... 68,404 60,353 70,476
------ ------ ------
Total production..................... 82,339 79,820 89,527
====== ====== ======
Percent sold at market prices............. 83% 76% 79%
====== ====== ======
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 traded on the New York Mercantile
Exchange. The following table shows the effects of Mesa s fixed price
contracts and hedging activities on its natural gas prices:
Years Ended December 31
--------------------------
1994 1993 1992
------ ------ ------
Average Natural Gas Prices (per Mcf):
Fixed price contracts..................... $ 2.16 $ 1.94 $ 2.06
Market prices received.................... 1.55 1.75 1.55
Hedge gains (losses)...................... .01 (.01) .08
------ ------ ------
Total market prices.................. 1.56 1.74 1.63
------ ------ ------
Total average prices...................... $ 1.67 $ 1.79 $ 1.72
====== ====== ======
Gains and losses from hedging activities are included in natural gas
revenues when the hedged production occurs. Mesa recognized gains from
hedging activities of $895,000 in 1994, losses of $324,000 in 1993, and
gains of $5.6 million in 1992. Mesa has hedged a significant portion of its
market-sensitive production for the first three quarters of 1995. As of
February 21, 1995, Mesa had closed its hedge positions which were open as of
December 31, 1994, and realized gains of approximately $12 million which
will be recognized as natural gas revenues as the hedged production occurs.
In 1995 Mesa has entered into additional hedge positions related to 1995
production. The results of such positions may increase or decrease Mesa s
natural gas revenues.
Costs and Expenses
------------------
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 in the Hugoton field
and higher Hugoton field production. Lease operating expenses, however,
have decreased on a unit of production basis due to increased production.
Exploration charges in 1994 are greater than such charges in 1993,
reflecting Mesa s increased exploration activities in the Gulf of Mexico.
The increased 1994 costs result primarily from the purchase of 3-D seismic
data. General and administrative 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 (see Note 9 to the consolidated
financial statements of the Company located elsewhere in this Form 10-K).
Depreciation, depletion and amortization ("DD&A") expense was lower in 1994
compared to 1993. DD&A expense, which is calculated on a unit-of-production
basis, reflects the 1994 reserve increases in the Hugoton and West Panhandle
fields and reserve discoveries in the Gulf Coast. (See "Supplemental
Financial Data" to the consolidated financial statements of the Company
located elsewhere in this Form 10-K.)
Mesa's aggregate costs and expenses declined by approximately 5% from
1992 to 1993 primarily due to decreases in exploration and DD&A expenses
partially offset by an increase in lease operating expenses. Lease
operating expenses were greater in 1993 than in 1992 due to increased
production costs in the West Panhandle field. The increase was primarily a
result of increased gathering-related fees paid to CIG as operator of the
gathering system in the West Panhandle field. Exploration charges were
substantially lower in 1993 than in 1992. The 1992 expense included
exploratory dry holes in the Gulf Coast area. DD&A expense was lower in
1993 than in 1992 due primarily to lower production in 1993.
Other Income (Expense)
----------------------
Interest expense in 1994 was not materially different from 1993 and
1992 as average aggregate debt outstanding did not materially change.
Interest income increased from $10.7 million in 1993 to $13.5 million
in 1994 as a result of higher average cash balances and higher average
interest rates earned on these cash balances in 1994.
Results of operations for the years 1994, 1993, and 1992 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
-------------------------
1994 1993 1992
------- ------- -------
Gains from futures and securities
investments............................... $ 6,698 $ 3,954 $ 7,808
Gains from collections from Bicoastal
Corporation............................... 16,577 18,450 --
Gains on dispositions of oil
and gas properties........................ -- 9,600 12,250
Litigation settlement....................... -- (42,750) --
Gain from adjustment of contingency reserve. -- 24,000 --
Expense of debt exchange transaction........ -- (9,651) --
Expense of Corporate Conversion............. -- -- (2,144)
Other....................................... (4,011) 3,235 (3,479)
------- ------- -------
$19,264 $ 6,838 $14,435
======= ======= =======
The gains from futures and securities investments relate to Mesa's
investments in marketable securities and futures contracts that are not
accounted for as hedges of future production. The gains from collection of
interest from Bicoastal Corporation relates 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 1994, 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 and the 1992 sale of Mesa s interests in Canada for
approximately $26 million and $12 million, respectively.
The litigation settlement charge relates to Mesa's early 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 and used the proceeds to pay 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. The Corporate
Conversion expense relates to costs associated with the year-end 1991
conversion of the Partnership to MESA Inc.
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 1994, 1993, and 1992, Mesa produced and sold
69%, 74% and 61%, 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.
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
---------------------------
1994 1993 1992
------- ------- -------
Revenues accrued.......................... $ 8,662 $ 5,145 $23,270
Costs and expenses accrued................ (3,075) (1,059) (6,073)
Depreciation, depletion and amortization.. (3,713) (1,244) (10,764)
------- ------- -------
Total................................ $ 1,874 $ 2,842 $ 6,433
======= ======= =======
Production Accrued:
Natural gas (MMcf)................... 2,386 740 6,772
Natural gas liquids (MBbls).......... 355 106 972
At December 31, 1994, the long-term gas balancing receivable from CIG,
net of accrued costs, relating to the PAA was $39.9 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.
Mesa entered into an amendment to the PAA in 1993 which allows Mesa,
for the first time, to market its residue gas production outside of
Amarillo, Texas, but which also limits Mesa's production to 35 Bcf of
unprocessed gas in 1993 and 32 Bcf annually in 1994 through 1996. Mesa
produced 31 Bcf and 35 Bcf in 1994 and 1993, respectively.
Capital Resources and Liquidity
-------------------------------
Mesa is primarily in the business of exploring for, developing,
producing, and processing oil and natural gas. At December 31, 1994, Mesa
owned over 1.8 Tcfe of proved equivalent natural gas reserves. Mesa is also
highly leveraged with over $1.2 billion of long-term debt, including current
maturities. HCLP, an indirect subsidiary of Mesa, is the obligor on
approximately 44% of Mesa's consolidated long-term debt. The HCLP debt is
secured by Mesa s Hugoton field properties, which represent approximately
65% of Mesa s oil and gas reserves. The assets and cash flows of HCLP that
are subject to the mortgage securing the HCLP debt are dedicated to service
HCLP s debt and are not available to pay creditors of Mesa or its
subsidiaries other than HCLP. However, any "excess cash," as defined in the
HCLP debt agreements, may be distributed by HCLP to its equity owners, MOC,
MHC and HMC, which are direct subsidiaries of Mesa, to be used for general
corporate purposes. MOC owns all of Mesa s interest in the West Panhandle
field of Texas and the Gulf Coast and the Rocky Mountain areas. At December
31, 1994, MOC owned an approximate 99% limited partnership interest in HCLP.
The Company and MOC are liable for all of the Company's consolidated long-
term debt other than the HCLP debt. MHC owns cash and securities, an
approximate 1% limited partnership interest in HCLP and 100% of Mesa
Environmental, a company established to compete in the natural gas vehicle
market. HMC owns the general partner interest in HCLP.
Approximately 88% of Mesa's non-HCLP debt does not require cash
interest payments until December 31, 1995. Beginning on this date, and
until the debt is repaid, Mesa is required to make semiannual interest
payments in cash at a 12-3/4% annual rate. If Mesa had been required to
make cash interest payments on this debt in 1994, the interest payments
would have totaled $70.6 million. These additional interest payments would
have exceeded Mesa's 1994 consolidated cash flows from operating activities,
which totaled $48.6 million. Mesa also has significant principal payments
due in 1996 and 1998.
Following is a discussion of Mesa's debt, resources and alternatives:
Long-term Debt
--------------
The following table provides additional information as to Mesa's long-
term debt at December 31, 1994, (in thousands):
Obligors
-----------------
Company
and MOC HCLP Total
-------- -------- ----------
Debt:
HCLP Secured Notes(a)............... $ -- $520,180 $ 520,180
Credit Agreement(b)................. 71,131 -- 71,131
12-3/4% secured discount notes(c)(e) 581,942 -- 581,942
12-3/4% unsecured discount
notes(d)(e)....................... 37,345 -- 37,345
Other............................... 12,695 -- 12,695
-------- -------- ----------
703,113 520,180 1,223,293
Current maturities....................... (15,305) (15,232) (30,537)
-------- -------- ----------
Long-term debt........................... $687,808 $504,948 $1,192,756
======== ======== ==========
----------
(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 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, 1994, the Credit Agreement also supported letters of credit
totaling $11.4 million.
(c) These notes are due in June 1998 and are secured by second liens
on MOC's West Panhandle properties and a 76% limited partnership
interest in HCLP.
(d) These notes are unsecured and are due in June 1996.
(e) These secured and unsecured discount notes (together, the
"Discount Notes") do not require cash interest payments until
December 31, 1995, but the accreted value of such Discount Notes
increases at 12-3/4% per annum through June 30, 1995.
The following tables summarize Mesa's 1994 actual and 1995 through 1998
forecast cash requirements, assuming no changes in capital structure, for
interest, debt principal and capital expenditures (in thousands):
Actual Forecast
-------- -----------------------------------
1994 1995 1996 1997 1998
-------- -------- -------- -------- --------
HCLP:
Interest payments,
net(a)............... $ 46,815 $ 46,000 $ 45,900 $ 41,200 $ 37,800
Principal repayments... 21,420 15,200 32,300 35,800 37,000
Capital expenditures(b) 6,957 11,100 5,000 1,000 --
-------- -------- -------- -------- --------
$ 75,192 $ 72,300 $ 83,200 $ 78,000 $ 74,800
======== ======== ======== ======== ========
Other Mesa subsidiaries:
Interest payments,
net(a)............... $ 1,945 $ 47,500 $ 92,300 $ 96,900 $ 99,400
Principal repayments(c) 153,687 15,300 62,200 38,600 617,400
Capital
expenditures(b)(d)... 25,633 25,500 9,700 15,500 2,400
-------- -------- -------- -------- --------
$181,265 $ 88,300 $164,200 $151,000 $719,200
======== ======== ======== ======== ========
----------
(a) Cash interest payments, net of interest income. MOC is required
to begin making semiannual cash interest payments on the Discount
Notes on December 31, 1995.
(b) 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 include $10.7 million
of committed capital expenditures for 1995, which is included in
the amount set forth in the table. Mesa may incur capital
expenditures in addition to those reflected in the table.
(c) Includes approximately $93 million of principal repayments made in
1994 with proceeds from a $93 million equity offering completed in
the second quarter of 1994. Such principal was scheduled to
mature in 1996.
(d) Over the next two years, Mesa may spend an estimated $11 million
in exploratory capital contingent upon evaluation and identifi-
cation of additional prospects for drilling. These amounts are
not included in the above table.
The Credit Agreement contains restrictive covenants which require Mesa
to maintain a tangible adjusted equity, as defined, of at least $50 million
and available cash, as defined, of $32.5 million. At December 31, 1994,
tangible adjusted equity was $125 million and available cash was $105
million.
The indentures governing the Discount Notes restrict, among other
things, Mesa's ability to incur additional indebtedness, pay dividends,
acquire stock or make investments, loans and advances. The Credit Agreement
also restricts, among other things, Mesa's ability to incur additional
indebtedness, create liens, pay dividends, acquire stock or make
investments, loans and advances.
Company Resources
-----------------
The following table sets forth certain of Mesa s near-term resources as
of or for the year ended December 31, 1994, (in thousands):
Other
Subsidiaries
MOC HCLP Combined Total
-------- -------- ------------ --------
Cash and securities(a)......... $ 40,815 $ 49,638 $ 72,081 $162,534
Working capital................ 21,958 19,097 74,600 115,655
Restricted cash(b)............. -- 61,299 -- 61,299
Cash flows from
operating activities:
Oil and gas sales, net
of production and
administrative costs.... $ 37,768 $ 89,952 $ -- $127,720
Litigation settlement(c).. (42,750) -- -- (42,750)
Interest payments, net(d). (4,992) (46,815) 3,047 (48,760)
Other..................... (6,028) (2,689) 21,104 12,387
-------- -------- -------- --------
$(16,002) $ 40,448 $ 24,151 $ 48,597
======== ======== ======== ========
----------
(a) Included in working capital.
(b) Non-current asset in balance sheet.
(c) In March 1994 Mesa issued additional 12-3/4% secured discount
notes and used the proceeds of $42.8 million to settle the Unocal
litigation. See "Other Income (Expense)."
(d) Cash interest payments, net of interest income.
Mesa's cash flows from operating activities are substantially dependent
on the amount of oil and gas produced and the price received for such
production. Production and prices received from Mesa's properties, together
with available cash and securities balances, are expected, under Mesa's
current operating plan, to generate sufficient cash flow to meet Mesa's
required principal, interest and capital obligations through December 31,
1995.
Mesa s current financial forecasts indicate that Mesa will be unable to
fund its principal and interest obligations on MOC debt in 1996 with cash
flows from operating activities and available cash and securities balances.
To address this situation 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, and in the
first quarter of 1995 began an auction process to sell such properties.
(See "Hugoton Properties Sale" below.) Proceeds from such a sale would be
used to retire long-term debt. If Mesa does not sell its Hugoton
properties, it would attempt to strengthen its financial condition by other
means, including the sale of additional equity or refinancing of its long-
term debt. There can be no assurance that Mesa will sell its Hugoton
properties or that, in the absence of such a sale, Mesa will be able to
issue equity or refinance its debt.
Hugoton Properties Sale
-----------------------
In the first quarter of 1995 Mesa began an auction process to sell its
interests in the Hugoton field, including the Satanta Plant, by approaching
a select group of prospective buyers which have the financial means to
complete a purchase of Mesa s entire interest. Mesa hopes to complete a
sale by mid-1995.
Mesa intends to use proceeds from a sale to retire debt. Any sales
proceeds must first be applied against the outstanding balances related to
the HCLP Secured Notes, which are secured by the Hugoton properties. Such
balances include note principal, accrued interest and any premiums due,
including premiums for early retirement of the notes. As of December 31,
1994, such premiums for early retirement of the notes would have totaled
approximately $42 million. The actual premiums due in the event of a
redemption of the HCLP Secured Notes will depend upon the prevailing
interest rates at the date of redemption. The restricted cash held at HCLP
would be available to repay obligations under the HCLP Secured Notes. Sales
proceeds remaining after satisfying the HCLP Secured Note obligations would
be applied to the amounts outstanding under the Credit Agreement, including
outstanding letters of credit, and the Discount Notes. Mesa expects to
record a gain from the sale.
Excluding the Hugoton properties, Mesa had approximately 648 Bcfe of
proved reserves at December 31, 1994, and had approximately 55 Bcfe of oil
and gas production in 1994. Excluding Hugoton, Mesa generated approximately
$40 million of cash flows from sales of oil and gas production, net of
operating and administrative expenses, in 1994.
Masterson Lawsuit
-----------------
Mesa and CIG are defendants in a lawsuit brought by the lessors of a
portion of Mesa s interests in the West Panhandle field. In the lawsuit,
the plaintiffs allege that CIG and Mesa have underpaid royalties by
approximately $500 million since 1967 as a 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 included in a 1967 Gas Lease Amendment. In March 1995 the court made
several rulings which eliminated approximately $400 million of the
plaintiffs' claims, but which also reduced a number of CIG's and Mesa's
defenses. Mesa and CIG have stipulated to the court that Mesa would be
liable for between 50% and 60% of any adverse judgment against CIG for post-
February 1988 underpayment of royalties. The trial began March 22, 1995.
Additional information regarding the lawsuit is contained in Note 9 to the
consolidated financial statements of the Company located elsewhere in this
Form 10-K.
Mesa does not expect the ultimate resolution of this lawsuit to have a
material adverse effect on its financial position or results of operations.
However, no determination can be made at this time as to the ultimate
outcome and a significant final judgment for the plaintiffs could have such
a material adverse effect. Mesa and CIG would expect to appeal any adverse
decision reached by the U.S. District Court and would expect to argue on
appeal many of the defenses which were ruled against by the court. In the
event of an adverse decision at the U.S. District Court, Mesa would be
required to post a bond to appeal. Mesa believes that it has sufficient
resources to post such a bond and to pursue an appeal. Mesa's financial
flexibility could be adversely affected in 1996 because of the bonding
requirements.
Other
-----
Mesa recognizes its ownership interest in natural gas production as
revenue. Actual production quantities sold may be different from Mesa's
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 5% of total equivalent
production in 1994 compared with 3% during the same period 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 commodity futures contracts primarily related to
crude oil and natural gas. 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 22, 1995, and supplementary data are
included in this Form 10-K under Item 14 on pages F-2 through F-26.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
========================================================================
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
============================================================
Information regarding Directors and Executive Officers of the
Registrant appears in Mesa's Proxy Statement for the 1995 Annual Meeting of
Stockholders which is to be filed with the Commission (the "Proxy
Statement"), and such information is incorporated by reference herein.
Item 11. Executive Compensation
================================
The presentation of Executive Compensation of the Registrant appears in
the Proxy Statement and such information (other than information that is not
required to be set forth in this Form 10-K) is incorporated by reference
herein.
Item 12. Security Ownership of Certain Beneficial Owners and Management
========================================================================
The presentation of Security Ownership of Certain Beneficial Owners and
Management of the Registrant appears in the Proxy Statement and such
information is incorporated by reference herein.
Item 13. Certain Relationships and Related Transactions
========================================================
The information in Item 11 above, "Executive Compensation," and in the
Proxy Statement under "Election of Directors," is incorporated by reference
herein.
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-26
(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).
*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
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 Deed of Trust, Assignment of Production,
Security Agreement and Financing Statement dated as of March
2, 1994, between Mesa Operating Co. as Mortgagor and Debtor,
and Harris Trust and Savings Bank, as mortgagee and Secured
Party (Exhibit 4.8 to the Company's Form 10-Q dated March 31,
1994).
*4.4 - 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).
*4.5 - 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).
*4.6 - 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).
4.7 - 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.
*4.8 - 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).
*4.9 - 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).
*4.10 - 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).
*4.11 - 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).
*4.12 - Fourth Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
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).
*4.13 - 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).
*4.14 - 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).
*4.15 - 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).
*4.16 - Second Amended and Restated Credit Agreement dated as of May
1, 1993, among the Company, Mesa Operating Limited
Partnership, the Banks, and Societe Generale, Southwest
Agency, as Agent (Exhibit 4.17 to the Company's Registration
Statement on Form S-4, Registration No. 33-53706).
*4.17 - Assignment and Assumption Agreement dated as of January 5,
1994, among Mesa Inc., Mesa Operating Co., Mesa Operating
Limited Partnership, Pickens Operating Co., the Banks party
to the Credit Agreement and the Agent with respect to the
Credit Agreement (Exhibit 4.21 to the Company's Registration
Statement on Form S-4, Registration No. 33-53706).
*4.18 - 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 and the Convertible Notes
(Exhibit 4.18 to the Company's Registration Statement on Form
S-4, Registration No. 33-53706).
*4.19 - Amended and Restated Pledge Agreement dated as of March 2,
1994, by Mesa Operating Co., in favor of Societe Generale,
Southwest Agency, as Agent for the pro rata benefit of the
banks parties to the Credit Agreement (Exhibit 4.31 to the
Company's Form 10-Q dated March 31, 1994).
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.
*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 - Hugoton (MTR) Gas Purchase Contract between The Kansas Power
and Light Company, buyer, and Mesa Operating Limited
Partnership, seller, dated effective January 1, 1990
(Exhibit 19[a] to the Partnership's Form 10-Q dated June 30,
1989).
*10.3 - Supplemental Gas Purchase Contract between The Kansas Power
and Light Company, buyer, and Mesa Operating Limited
Partnership, seller, dated effective January 1, 1990
(Exhibit 19[b] to the Partnership's Form 10-Q dated June 30,
1989).
*10.4 - 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
December 31, 1985).
*10.5 - Amendments to the "B" Contract (Exhibit 10.2 to Pioneer
Corporation's Form 10-K dated December 31, 1985).
*10.6 - Gathering Charge Agreement dated January 20, 1985, as
amended, with respect to the "B" Contract (Exhibit 10.3 to
Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.7 - 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).
*10.8 - 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).
*10.9 - Gas Purchase Contract dated June 27, 1949, as amended through
October 3, 1985, between Amarillo Oil Company and Energas
Company (Exhibit 10.6 to Pioneer Corporation's Form 10-K
dated December 31, 1985).
*10.10 - 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).
*10.11 - 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).
*10.12 - Third Amendment dated December 19, 1991, to the Hugoton
(MTR) Gas Purchase Contract between The Kansas Power and
Light Company, buyer, and Mesa Operating Limited
Partnership, seller, dated effective January 1, 1990
(Exhibit 10[q] to the Company's Form 10-K dated December 31,
1991).
*10.13 - "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).
*10.14 - 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).
*10.15 - 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).
*10.16 - 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).
*10.17 - 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).
*10.18 - First Amendment to Settlement and Interim Release Agreement
between Hugoton Capital Limited Partnership, Mesa Operating
Limited Partnership and The Kansas Power and Light Company
dated December 19, 1991, (Exhibit 10[w] to the Company's Form
10-K dated December 31, 1991).
*10.19 - Engagement Agreement dated as of July 1, 1991, between Mesa
Limited Partnership, Mesa Operating Limited Partnership,
Mesa Holding Limited Partnership, Mesa Midcontinent Limited
Partnership, Mesa Acquisition Limited Partnership, and BTC
Partners, Inc. (Exhibit 10[v] to the Company's Registration
Statement on Form S-4, Registration No. 33-42102).
*10.20 - Conversion Agreement dated as of December 31, 1991, between
Mesa, Boone Pickens and Pickens Operating Co. (Exhibit 10[y]
to the Company's Form 10-K dated December 31, 1991).
*10.21 - Amendment to the Gas Purchase Contract dated June 27, 1949,
as amended, between Amarillo Oil Company and Energas Company
dated June 4, 1992 (Exhibit 10[z] to the Company's Form 10-K
dated December 31, 1992).
*10.22 - Agreement of Compromise and Settlement dated January 11,
1994, among Unocal Corporation, David Colan, MESA Inc. and
certain other parties (Exhibit 10.25 to the Company's
Registration Statement on Form S-1, Registration No.
033-51909).
*10.23 - Agreement of merger, dated as of January 5, 1994, entered
into by and among the Company, Boone Pickens and certain
other parties (Exhibit 10.27 to the Company's Form 10-K
dated December 31, 1993).
10.24 - 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.
*10.25 - 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).
*10.26 - 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).
*10.27 - 1991 Stock Option Plan of Mesa (Exhibit 10[v] to the
Company's Form 10-K dated December 31, 1991).
*10.28 - 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).
22 - List of Subsidiaries of the Company.
27 - Article 5 of Regulation S-X Financial Data Schedule
for Year-End 1994 Form 10-K.
28 - Summary Report of the Company relating to proved oil and gas
reserves at December 31, 1994.
(b) Reports on Form 8-K
------------------------
1. Current Report on Form 8-K dated February 17, 1995, regarding the
Annual Meeting of Stockholders of the Company to be held May 17, 1995.
<PAGE>
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: March 30, 1995 (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 March 30, 1995
(Boone Pickens) Chairman of the Board of
Directors
(Principal Executive Officer)
/s/ Paul W. Cain
------------------------- President, Chief Operating March 30, 1995
(Paul W. Cain) Officer and Director
/s/ Stephen K. Gardner
------------------------- Vice President and Chief March 30, 1995
(Stephen K. Gardner) Financial Officer
(Principal Financial Officer)
/s/ William D. Ballew
------------------------- Controller March 30, 1995
(William D. Ballew) (Principal Accounting Officer)
/s/ John L. Cox
------------------------- Director March 30, 1995
(John L. Cox)
/s/ John S. Herrington
------------------------- Director March 30, 1995
(John S. Herrington)
/s/ Wales H. Madden, Jr.
------------------------- Director March 30, 1995
(Wales H. Madden, Jr.)
/s/ Fayez S. Sarofim
------------------------- Director March 30, 1995
(Fayez S. Sarofim)
/s/ Robert L. Stillwell
------------------------- Director March 30, 1995
(Robert L. Stillwell)
/s/ J. R. Walsh, Jr.
------------------------- Director March 30, 1995
(J. R. Walsh, Jr.)
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-26
F-1
<PAGE>
<PAGE>
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, 1994 and 1993, 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, 1994. 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.
As discussed further in Note 2 to the consolidated financial statements, the
Company's current financial forecasts indicate that the Company will be
unable to fund its principal and interest obligations in 1996 with cash
flows from operating activities and available cash and securities balances.
Also, as discussed further below, the Company would be required to post a
bond in the event of an adverse decision in a lawsuit. This could result in
accentuating the Company's forecasted inability to fund its principal and
interest obligations in 1996. 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. Proceeds from such a sale would be used to retire long-term
debt. If the Company does not sell its Hugoton properties, it would attempt
to strengthen its financial position by other means, including the sale of
additional equity or refinancing of its long-term debt. There can be no
assurances that, in the absence of such a sale, the Company will be able to
issue equity or refinance its debt.
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, 1994 and 1993, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1994, in conformity with generally accepted
accounting principles.
As discussed further in Note 9 to the consolidated financial statements, the
Company is a defendant in a lawsuit alleging royalty underpayments relating
to the Company s interest in an oil and gas lease. As discussed further in
Note 2 to the consolidated financial statements, an unfavorable final
judgment could have a material adverse effect on the Company s financial
position and results of operations. The Company would be required to post a
bond to appeal an adverse decision at the U.S. District Court. The Company
believes it will have sufficient resources to post a bond requirement;
however, the Company's cash position and financial flexibility could be
adversely affected in 1996 by such a bond requirement. Although 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, no
determination can be made at this time as to the ultimate outcome of the
litigation and no estimate of damages, if any, can be made. Accordingly, no
provision for any liability that may result upon the adjudication has been
made in the accompanying consolidated financial statements.
/s/ Arthur Andersen LLP
-----------------------
ARTHUR ANDERSEN LLP
Houston, Texas
March 22, 1995
F-2
<PAGE>
<PAGE>
MESA Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
-------------------------------------
(in thousands, except per share data)
Years Ended December 31
-------------------------------
1994 1993 1992
--------- --------- ---------
Revenues:
Natural gas........................... $ 139,580 $ 141,798 $ 157,672
Natural gas liquids................... 72,771 61,427 59,669
Oil and condensate.................... 7,877 12,428 18,701
Other................................. 8,509 6,551 1,070
--------- --------- ---------
228,737 222,204 237,112
--------- --------- ---------
Costs and Expenses:
Lease operating....................... 52,655 51,819 43,859
Production and other taxes............ 21,306 20,332 18,631
Exploration charges................... 5,157 2,705 10,008
General and administrative............ 28,649 25,237 24,460
Depreciation, depletion and
amortization........................ 92,287 100,099 113,933
--------- --------- ---------
200,054 200,192 210,891
--------- --------- ---------
Operating Income........................... 28,683 22,012 26,221
--------- --------- ---------
Other Income (Expense):
Interest income....................... 13,457 10,704 13,504
Interest expense...................... (144,757) (142,002) (143,392)
Gains from futures and securities
investments......................... 6,698 3,954 7,808
Gains from collections from
Bicoastal Corporation............... 16,577 18,450 --
Gains on dispositions of oil
and gas properties.................. -- 9,600 12,250
Litigation settlement................. -- (42,750) --
Gain from adjustment of contingency
reserve............................. -- 24,000 --
Other................................. (4,011) (6,416) (5,623)
--------- --------- ---------
(112,036) (124,460) (115,453)
--------- --------- ---------
Net Loss................................... $ (83,353) $(102,448) $ (89,232)
========= ========= =========
Net Loss Per Common Share.................. $ (1.42) $ (2.61) $ (2.31)
========= ========= =========
Weighted Average Common Shares Outstanding. 58,860 39,272 38,571
========= ========= =========
(See accompanying notes to consolidated financial statements.)
F-3
<PAGE>
MESA Inc.
CONSOLIDATED BALANCE SHEETS
---------------------------
(in thousands, except share data)
December 31
----------------------
1994 1993
---------- ----------
ASSETS
Current Assets:
Cash and cash investments..................... $ 143,422 $ 138,709
Marketable securities and futures contracts... 19,112 11,319
Accounts and notes receivable................. 38,938 43,442
Other......................................... 3,372 2,732
---------- ----------
Total current assets..................... 204,844 196,202
---------- ----------
Property, Plant and Equipment:
Oil and gas properties, wells
and equipment, using the successful
efforts method of accounting................ 1,867,842 1,846,237
Office and other.............................. 43,836 41,064
Accumulated depreciation, depletion
and amortization............................ (781,230) (695,455)
---------- ----------
1,130,448 1,191,846
---------- ----------
Other Assets:
Restricted cash of subsidiary partnership..... 61,299 62,649
Gas balancing receivable...................... 54,971 47,101
Other......................................... 32,397 35,584
---------- ----------
148,667 145,334
---------- ----------
$1,483,959 $1,533,382
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities on long-term debt.......... $ 30,537 $ 67,657
Accounts payable and accrued liabilities...... 40,468 33,375
Interest payable.............................. 18,184 19,012
---------- ----------
Total current liabilities................ 89,189 120,044
---------- ----------
Long-Term Debt..................................... 1,192,756 1,173,637
---------- ----------
Deferred Revenue................................... 21,900 22,707
---------- ----------
Other Liabilities.................................. 55,542 104,865
---------- ----------
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 46,511,439 shares, respectively......... 640 465
Additional paid-in capital.................... 398,965 303,344
Accumulated deficit........................... (275,033) (191,680)
---------- ----------
124,572 112,129
---------- ----------
$1,483,959 $1,533,382
========== ==========
(See accompanying notes to consolidated financial statements.)
F-4
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<PAGE>
MESA Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(in thousands)
Years Ended December 31
-----------------------------
1994 1993 1992
-------- --------- --------
Cash Flows From Operating Activities:
Net loss................................ $(83,353) $(102,448) $(89,232)
Adjustments to reconcile net loss to
net cash provided by (used in)
operating activities:
Depreciation, depletion and
amortization..................... 92,287 100,099 113,933
Gains on dispositions of
oil and gas properties........... -- (9,600) (12,250)
Accreted interest on discount notes 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) --
Increase in gas balancing
receivables...................... (7,840) (4,942) (17,772)
Decrease in deferred natural gas
revenue.......................... (785) (3,370) (10,287)
Settlement of prior year tax claims -- (12,931) --
Natural gas hedging activities..... 9,715 324 (8,357)
Sales of marketable securities
and futures contracts............ 18,771 39,283 126,217
Purchases of marketable securities
and futures contracts............ (19,866) (34,711) (102,161)
Gains from futures and securities
investments...................... (6,698) (3,954) (7,808)
(Increase) decrease in
accounts receivable.............. 5,934 1,986 (585)
Decrease in payables and
accrued liabilities.............. (3,142) (15,887) (7,814)
Other.............................. 6,972 (4,662) 11,733
-------- -------- --------
Net cash provided by (used in)
operating activities............. 48,597 32,492 (4,383)
-------- -------- --------
Cash Flows From Investing Activities:
Capital expenditures.................... (32,590) (29,636) (69,201)
Proceeds from dispositions of
oil and gas properties................ -- 26,118 11,424
Collection of notes receivable.......... -- 47,501 28,181
Other................................... (7,660) (6,461) (11,494)
-------- -------- --------
Net cash provided by (used in)
investing activities............. (40,250) 37,522 (41,090)
-------- -------- --------
Cash Flows From Financing Activities:
Issuance of common stock................ 93,067 -- --
Repayments of long-term debt............ (175,107) (80,102) (24,550)
Long-term borrowings.................... 77,754 -- --
Debt issuance costs..................... -- (9,651) --
Other................................... 652 1,251 (4,935)
-------- -------- --------
Net cash used in
financing activities............. (3,634) (88,502) (29,485)
-------- -------- --------
Net Increase (Decrease) in Cash and
Cash Investments........................... 4,713 (18,488) (74,958)
Cash and Cash Investments
at Beginning of Year....................... 138,709 157,197 232,155
-------- -------- --------
Cash and Cash Investments at End of Year..... $143,422 $138,709 $157,197
======== ======== ========
(See accompanying notes to consolidated financial statements.)
F-5
<PAGE>
<PAGE>
MESA Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
----------------------------------------------------------
(in thousands)
Common Stock Additional
-------------- Paid-in Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance, December 31, 1991.......... 38,571 $386 $273,198 $ --
Net loss....................... -- -- -- (89,232)
------ ---- -------- ---------
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)
====== ==== ======== =========
(See accompanying notes to consolidated financial statements.)
F-6
<PAGE>
<PAGE>
MESA Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
(1) Organization and Summary of Significant Accounting Policies
===========================================================
MESA Inc., a Texas corporation, was formed 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.
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.
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 1994 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 futures contracts which are not
intended to be hedges of future natural gas or crude oil production.
Investments in such contracts are periodically adjusted to market prices and
gains and losses are included in gains from futures and securities
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
F-7
<PAGE>
<PAGE>
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. 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.
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, short-term trade receivables and payables, restricted cash, and
long-term debt. The carrying values of cash, marketable securities, short-
term trade receivables and payables, and restricted cash approximate fair
value. 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).
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, 1994, the Company had produced and sold a net
19.2 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 $36.1 million. Substantially all of the
Company's gas balancing receivables and deferred revenue are classified as
long-term.
The Company periodically enters into 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 $5.6
million and $895,000 in 1992 and 1994, respectively, and a net loss of
$324,000 in 1993 related to hedging activities. At December 31, 1994, the
Company had deferred gains of $9.7 million resulting from hedging a
substantial portion of the Company s anticipated natural gas production for
the first three quarters of 1995. These deferred gains and any increases or
decreases in 1995 in the value of open hedge contracts related to such
production periods will be recognized as natural gas revenues when the
hedged production occurs.
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
F-8
<PAGE>
<PAGE>
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
=======================
The Company is highly leveraged with over $1.2 billion of long-term
debt, including current maturities (see Note 4). Hugoton Capital Limited
Partnership ("HCLP") is the obligor on approximately 44% of the Company's
consolidated long-term debt. HCLP, an indirect, wholly owned subsidiary of
the Company was formed in 1991 to issue long-term debt which is secured by
the Company's Hugoton field properties which represent approximately 65% of
the Company's total proved oil and gas reserves. The assets and cash flows
of HCLP that are subject to the mortgage securing HCLP's debt are dedicated
to service such debt and are not available to pay creditors of the Company
or its subsidiaries other than HCLP. Approximately 88% of the Company's
remaining debt, excluding HCLP's debt, does not require cash interest
payments until December 31, 1995. On this date, and until the debt is
repaid, the Company is required to make semiannual cash interest payments at
a 12-3/4% annual rate. If the Company had been required to make cash
interest payments on this debt in 1994, the interest payments would have
totaled $70.6 million. Such payments would have exceeded the Company's 1994
consolidated cash flows from operating activities which totaled $48.6
million. The Company also has significant debt principal payments due in
1996 through 1998.
The Company's cash flows from operating activities are substantially
dependent on the amount of oil and gas produced and the price received for
such production. The Company expects that cash generated by its 1995
production, together with available cash and securities balances, will be
sufficient to cover its debt principal and interest obligations and capital
expenditures through December 31, 1995.
The Company s current financial forecasts indicate that it will be
unable to fund its principal and interest obligations in 1996 with cash
flows from operating activities and available cash and securities balances.
To address this situation 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. Proceeds from such a sale would be used to retire long-term
debt. If the Company does not sell its Hugoton properties, it would attempt
to strengthen its financial condition by other means, including the sale of
additional equity or refinancing of its long-term debt. There can be no
assurance that the Company will sell its Hugoton properties or that, in the
absence of such a sale, the Company will be able to issue equity or
refinance its debt.
Excluding the Hugoton properties, the Company had approximately 648
billion cubic feet of proved equivalent natural gas reserves ("Bcfe") at
December 31, 1994, and had approximately 55 Bcfe of oil and gas production
in 1994. Excluding Hugoton, the Company generated approximately $40 million
of cash flows from sales of oil and gas production, net of operating and
administrative expenses, in 1994. The Company expects to record a gain from
the sale.
The Company is a defendant in a lawsuit brought by the lessors of a
portion of the Company's interest in the West Panhandle field. The
plaintiffs are seeking approximately $500 million for alleged underpayments
of royalties. In March 1995 the court made certain pretrial rulings that
eliminated approximately $400 million of the plaintiffs' claims, but which
also reduced a number of the Company's defenses. The Company would be
liable for between 50% and 60% of any damages in the event of an adverse
judgment. The trial began on March 22, 1995. (See Note 9 for additional
information regarding the lawsuit.) 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. However, no determination can
be made at this time as to the ultimate outcome and a significant
F-9
<PAGE>
<PAGE>
final judgment for the plaintiffs could have such a material adverse effect.
The Company would expect to appeal any adverse decision reached by the U.S.
District Court and would expect to argue on appeal many of the defenses
which were ruled against by the court. In the event of an adverse decision
at the U.S. District Court, the Company would be required to post a bond to
appeal. The Company believes that it has sufficient resources to post such
a bond and to pursue an appeal. The Company's financial flexibility could
be adversely affected in 1996 because of the bonding requirements.
(3) Marketable Securities and Futures Contracts
===========================================
The value of marketable securities and futures contracts are as follows
(in thousands):
December 31
--------------------
1994 1993
------- -------
Equity securities:
Cost...................................... $ 9,489 $11,156
Unrealized loss........................... (1,381) (469)
Futures contracts:
Margin cash............................... 1,337 656
Unrealized gain in hedge contracts........ 6,823 --
Unrealized gain (loss) in investment
contracts............................... 2,844 (24)
------- -------
Total market value........................ $19,112 $11,319
======= =======
In 1994 the Company recognized net gains of approximately $6.7 million
from its investments in securities and futures contracts compared with net
gains in 1993 of $4.0 million and in 1992 of $7.8 million. These gains and
losses do not include gains or losses from natural gas futures contracts
accounted for as hedges 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 securities and futures contracts gains and losses recognized
during a period include both realized and unrealized gains and losses. The
Company realized net gains from securities transactions and futures
contracts of $4.7 million in 1994, $2.3 million in 1993, and $10.0 million
in 1992.
(4) Long-term Debt
==============
Long-term debt and current maturities are as follows (in thousands):
December 31
------------------------
1994 1993
---------- ----------
HCLP Secured Notes.......................... $ 520,180 $ 541,600
Credit Agreement............................ 71,131 59,148
12-3/4% secured discount notes.............. 581,942 472,939
12-3/4% unsecured discount notes............ 37,345 148,576
12% subordinated notes...................... -- 6,336
13-1/2% subordinated notes.................. 7,390 7,390
Other....................................... 5,305 5,305
---------- ----------
1,223,293 1,241,294
Current maturities.......................... (30,537) (67,657)
---------- ----------
Long-term debt.............................. $1,192,756 $1,173,637
========== ==========
F-10
<PAGE>
<PAGE>
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, 1994, bear interest at fixed rates
ranging from 8.80% to 11.30% per annum (weighted average 10.27%). Principal
payments, if required, 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, 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. Such
premiums have increased the effective weighted average interest rate payable
on the remaining HCLP Secured Notes outstanding to 10.33% per annum at
December 31, 1994. According to current expectations, principal payments
based on actual production and prices could reduce principal payments from
the initial scheduled amortization by approximately $50 million through
1996.
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.
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.
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 (10.27% at December 31, 1994). 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.
In February 1994 the Company contributed $5.8 million to HCLP which,
along with $10.3 million of HCLP cash not subject to the mortgage, was used
to supplement HCLP s cash flows in order to make the February 1994 scheduled
principal payment. In the third quarter of 1994 HCLP distributed $10
million of cash not subject to the mortgage to the Company's subsidiaries
which own HCLP's equity.
F-11
<PAGE>
<PAGE>
HCLP's cash balances were as follows (in thousands):
December 31
----------------
1994 1993
------- -------
Subject to the mortgage.............................. $48,087 $30,595
Not subject to the mortgage.......................... 1,551 9,851
------- -------
Cash included in current assets...................... $49,638 $40,446
======= =======
Restricted cash included in noncurrent assets........ $61,299 $62,649
======= =======
Refundable GIC fee included in noncurrent assets..... $10,295 $11,400
======= =======
Mesa Operating Co. ("MOC"), a Company subsidiary which owns
substantially all 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, process
remittances of production revenues and perform certain other administrative
functions in exchange for a services fee. The fee totaled approximately
$12.8 million in 1994, $11.4 million in 1993, and $10.7 million in 1992.
Credit Agreement
----------------
In the fourth quarter of 1994 the Company negotiated an amendment to
its bank credit agreement (the "Credit Agreement") which extended its final
maturity date from June 1995 until June 1997 and increased the amount that
may be borrowed from the then outstanding $47.5 million to $82.5 million,
including letters of credit. The terms of the amendment require principal
payments of $10 million in December 1995, $22.5 million in 1996, and the
remainder in June 1997 (including cash collateralization of letters of
credit outstanding at that time). The amendment also eliminated a covenant
requiring a specified ratio of cash flow and available cash to debt service.
As of December 31, 1994, the Company had outstanding borrowings of
approximately $71.1 million and letter of credit obligations of $11.4
million under the amended Credit Agreement.
The rate of interest payable on borrowings under the amended Credit
Agreement is 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.
The amended Credit Agreement requires the Company to maintain tangible
adjusted equity, as defined, of $50 million and available cash, as defined,
of $32.5 million. At December 31, 1994, the Company's tangible adjusted
equity, as defined, was approximately $125 million and available cash, as
defined, was $105 million.
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
F-12
<PAGE>
<PAGE>
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
early 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 will not accrue interest through June 30, 1995;
however, the accreted value, as defined, of both series increases at a rate
of 12-3/4% per year, compounded semiannually, until June 30, 1995. After
June 30, 1995, each series will accrue interest at an annual rate of
12-3/4%, payable in cash semiannually in arrears, with the first payment due
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.
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.
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. The 12%
subordinated notes outstanding as of December 31, 1993, were redeemed on May
31, 1994, with proceeds from the Equity Offering.
Interest and Maturities
-----------------------
The aggregate interest payments made during 1994, 1993, and 1992 were
$62.2 million, $89.4 million and $142.7 million, respectively. Payment of
approximately $70.6 million and $64.6 million of interest incurred during
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 1994 and 1993 consolidated statements of
operations.
F-13
<PAGE>
<PAGE>
The scheduled principal repayments on long-term debt for the next five
years are as follows (in millions):
1995 1996 1997 1998 1999
------ ------ ------ ------ ------
HCLP Secured Notes................. $ 15.2 $ 32.3 $ 35.8 $ 37.0 $ 39.8
Credit Agreement(a)................ 10.0 22.5 38.6 -- --
12-3/4% secured discount notes..... -- -- -- 617.4 --
12-3/4% unsecured discount notes... -- 39.7 -- -- --
13-1/2% subordinated notes......... -- -- -- -- 7.4
Other.............................. 5.3 -- -- -- --
------ ------ ------ ------ ------
Total......................... $ 30.5 $ 94.5 $ 74.4 $654.4 $ 47.2
====== ====== ====== ====== ======
----------
(a) Excludes approximately $11.4 million in letter of credit
obligations currently outstanding and required to be cash
collateralized in June 1997.
Fair Value of Long-term Debt
----------------------------
The following is a summary of estimated fair value of the Company's
long-term debt for the years ended (in thousands):
1994 1993
------------------ ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
HCLP Secured Notes.............. $520,180 $535,135 $541,600 $614,716
Credit Agreement................ 71,131 71,131 59,148 59,148
12-3/4% secured discount notes.. 581,942 528,688 472,939 486,732
12-3/4% unsecured discount notes 37,345 37,591 148,576 141,731
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.
Proposed Hugoton Properties Sale
--------------------------------
In the first quarter of 1995 the Company began an auction process to
sell its interest in the Hugoton field by approaching a select group of
prospective buyers which have the financial means to complete a purchase of
the Company's entire interest. The Company hopes to complete a sale by mid-
1995.
The Company will use proceeds from a sale to retire debt. Any sales
proceeds must first be applied against the outstanding balances related to
the HCLP Secured Notes, which are secured by the Hugoton properties. Such
balances include note principal, accrued interest and any premiums due,
including premiums for early retirement of the notes. As of December 31,
1994, such premiums for early retirement of the notes would have totaled
approximately $42 million. The actual premiums due in the event of a
redemption of the HCLP Secured Notes will depend upon the prevailing
interest rates at the date of redemption. The restricted cash held at HCLP
would be available to repay obligations under the HCLP Secured Notes. Sales
proceeds remaining after satisfying the HCLP Secured Note obligations would
be applied to the amounts outstanding under the amended Credit Agreement,
including outstanding letters of credit, and the Discount Notes.
F-14
<PAGE>
<PAGE>
(5) Income Taxes
============
Effective January 1, 1993, the Company adopted SFAS No. 109,
"Accounting for Income Taxes." SFAS No. 109 requires 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 Company elected to adopt the change
in method of accounting for income taxes prospectively in 1993. After
consideration of offsetting valuation allowances, there was no cumulative
effect on prior years of adopting SFAS No. 109.
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
---------------
1994 1993
------ ------
Deferred tax asset................................... $ 240 $ 208
Deferred tax liability............................... -- (1)
Valuation allowance.................................. (240) (207)
------ ------
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
---------------
1994 1993
------ ------
Tax basis of oil and gas properties in
excess of financial basis.......................... $ 80 $ 91
Regular tax net operating loss carryforward.......... 156 114
Other, net........................................... 4 2
Valuation allowance.................................. (240) (207)
------ ------
Net deferred tax asset.......................... $ -- $ --
====== ======
At December 31, 1994, the Company had a regular tax net operating loss
carryforward of approximately $400 million. Additionally, the Company had
an alterative minimum tax loss carryforward available to offset future
alternative minimum taxable income of approximately $370 million. If not
used, these carryforwards will expire between 2007 and 2009.
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, 1994, there are no remaining open tax
years for Original Mesa for federal income tax purposes.
F-15
<PAGE>
<PAGE>
(6) Property Sales
==============
See Notes 2 and 4 for discussion of the proposed sale of the Company's
interests in the Hugoton field.
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.
In June 1992 the Company sold all of its Canadian interests (consisting
of overriding royalty interests in producing and nonproducing acreage) for
approximately $12 million in cash and recognized an approximate $12 million
gain.
(7) Stockholders' Equity
====================
At December 31, 1993, the Company had outstanding 46.5 million shares
of common stock and owned a 97.38% interest in its direct subsidiaries; the
General Partner owned a 2.62% interest. In January 1994 the remaining
general partner interest was converted into common stock. See Note 1 for
further discussion of the conversion in 1994 of the remaining general
partner interest into common stock of the Company. In the second quarter of
1994 the Company completed the Equity Offering (see Note 4) 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. At
December 31, 1994, the Company had outstanding 64.1 million shares of common
stock.
The Company has authorized 10 million shares of preferred stock. No
shares of preferred stock have been issued as of December 31, 1994.
(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 approximately $28 million and $46 million,
respectively, 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 1994 the Company
recorded gains of $16.6 million 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. The Company owns an interest in the Gas Lease.
The plaintiffs, in their Second Amended Complaint, included the Company as a
defendant. The plaintiffs allege 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.
F-16
<PAGE>
<PAGE>
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 subsequently dismissed their claims against the Company
for reasons relating to the jurisdiction of the federal court; however, the
third-party complaint by CIG against the Company is not affected by the
dismissal.
The plaintiffs allege royalty underpayments of approximately $500
million (including interest at 10%) covering the period July 1, 1967 to the
present. In addition, the plaintiffs seek exemplary damages. Management
believes that the Company has several defenses to the plaintiffs' claims,
including (i) that the royalties for all periods were properly computed and
paid, (ii) that plaintiffs' claims with respect to all periods prior to
October 1, 1989 (which appear to account for approximately $400 million of
the claims) were explicitly released by a 1988 written settlement agreement
among plaintiffs, CIG and the Company and are further barred by the statute
of limitations, and (iii) that from October 1, 1988 and thereafter the
"favored nations" clause was suspended and that "in lieu of" such "favored
nations" clause, CIG and the Company would pay royalties based upon the
Federal Energy Regulatory Commission rate or market value rate set forth in
the 1988 royalty agreements.
In March 1995 the court ruled (1) that all claims for royalty
underpayments for the periods prior to October 1, 1989, were released by the
plaintiffs in the 1988 settlement agreement, (2) plaintiffs are not entitled
to exemplary damages, and (3) that the "favored nations" clause in the Gas
Lease Amendment has not been eliminated or suspended by the "in lieu of"
provision to the 1988 royalty agreements. The court has also made certain
other rulings adverse to the defendants covering certain other defenses.
The Company and CIG have filed stipulations with the court whereby the
Company will be liable for between 50% and 60%, depending upon the time
period covered, of any adverse judgment against CIG for post-February 1988
underpayment of royalties, if any, depending upon the time period covered by
an adverse judgment against CIG. The court's rulings have eliminated
approximately $400 million of the plaintiff's original $500 million of
claims but have also reduced a number of CIG's and the Company's defenses.
The trial began March 22, 1995.
See Note 2 for a discussion of the potential effect on the Company of
an adverse decision in this lawsuit.
Preference Unitholders
----------------------
The Company is a defendant in lawsuits related to the Corporate
Conversion filed in the U.S. District Court for the Northern District of
Texas--Dallas Division. Plaintiffs allege, among other things, that (i) the
proxy materials delivered to unitholders in connection with the Corporate
Conversion contained material misstatements and omissions, (ii) the General
Partner of the Partnership breached fiduciary duties to the preference
unitholders in structuring the transaction and allocating the common stock
of the Company and (iii) the Corporate Conversion was implemented in breach
of the partnership agreement of the Partnership because defendants allegedly
did not obtain the requisite opinion of independent counsel regarding
certain tax effects of the transaction. The Company and the other
defendants have denied the allegations and believe they are without merit.
Plaintiffs seek a declaration declaring the Corporate Conversion void and
rescinding it, an order requiring payment of $164 million to the former
preference unitholders in respect of the preferential distribution rights of
their units, unspecified compensatory and punitive damages and other relief.
On August 12, 1994, the Court entered an order denying plaintiff's
motion for a summary judgment and granted the Company's motion for a summary
judgment. A final judgment was entered dismissing the case. A notice of
appeal was filed August 19, 1994, by plaintiffs. Oral arguments in the case
have been scheduled before the Fifth Circuit Court of Appeals in May 1995.
The Company does not expect the resolution of this lawsuit to have a
material adverse effect on its financial position or results of operations.
F-17
<PAGE>
<PAGE>
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 the 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 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.
(10) Employee Benefit Plans
======================
Retirement Plans
----------------
The Company maintains two defined contribution retirement plans for the
benefit of its employees. The Company expensed $3.3 million in 1994, $3.2
million in 1993, and $3.3 million in 1992 in connection with these plans.
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
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, 1994, the
following stock options were outstanding:
Number of
Options
---------
Outstanding at December 31, 1993............................ 1,933,050
Granted................................................ 1,075,000
Exercised.............................................. (41,720)
Forfeited.............................................. (39,870)
---------
Outstanding at December 31, 1994............................ 2,926,460
=========
F-18
<PAGE>
The outstanding options at December 31, 1994, are detailed as follows:
Number of Date of Exercise Price
Options Grant Per Share Exercisable
--------- -------- -------------- -----------
1,126,000................... 01/10/92 $ 6.8125 900,800
142,500................... 10/02/92 11.6875 114,000
107,960................... 05/18/93 5.8125 59,378
475,000................... 11/10/93 7.3750 261,250
75,000................... 06/06/94 6.1875 22,500
1,000,000................... 12/01/94 4.2500 --
--------- ---------
2,926,460 1,357,928
========= =========
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, 1994, options for 1,010,820 shares were
available for grant.
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 Corporation ("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.
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, 1994, (in thousands):
Mesa Pioneer
Plan Plan Total
------ ------- -------
Accumulated Postretirement Benefit
Obligation ("APBO"):
Retirees and dependents............ $ 983 $11,347 $12,330
Actives - fully eligible........... 327 -- 327
Other actives...................... 588 -- 588
------ ------- -------
Total APBO.................... 1,898 11,347 13,245
Unrecognized Transition Obligation...... (1,503) (2,503) (4,006)
------ ------- -------
Accrued Postretirement
Benefit Obligation.................... $ 395 $ 8,844(a) $ 9,239
====== ======= =======
----------
(a) The Company established an accrued liability associated with the
Pioneer Plan in conjunction with its acquisition of Pioneer in
1986.
F-19
<PAGE>
<PAGE>
For measurement purposes, the 1994 annual rate of increase in per
capita cost of covered health care benefits was assumed to be 11% for those
participants under age 65 and 10% 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, 1994, by approximately $735,000
and the net periodic postretirement benefit cost for the year ended December
31, 1994, by approximately $77,000. The net periodic postretirement benefit
cost for the year ended December 31, 1994, was approximately $1.4 million
based on the assumptions used.
The discount rate used in determining the APBO as of December 31, 1994,
was 8%.
The following table presents the Company's cost of postretirement
benefits other than pensions for the years ended December 31 (in thousands):
1994 1993 1992
------ ------ ------
Net periodic postretirement benefit cost:
Service cost............................ $ 110 $ 96 $ --
Interest cost........................... 988 988 --
Amortization of Transition Obligation... 276 276 --
------ ------ ------
$1,374 $1,360 $ -- (a)
====== ====== ======
Actual costs of providing benefits:
Mesa Plan(b)............................ $ 120 $ 123 $ 205
Pioneer Plan(c)......................... 666 909 1,356
------ ------ ------
$ 786 $1,032 $1,561
====== ====== ======
----------
(a) SFAS No. 106 was adopted effective January 1, 1993.
(b) Actual costs of providing benefits in 1992 under the Mesa Plan
were recorded to expense in the consolidated statements of
operations. Actual costs of providing benefits in 1993 and 1994
under the Mesa Plan were applied as incurred against the accrued
postretirement benefit obligation.
(c) Actual costs of providing benefits in 1992 under the Pioneer Plan
were applied as incurred against the previously accrued liability.
Actual costs of providing benefits in 1993 and 1994 under the
Pioneer Plan were applied as incurred against the accrued
postretirement benefit obligation.
Deferred Compensation
---------------------
The Company had agreements with two officers to provide postretirement
deferred compensation at a rate of one-half of the participant's final rate
of compensation (subject to minimum amounts specified in the agreements) for
a period of ten years following the date of retirement or death. In 1992 in
order to terminate the deferred compensation agreements, the Company
established life insurance plans, executed agreements with the two officers
and purchased insurance policies at an aggregate cost of $4.9 million. At
the time they were terminated, approximately $3.9 million had been accrued
under the deferred compensation agreements. The Company fully funded the
life insurance policies and has no further obligations under such policies
or under the deferred compensation agreements.
F-20
<PAGE>
<PAGE>
(11) Major Customers
===============
In 1994 revenues include sales to Mapco Oil and Gas Company ("Mapco")
of $70.9 million (31.4%), Western Resources, Inc. ("WRI") of $37.4 million
(16.6%), and Energas Company ("Energas") 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%). In
1992 revenues included sales to Mapco of $45.7 million (19.4%), WRI of $39.7
million (16.8%) and Energas of $23.7 million (10.0%).
(12) Concentrations of Credit Risk
=============================
Substantially all of the Company's accounts receivable at December 31,
1994, 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
============================================
The Company conducts its operations through various direct and indirect
subsidiaries. On December 31, 1994, the Company's direct subsidiaries were
MOC, Mesa Holding Co. ("MHC") and Hugoton Management Co. ("HMC"). 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 an approximate 99% limited
partnership interest in HCLP. MHC owns cash and securities, an approximate
1% 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 general partner interest of HCLP.
See discussion below for 1994 changes in subsidiaries and HCLP ownership.
HCLP owns substantially all of the Company's Hugoton field natural gas
properties and is liable for 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. MOC and the Company are liable for the Credit Agreement, the 13-1/2%
subordinated notes and the Discount Notes. Mesa Capital Corp. ("Mesa
Capital"), a wholly owned financing subsidiary of MOC, is also an obligor
under the 13-1/2% subordinated notes and the Discount Notes. 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.
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.
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
approximately 19%) 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 has also repaid an additional $33 million of intercompany
debt to MOC in cash during 1994. As a result of these transactions, MOC now
owns 99% of the limited partnership interest in HCLP, and all of MHC's
intercompany debt to MOC which was outstanding at December 31, 1993, has
been eliminated.
F-21
<PAGE>
<PAGE>
The following are condensed consolidating financial statements of MESA
Inc., HCLP, MOC, and the Company's other direct and indirect subsidiaries
combined (in millions):
Condensed Consolidating Balance Sheets
--------------------------------------
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
====== ====== ====== ====== ====== ======
<PAGE>
Other Consol. The
MESA Company and Company
December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd
----------------- ------ ------ ------ -------- -------- --------
Assets:
Cash and cash
investments....... $ - $ 40 $ 16 $ 83 $ - $ 139
Other current
assets............ - 23 22 12 - 57
------ ------ ------ ------ ------ ------
Total current
assets.......... - 63 38 95 - 196
------ ------ ------ ------ ------ ------
Property, plant
and equipment,
net............... - 656 535 1 - 1,192
Investment in
subsidiaries...... 121 - 44 189 (354) -
Intercompany
receivables....... - - 113 - (113) -
Other noncurrent
assets............ - 87 55 3 - 145
------ ------ ------ ------ ------ ------
$ 121 $ 806 $ 785 $ 288 $ (467) $1,533
====== ====== ====== ====== ====== ======
Liabilities and
Equity:
Current
liabilities....... $ - $ 73 $ 46 $ 1 $ - $ 120
Long-term debt..... - 499 675 - - 1,174
Intercompany
payables.......... 9 - - 123 (132) -
Other noncurrent
liabilities....... - - 120 4 3 127
Partners'/Stock-
holders' equity
(deficit)......... 112 234 (56) 160 (338) 112
------ ------ ------ ------ ------ ------
$ 121 $ 806 $ 785 $ 288 $ (467) $1,533
====== ====== ====== ====== ====== ======
F-22
<PAGE>
<PAGE>
Condensed Consolidating Statements of Operations
------------------------------------------------
Years Ended:
------------
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)
====== ====== ====== ====== ====== ======
<PAGE>
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 on 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)
====== ====== ====== ====== ====== ======
<PAGE>
Other Consol. The
MESA Company and Company
December 31, 1992 Inc. HCLP MOC Subs. Elimin. Consol'd
----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 88 $ 149 $ - $ - $ 237
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 22 51 - - 73
General and
administrative.... - - 24 - - 24
Depreciation,
depletion and
amortization...... - 34 80 - - 114
------ ------ ------ ------ ------ ------
- 56 155 - - 211
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 32 (6) - - 26
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (52) (80) 2 - (130)
Intercompany interest
income (expense).... - - 18 (18) - -
Gains of dispositions
of oil and gas
properties.......... - - 12 - - 12
Equity in loss of
subsidiaries........ (87) - (16) (4) 107 -
Other................ (2) - (21) 9 17 3
------ ------ ------ ------ ------ ------
Net Loss............. $ (89) $ (20) $ (93) $ (11) $ 124 $ (89)
====== ====== ====== ====== ====== ======
F-23
<PAGE>
<PAGE>
Condensed Consolidating Statements of Cash Flows
------------------------------------------------
Years Ended:
------------
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
====== ====== ====== ====== ====== ======
<PAGE>
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)
====== ====== ====== ====== ====== ======
F-24
<PAGE>
<PAGE>
Other Consol. The
MESA Company and Company
December 31, 1992 Inc. HCLP MOC Subs. Elimin. Consol'd
----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 16 $ (52) $ 32 $ - $ (4)
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (3) (66) - - (69)
Proceeds from
dispositions of
oil and gas
properties........ - - 11 - - 11
Contributions to
subsidiaries...... - - (25) (7) 32 -
Other.............. - - 23 25 (31) 17
------ ------ ------ ------ ------ ------
- (3) (57) 18 1 (41)
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Repayments of
long-term debt.... - (25) - - - (25)
Contributions from
equity holders.... - 32 - - (32) -
Other.............. - (1) (1) (34) 31 (5)
------ ------ ------ ------ ------ ------
- 6 (1) (34) (1) (30)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ 19 $ (110) $ 16 $ - $ (75)
====== ====== ====== ====== ====== ======
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, 1994, 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
disposition of an 18% equity interest in HCLP. The HCLP 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-25
<PAGE>
<PAGE>
SUPPLEMENTAL FINANCIAL DATA
===========================
Oil and Gas Reserves and Cost Information
-----------------------------------------
(Unaudited)
Net proved oil and gas reserves as of December 31, 1994, were estimated
by Company engineers. Net proved oil and gas reserves as of December 31,
1993 and 1992, 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 dates estimated by the independent petroleum engineers.
All of the Company s reserves at December 31, 1994, 1993, and 1992, 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 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.
Over 70% 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, 1994, are natural gas. The natural gas prices in effect at December 31,
1994, (having a weighted average of $1.66 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 1994 was $1.66 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 $119 million and $51
million, respectively. At December 31, 1994, 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
value of oil and gas properties by approximately $180 million and $126
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 and 1992, 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
dates. The Company's proved reserve estimates as of December 31, 1994, for
the Hugoton and West Panhandle fields are approximately 241 Bcfe greater
than the reserves reported at December 31, 1993, adjusted for 1994
production, for the same properties. In the Hugoton field, the primary
difference reflects increased reserves for properties on which the Company
drilled 381 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. The Company operates the producing wells and the
natural gas processing plants on each of these properties and, based on its
knowledge of the properties, believes that its proved reserve estimates are
more reflective of future production than those estimates previously
reported by independent petroleum engineers.
F-26
<PAGE>
<PAGE>
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.
Capitalized Costs and Costs Incurred
------------------------------------
(Unaudited)
Capitalized costs relating to oil and gas producing activities at
December 31, 1994, 1993, and 1992 and the costs incurred during the years
then ended are set forth below (in thousands):
1994 1993 1992
---------- ---------- ----------
Capitalized Costs:
Proved properties................ $1,865,004 $1,845,483 $1,850,793
Unproved properties.............. 2,838 754 762
Accumulated depreciation,
depletion and amortization..... (753,827) (670,706) (589,720)
---------- ---------- ----------
Net......................... $1,114,015 $1,175,531 $1,261,835
========== ========== ==========
Costs Incurred:
Exploration and development:
Proved properties........... $ 523 $ 73 $ 64
Unproved properties......... 2,425 17 63
Exploration costs........... 5,157 2,705 15,157
Development costs........... 14,043 2,381 6,911
---------- ---------- ----------
Total exploration and
development.......... 22,148 5,176 22,195
---------- ---------- ----------
Plants and facilities:
Processing plants........... 3,248 17,501 44,716
Field compression facilities 3,129 4,387 1,509
Other....................... 5,168 2,257 3,301
---------- ---------- ----------
Total plants and
facilities........... 11,545 24,145 49,526
---------- ---------- ----------
Total costs incurred............. $ 33,693 $ 29,321 $ 71,721
========== ========== ==========
Depreciation, depletion
and amortization............... $ 89,413 $ 96,774 $ 110,340
========== ========== ==========
F-27
<PAGE>
<PAGE>
Estimated Quantities of Reserves
--------------------------------
(Unaudited) Years Ended December 31
------------------------------------
Natural Gas (MMcf) 1994 1993 1992
----------- ---------- ---------- ----------
Proved Reserves:
Beginning of year................ 1,202,444 1,276,049 1,367,968
Extensions and discoveries.. 6,211 5,132 37,100
Purchases of producing
properties................ 822 166 583
Revisions of previous
estimates................. 176,049 7,284 (24,462)
Sales of producing
properties................ - (6,367) (15,613)
Production.................. (82,339) (79,820) (89,527)
---------- ---------- ----------
End of year...................... 1,303,187 1,202,444 1,276,049
========== ========== ==========
Proved Developed Reserves:
Beginning of year................ 1,159,453 1,223,672 1,338,856
========== ========== ==========
End of year...................... 1,257,883 1,159,453 1,223,672
========== ========== ==========
Years Ended December 31
Natural Gas Liquids, Oil ------------------------------------
and Condensate (MBbls) 1994 1993 1992
------------------------ ---------- ---------- ----------
Proved Reserves:
Beginning of year................ 82,446 87,392 83,225
Extensions and discoveries.. 491 778 7,591
Purchases of producing
properties................ 1 - 9
Revisions of previous
estimates................. 13,947 3,083 3,028
Sales of producing
properties................ - (3,019) (637)
Production.................. (7,457) (5,788) (5,824)
---------- ---------- ----------
End of year...................... 89,428 82,446 87,392
========== ========== ==========
Proved Developed Reserves:
Beginning of year................ 79,294 82,439 82,406
========== ========== ==========
End of year...................... 85,656 79,294 82,439
========== ========== ==========
* Proved natural gas liquids, oil and condensate reserve quantities include
oil and condensate reserves at December 31 of the respective years as
follows: 1994, 5,031 MBbls; 1993, 3,296 MBbls; and 1992, 7,268 MBbls.
* 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: 1994, 4,457 MMcf of helium and 46,459 MMcf
of CO2; 1993, 5,198 MMcf of helium and 46,376 MMcf of CO2; and 1992,
5,634 MMcf of helium and 46,457 MMcf of CO2.
F-28
<PAGE>
<PAGE>
Standardized Measure of Future Net Cash Flows from Proved Reserves
------------------------------------------------------------------
(Unaudited)
December 31
------------------------------------
1994 1993 1992
---------- ---------- ----------
(in thousands)
Future cash inflows................... $3,513,282 $3,723,760 $3,802,614
Future production and
development costs:
Operating costs and
production taxes............... (1,192,005) (1,337,224) (1,271,799)
Development and
abandonment costs.............. (95,441) (80,310) (122,860)
Future income taxes................... (211,076) (240,017) (302,492)
---------- ---------- ----------
Future net cash flows................. 2,014,760 2,066,209 2,105,463
Discount at 10% per annum........ (1,080,578) (1,079,278) (1,068,282)
---------- ---------- ----------
Standardized Measure.................. $ 934,182 $ 986,931 $1,037,181
========== ========== ==========
Future net cash flows
before income taxes................. $2,225,836 $2,306,226 $2,407,955
========== ========== ==========
Standardized Measure
before income taxes................. $ 988,325 $1,068,740 $1,167,694
========== ========== ==========
----------
* 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.
<PAGE>
Changes in Standardized Measure
-------------------------------
(Unaudited)
Years Ended December 31
------------------------------------
1994 1993 1992
---------- ---------- ----------
(in thousands)
Standardized Measure at
beginning of year................... $ 986,931 $1,037,181 $ 995,214
---------- ---------- ----------
Revisions of reserves
proved in prior years:
Changes in prices and
production costs............... (121,300) 6,178 (77,527)
Changes in quantity estimates.... 151,538 17,616 (3,995)
Changes in estimates of
future development and
abandonment costs.............. (27,343) 8,054 (2,468)
Net change in income taxes....... 27,666 48,703 55,287
Accretion of discount............ 106,874 116,769 118,101
Other, primarily timing
of production.................. (80,650) (108,371) 12,687
---------- ---------- ----------
Total revisions............. 56,785 88,949 102,085
Extensions, discoveries and
other additions, net of future
production and development costs.... 8,075 4,456 65,737
Purchases of proved properties........ 463 138 457
Sales of oil and gas produced,
net of production costs............. (146,267) (143,502) (173,552)
Sales of producing properties......... - (26,907) (14,473)
Previously estimated development
and abandonment costs incurred
during the period................... 28,195 26,616 61,713
---------- ---------- ----------
Net changes in Standardized Measure... (52,749) (50,250) 41,967
---------- ---------- ----------
Standardized Measure at end of year... $ 934,182 $ 986,931 $1,037,181
========== ========== ==========
F-29
<PAGE>
<PAGE>
Quarterly Results
-----------------
(Unaudited)
Quarters Ended(2)
-------------------------------------------------
March 31 June 30 September 30 December 31
-------- -------- ------------ -----------
(in thousands, except per share data)
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)
======== ======== ======== ========
1993:
----
Revenues............ $ 63,826 $ 50,826 $ 42,377 $ 65,175
======== ======== ======== ========
Gross profit(1)..... $ 44,644 $ 32,009 $ 26,782 $ 46,618
======== ======== ======== ========
Operating income
(loss)............ $ 10,032 $ 4,904 $ (510) $ 7,586
======== ======== ======== ========
Net loss............ $(17,088) $(14,445) $(27,480) $(43,435)
======== ======== ======== ========
Net loss per
common share...... $ (.44) $ (.37) $ (.71) $ (1.06)
======== ======== ======== ========
----------
(1) Gross profit consists of total revenues less lease operating
expenses and production and other taxes.
(2) See Notes 5 and 9 to the Company's consolidated financial
statements for information on items affecting fourth quarter 1993
results.
F-30
<PAGE>
<PAGE>
INDEX TO EXHIBITS
-----------------
Exhibit No. Description
----------- -----------
4.7 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.
10.24 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.
22 MESA Inc. Subsidiaries
27 Article 5 of Regulation S-X Financial Data Schedule
for Year-End 1994 Form 10-K
28 Summary Report of the Company relating to proved oil and gas
reserves at December 31, 1994.
----------------------------------------------------------------------------
$82,500,000
THIRD AMENDED AND RESTATED CREDIT AGREEMENT
Dated as of November 29, 1994
Among
MESA INC.
and
MESA OPERATING CO.
and
THE BANKS NAMED IN THIS CREDIT AGREEMENT
and
SOCIETE GENERALE, SOUTHWEST AGENCY
as Agent
----------------------------------------------------------------------------
<PAGE>
TABLE OF CONTENTS
Page
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS
Section 1.01. Certain Defined Terms............................... 3
Section 1.02. Computation of Time Periods......................... 23
Section 1.03. Accounting Terms; Changes in GAAP................... 23
Section 1.04. Miscellaneous....................................... 23
ARTICLE II
THE ADVANCES AND THE LETTERS OF CREDIT
Section 2.01. The Advances........................................ 24
Section 2.02. Method of Borrowing................................. 24
Section 2.03. Fees................................................ 27
Section 2.04. Reduction of Commitments............................ 27
Section 2.05. Repayment of Advances; Reborrowings................. 28
Section 2.06. Interest on Advances................................ 29
Section 2.07. Prepayments......................................... 31
Section 2.08. Compensation........................................ 32
Section 2.09. Increased Costs..................................... 33
Section 2.10. Payments and Computations........................... 34
Section 2.11. Taxes............................................... 35
Section 2.12. Sharing of Payments, Etc. .......................... 37
Section 2.13. Letters of Credit................................... 38
Section 2.14. The Obligors Jointly and Severally Liable........... 41
Section 2.15. Use of Proceeds..................................... 41
Section 2.16. Interest on Overdue Amounts......................... 41
ARTICLE III
CONDITIONS OF LENDING
Section 3.01. Conditions Precedent to the Effectiveness of this
Agreement......................................... 42
Section 3.02. Conditions Precedent to Each Borrowing.............. 42
Section 3.03. Conditions Precedent to Certain Borrowings.......... 43
Section 3.04. Conditions Precedent to Letters of Credit........... 44
ARTICLE IV
REPRESENTATIONS AND WARRANTIES
Section 4.01. Organization, etc. ................................. 45
Section 4.02. Authorization; No Conflict.......................... 45
Section 4.03. Validity and Binding Nature......................... 46
Section 4.04. Financial Statements................................ 46
Section 4.05. Status of Title to Properties....................... 46
Section 4.06. Governmental Approvals.............................. 47
Section 4.07. Pending or Threatened Litigation.................... 47
Section 4.08. Pension Plans....................................... 47
Section 4.09. Investment Company Act.............................. 48
Section 4.10. Public Utility Holding Company Act.................. 48
Section 4.11. True and Complete Disclosure........................ 48
Section 4.12. Defaults............................................ 49
Section 4.13. Investments and Guaranties.......................... 49
Section 4.14. Liabilities......................................... 49
Section 4.15. Permits, Licenses, etc. ............................ 50
Section 4.16. Taxes............................................... 50
Section 4.17. Issuance of Notes................................... 50
Section 4.18. Condition of Property; Casualties................... 51
Section 4.19. Insurance........................................... 51
Section 4.20. Principal Place of Business......................... 51
Section 4.21. Documents........................................... 51
Section 4.22. The Security Documents.............................. 52
Section 4.23. Federal Regulations................................. 52
Section 4.24. Environmental Condition............................. 52
Section 4.25. Senior Debt......................................... 53
Section 4.26. Ownership of HCLP Limited Partnership Interests..... 54
ARTICLE V
AFFIRMATIVE COVENANTS
Section 5.01. Financial Statements and Other Information.......... 54
Section 5.02. Compliance with Laws, Etc. ......................... 58
Section 5.03. Maintenance of Insurance............................ 59
Section 5.04. Preservation of Existence, Etc. .................... 59
Section 5.05. Payment of Taxes, Etc. ............................. 59
Section 5.06. Visitation and Discussion........................... 60
Section 5.07. Maintenance of Property............................. 60
Section 5.08. Collateral.......................................... 60
Section 5.09. Title Assurances.................................... 60
Section 5.10. Tangible Equity..................................... 60
Section 5.11. Lock Box Account.................................... 60
Section 5.12. Further Assurances.................................. 60
Section 5.13. HCLP Related Collateral............................. 61
ARTICLE VI
NEGATIVE COVENANTS
Section 6.01. Limitation on Sale or Transfer of Property.......... 61
Section 6.02. Restrictions on Dividends, Distributions
and Redemptions................................... 62
Section 6.03. Restrictions on Investments, Loans or Advances by MI or
Guaranteeing Affiliates........................... 6
Section 6.04. Restrictions on Investments, Loans or Advances by the
Borrower and its Subsidiaries..................... 63
Section 6.05. Limitation on Accommodation Obligations............. 64
Section 6.06. Limitation on Merger and Consolidation.............. 65
Section 6.07. Limitation on Liens................................. 65
Section 6.08. Prohibition Upon Payments on the Subordinated Notes. 67
Section 6.09. Operating Losses.................................... 67
Section 6.10. Limitation on Indebtedness.......................... 68
Section 6.11. Amendments.......................................... 68
Section 6.12. Compliance with ERISA............................... 68
Section 6.13. Other Agreements.................................... 68
Section 6.14. Available Cash...................................... 68
ARTICLE VII
EVENTS OF DEFAULT
Section 7.01. Events of Default................................... 69
Section 7.02. Optional Acceleration............................... 72
Section 7.03. Automatic Acceleration.............................. 72
Section 7.04. Cash Collateral..................................... 73
Section 7.05. Non-exclusivity of Remedies......................... 73
ARTICLE VIII
THE AGENT
Section 8.01. Authorization and Action............................ 74
Section 8.02. Agent's Reliance, Etc. ............................. 74
Section 8.03. Societe Generale and Its Affiliates................. 75
Section 8.04. Bank Credit Decision................................ 75
Section 8.05. Indemnification..................................... 75
Section 8.06. Successor Agent..................................... 76
ARTICLE IX
MISCELLANEOUS
Section 9.01. Amendments, Etc. ................................... 76
Section 9.02. Notices, Etc. ...................................... 77
Section 9.03. No Waiver; Remedies................................. 77
Section 9.04. Costs and Expenses.................................. 78
Section 9.05. Right of Set-off.................................... 78
Section 9.06. Binding Effect...................................... 78
Section 9.07. Bank Assignments and Participations................. 79
Section 9.08. Indemnification..................................... 81
Section 9.09. Liability of the Agent as Issuing Bank.............. 83
Section 9.10. Survival of Certain Provisions...................... 84
Section 9.11. Execution in Counterparts........................... 84
Section 9.12. Survival of Representations, etc. .................. 84
Section 9.13. Severability........................................ 84
Section 9.14. Release of Guarantors............................... 84
Section 9.15. Joinder by MI....................................... 85
Section 9.16. Disclosures......................................... 85
Section 9.17. Business Loans...................................... 85
Section 9.18. Usury Not Intended.................................. 85
Section 9.19. Governing Law....................................... 86
Section 9.20. Waivers............................................. 87
<PAGE>
EXHIBITS:
Exhibit A - Commitments
Exhibit B - Address Information
Exhibit C - Form of Promissory Note
Exhibit D - Form of Notice of Borrowing
Exhibit E - Form of Request for Letter of Credit
Exhibit F - Form of Guaranty
Exhibit G - [INTENTIONALLY LEFT BLANK]
Exhibit H - [INTENTIONALLY LEFT BLANK]
Exhibit I - [INTENTIONALLY LEFT BLANK]
Exhibit J - Form of Assignment and Acceptance
Exhibit K-1 - Certificate of the Borrower
Exhibit K-2 - Certificate of MI
Exhibit L - [INTENTIONALLY LEFT BLANK]
Exhibit M - Form of Borrower's Counsel Opinion
Exhibit N - Form of Agent's Counsel Opinion
Exhibit O - Subordination Provisions
Exhibit P - Form of Deposit Account Agreement
Exhibit Q - Assignment and Assumption Agreement
Exhibit R - Form of Lockbox Report
Exhibit S - Form of HCLP Partners Agreement
SCHEDULES:
Schedule 1.01(a) - "B" Contract and Related Documents
Schedule 1.01(b) - Existing Letters of Credit
Schedule 1.01(c) - Existing Litigation
Schedule 1.01(d) - Existing West Panhandle Mortgages
Schedule 1.01(e) - Existing Indebtedness
Schedule 1.01(f) - Supply Contract and Related Documents
Schedule 4.01 - Subsidiaries of the Borrower and of MI
Schedule 4.22(a) - Filing Locations for MI Pledge Agreement
Schedule 4.22(b) - Filing Locations for Mortgage
Schedule 4.24(a) - Existing Environmental Concerns
Schedule 4.24(b) - Designated Environmental Sites
Schedule 6.04 - Existing Loans and Advances
Schedule 6.05 - Existing Accommodation Obligations
<PAGE>
THIRD AMENDED AND RESTATED CREDIT AGREEMENT
This Third Amended and Restated Credit Agreement dated as of November
29, 1994 is among Mesa Inc., a Texas corporation ("MI"), and Mesa Operating
Co., a Delaware corporation ("MOC" being herein sometimes called the
"Borrower" and collectively with MI sometimes called the "Obligors"), the
Banks (as herein defined), and Societe Generale, Southwest Agency, as Agent
for the Banks.
PRELIMINARY STATEMENTS
1. MI is a corporation formed in 1991 which, by transfer and
assignment, owns substantially all of the assets of and assumed
substantially all of the liabilities of Mesa Limited Partnership,
previously a Delaware limited partnership ("MLP"), of which Pickens
Operating Company, a Texas corporation ("POC") and Boone Pickens
were the sole general partners.
2. MOC is a corporation formed in 1994 which, by merger in accordance
with the Agreement of Merger dated as of January 5, 1994 among MI,
MOLP, and certain other affiliates of MI, owns all of the assets of
and assumed all of the liabilities of Mesa Operating Limited
Partnership, a Delaware limited partnership ("MOLP") of which Boone
Pickens and POC were the sole general partners.
3. MLP, MOLP, the Banks and the Agent previously entered into a Credit
Agreement dated as of June 3, 1991 ("Original Credit Agreement")
pursuant to which the Banks committed to make Advances to MOLP on
the terms and conditions set forth therein. The initial Borrowing
under the Original Credit Agreement was in the amount of
$100,000,000 and was utilized to repay a portion of the
indebtedness then outstanding under the Former Credit Agreement (as
defined hereafter).
4. The Banks and the Agent previously consented, to the transfer by
MLP of substantially all of its assets and liabilities to MI, and
to MLP's subsequent dissolution (together with related
transactions), all as more fully described in MLP's and MI's Proxy
Statement/Prospectus dated October 11, 1991, as the same was
supplemented by Supplement dated November 8, 1991, on the condition
that (a) MI assumed all of the obligations of MLP under the
Original Credit Agreement and (b) the parties entered into an
agreement to effect certain amendments to the Original Credit
Agreement.
5. In November, 1991, MI became a party to the Original Credit
Agreement in lieu of MLP and the parties amended and restated the
Original Credit Agreement in the form of the Amended and Restated
Credit Agreement dated as of November 15, 1991 among MI, MOLP, the
Banks and the Agent, as subsequently amended by Amendment No. 1
dated as of June 16, 1992 executed by MI, MOLP, the Required Banks
and the Agent (as so amended, the "First Amended and Restated
Credit Agreement").
6. As of May 1, 1993, the parties amended and restated the Amended and
Restated Credit Agreement in the form of the Second Amended and
Restated Credit Agreement dated as of May 1, 1993 among MI, MOLP,
the Banks, and the Agent, as subsequently amended by the First
Amendment Agreement dated as of March 31, 1994 executed by MI, the
Borrower (as successor to MOLP), the Agent and the Banks (as so
amended, the "Second Amended and Restated Credit Agreement").
7. The Banks and the Agent previously consented to the transfer by
MOLP of all of its assets and liabilities to MOC and to MOLP's
subsequent dissolution all as more fully described in the
Assignment and Assumption Agreement (as defined hereafter), on the
condition that MOC assumed all of the obligations of MOLP under the
Second Amended and Restated Credit Agreement.
8. MI and the Borrower have requested that the Banks (i) increase the
aggregate Commitments to $82,500,000 and (ii) make certain other
amendments to the Second Amended and Restated Credit Agreement.
9. In order to effect such further amendments, the parties have agreed
to restate the Second Amended and Restated Credit Agreement in its
entirety, and this Third Amended and Restated Credit Agreement
constitutes for all purposes an amendment to the Original Credit
Agreement, as amended by the Amended and Restated Credit Agreement
and the Second Amended and Restated Credit Agreement, and not a new
or substitute agreement and each reference to an "Advance" herein
shall include each Advance made heretofore under the Original
Credit Agreement, as amended by the Amended and Restated Credit
Agreement and the Second Amended and Restated Credit Agreement, as
well as each Advance made hereafter under this Third Amended and
Restated Credit Agreement.
In consideration of these premises and the mutual covenants and
agreements contained herein, the Obligors, the Banks, and the Agent agree as
follows:
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS
Section 1.01. Certain Defined Terms. As used in this Agreement,
the following terms shall have the following meanings (unless otherwise
indicated, such meanings to be equally applicable to both the singular and
plural forms of the terms defined):
"Acceptable Security Interest" in any Property means a Lien (a) which
exists in favor of the Agent for the benefit of the Banks, (b) which is
superior to all other Liens other than Permitted Liens, (c) which secures
the Advances, all other amounts owed by the Obligors under this Agreement
and the other Credit Documents, and all costs, expenses and amounts provided
for in the Security Documents, and (d) which is filed of record or
perfected.
"Accommodation Obligation" means, as to any Person, any obligation,
contingent or otherwise, of such Person entered into for the purpose of
guaranteeing or assuring, or in effect guaranteeing or assuring, any owner
or holder of any Indebtedness of any other Person (the "primary obligor") of
the payment of such Indebtedness or to protect such owner or holder against
loss in respect thereof, whether directly or indirectly, and including,
without duplication and without limiting the generality of the foregoing,
any obligation of such Person, direct or indirect, contingent or otherwise,
for the benefit of any owner or holder of Indebtedness of a primary obligor,
(i) to purchase or pay (or advance or supply funds for the purchase or
payment of) such Indebtedness or to purchase (or to advance or supply funds
for the purchase of) any direct or indirect security therefor, (ii) to
purchase property, securities or services for the purpose of assuring any
owner or holder of such Indebtedness of the payment of such Indebtedness, or
(iii) to maintain working capital, equity capital or other financial
statement condition of the primary obligor so as to enable the primary
obligor to pay such Indebtedness or otherwise to protect the owner or holder
thereof against loss in respect thereof; provided that the term
Accommodation Obligation shall not include endorsements for collection or
deposit, in either case, in the ordinary course of business.
"Adjusted Prime Rate" means, for any day, the fluctuating rate per
annum of interest equal to the greater of (a) the Prime Rate in effect on
such day and (b) the Federal Funds Rate plus one half of one percent (1/2%)
in effect on such day.
"Advance" means an advance by a Bank to the Borrower pursuant to
Article II, and refers to a Prime Rate Advance or a Eurodollar Rate Advance.
"Affiliate" of any Person means any trade or business (whether or not
incorporated) which is a member of a group of which such Person is a member
and which is under common control within the meaning of the regulations
under Section 414 of the Code.
"Agent" means Societe Generale, Southwest Agency in its capacity as an
agent pursuant to Article VIII and any successor agent pursuant to Section
8.06.
"Agreement" means this Third Amended and Restated Credit Agreement
dated as of November 29, 1994 among MI, the Borrower, the Banks, and the
Agent, as it may be amended or supplemented from time to time.
"Applicable Lending Office" means, with respect to each Bank, such
Bank's Domestic Lending Office in the case of a Prime Rate Advance, and such
Bank's Eurodollar Lending Office in the case of a Eurodollar Rate Advance.
"Applicable Margin" means (i) with respect to any Eurodollar Rate
Advance two and one-half percent (2-1/2%) and (ii) with respect to any Prime
Rate Advance, one half of one percent (1/2%).
"Assignment and Acceptance" means an assignment and acceptance entered
into by a Bank and an Eligible Assignee, and accepted by the Agent, in
substantially the form of the attached Exhibit J.
"Assignment and Assumption Agreement" means the Assignment and
Assumption Agreement dated as of January 5, 1994 among MOLP, MOC, MI, and
the Agent and the Banks in the form of Exhibit Q attached hereto.
"Authorized Officer" means (i) with respect to MI, the Chairman, the
President, any Vice President, the Treasurer or the Controller of MI, and
(ii) with respect to the Borrower, the Chairman, the President, any Vice
President, the Treasurer or the Controller of the Borrower.
"Available Cash" means, at any date, the sum of (i) the amount of all
cash, cash equivalents and Permitted Investments of MI and its Subsidiaries
other than HCLP at such date and (ii) Unrestricted Cash of HCLP at such
date.
""B" Contract" means that certain Agreement, dated January 3, 1928,
between Canadian River Gas Company, as Seller, and Amarillo Oil Company, as
Buyer, as heretofore supplemented and amended by the instruments listed in
Schedule 1.01(a) hereto, applicable to said parties' interests in (including
but not limited to, the sale and purchase of) natural gas produced from
certain acreage in the West Panhandle Field of Texas that is required to
supply customers located in the City of Amarillo or its environs in the
State of Texas.
"Banks" means each bank listed on the signature pages of this Agreement
and each Eligible Assignee that shall become a party to this Agreement
pursuant to Section 9.07.
"Borrower" has the meaning set forth in the Preliminary Statements to
this Agreement.
"Borrower Pledge Agreement" means the Amended and Restated Pledge
Agreement dated as of March 2, 1994, executed by the Borrower and the Agent,
as the same may be modified, amended or supplemented from time to time.
"Borrowing" means a borrowing consisting of Advances of the same Type
made by the Banks on the same day ratably according to their respective
Commitments (subject to the last sentence of Section 2.02(d)).
"Business Day" means a day of the year on which banks are not required
or authorized to close in New York City and Dallas, Texas and, if the
applicable Business Day relates to any Eurodollar Rate Advances, on which
dealings are carried on by banks in the London interbank market.
"Calendar Quarter" means a three-month period ending on the last day
of any March, June, September or December.
"Capital Lease" means, as to any Person, a lease of any property by
that Person as lessee that is, or should be, in accordance with GAAP
(including Financial Accounting Standards Board Statement No. 13, as amended
or superseded from time to time), recorded as a "capital lease" on the
balance sheet of that Person prepared in accordance with GAAP consistently
applied.
"Cash Collateral Account" means a special noninterest bearing cash
collateral account maintained at the Agent's office pursuant to Section
7.04.
"CERCLA" means the Comprehensive Environmental Response, Compensation,
and Liability Act of 1980, as amended, state and local analogs, and all
rules, regulations, and requirements thereunder in each case as now or
hereafter in effect.
"Code" means the Internal Revenue Code of 1986, as amended, and any
successor statute.
"Collateral" means the Collateral (as such term is defined in the MI
Pledge Agreement and the Borrower Pledge Agreement, respectively), and the
Mortgaged Property (as defined in the Mortgage).
"Commitment" means, for any Bank at the time any determination thereof
is to be made, the amount of such Bank's commitment hereunder to extend
credit to the Borrower by means of Advances and Letters of Credit, which,
subject to the provisions hereof, shall be the amount set forth opposite the
name of such Bank under the heading "Amount of Commitment" on Exhibit "A"
attached hereto (or, if such Bank has entered into one or more Assignments
and Acceptances, set forth for such Bank in the Register), as such amount is
reduced or terminated pursuant to Section 2.04 or Article VII, and
"Commitments" means the sum of the Commitments for each Bank.
"Consolidated MI" means MI and its Subsidiaries, taken as a whole.
"Control Percentage" means, with respect to any Person, the percentage
of the outstanding capital stock (or other equivalent interests) of such
Person having ordinary voting power which gives the direct or indirect
holder of such stock (or equivalent interests) the power to elect a majority
of the Board of Directors or other Persons performing similar functions (or,
if there are no such directors or Persons, having general voting power) of
such Person.
"Controlled Group" means any entity which, together with the Borrower,
is considered under common control under Sections 414(b), (c), or (m) of the
Code.
"Credit Documents" means this Agreement, the Notes, the Security
Documents, the Guaranties, the Letter of Credit Documents, the Letters of
Credit, and each other agreement, instrument or document executed by MI or
the Borrower or any Guaranteeing Affiliate at any time in connection with
this Agreement.
"Default" means (a) an Event of Default or (b) any event or condition
which with notice or lapse of time or both would, unless cured or waived,
become an Event of Default.
"Default Rate" means for any amount of the Obligations which is not
paid when due, to the fullest extent permitted by law, a rate per annum
equal at all times to the lesser of (a) the Maximum Rate or (b) in the case
EXHIBIT 10.24
GAS TRANSPORTATION AGREEMENT
----------------------------
THIS AGREEMENT, made and entered into as of this 14th day of June,
1994, by and between MESA Operating Co., a Delaware corporation, acting on
behalf of itself and as agent for Hugoton Capital Limited Partnership
(HCLP) hereinafter collectively referred to as "Shipper," and WESTERN
RESOURCES, INC., a Kansas corporation, hereinafter referred to as WR."
WITNESSETH
----------
WHEREAS, Shipper desires that certain volumes of gas be delivered to
WR, and
WHEREAS, WR is willing on behalf of Shipper to compress and transport
such gas through WR's facilities and deliver such gas for Shipper's account
at the interconnect point(s) specified herein or at such other interconnect
point(s) as may be mutually agreed to between the parties with such
compression and transportation to take place pursuant to this Agreement
between WR and Shipper and with WR to be paid for such compression and
transportation by Shipper as hereinafter set forth; and
WHEREAS, WR is agreeable to compressing and transporting such gas on a
firm basis, in accordance with the terms and conditions hereinafter set
forth.
NOW, THEREFORE, in consideration of the mutual covenants and premises
set forth herein, the parties hereto agree as follows:
ARTICLE I
---------
DEFINITION OF TERMS
-------------------
Except where the content expressly states another meaning, the
following terms, when used in this Agreement shall have the following
meanings:
1.1 The term "day" shall mean a period of twenty-four (24) consecutive
hours beginning and ending at 8:00 a.m. local time.
1.2 The term "month" shall mean the period of time beginning at 8:00
a.m. local time on the first day of the calendar month and ending at 8:00
a.m. local time on the first day of the next succeeding calendar month.
1.3 The term "quarter" shall mean a three-month period beginning
January 1st, April 1st, July 1st or October 1st.
1.4 The term "contract year" shall mean a period of twelve (12)
consecutive months beginning on the first day of the month during the
occurrence of initial deliveries of gas hereunder. The last contract year
of this Agreement shall end at the termination hereof as provided in Article
XI of this Agreement.
1.5 The term "cubic foot" shall mean the volume of gas which occupies
one cubic foot when such gas is at a temperature of sixty degrees Fahrenheit
(60 degrees sign F), and at a pressure of fourteen and sixty-five hundredths
pounds per square inch absolute (14.65 psia) dry and corrected for deviation
from ideal gas behavior.
1.6 The term "MCF" shall mean one thousand (1,000) cubic feet of gas;
the term "MMCF" shall mean one million (1,000,000) cubic feet of gas; and
the term "BCF" shall mean one billion (1,000,000,000) cubic feet of gas.
1.7 The term "British Thermal Unit (BTU)" shall mean the amount of
heat required to raise the temperature of one pound of water from fifty-nine
degrees Fahrenheit (59 degrees sign F) to sixty degrees Fahrenheit (60
degrees sign Fahrenheit) at a pressure of fourteen and sixty-five hundredths
pounds per square inch (14.65 psia). The term "MMBTU" shall mean one
million (1,000,000) BTU.
1.8 The term "gross heating value" means the total calorific value,
expressed as BTU per cubic foot, and obtained pursuant to Paragraph 7.11 of
ARTICLE VII of the amount of gas which would occupy the volume of one cubic
foot on a dry basis.
1.9 The term "gas" shall mean natural gas or a mixture of hydrocarbons
or of hydrocarbons and noncombustible gas, helium or other inerts, in a
gaseous state, consisting predominantly of methane.
<PAGE>
ARTICLE II
----------
DELIVERY AND REDELIVERY
-----------------------
2.1 Subject to the further provisions of this Agreement, Shipper
agrees to deliver to cause to be delivered to WR at the point(s) of
interconnect as set forth Exhibit "A," attached hereto and made a part
hereof, hereinafter called the "Delivery Point(s)," or at such other points
as the parties may mutually agree and place on Exhibit "A," and WR agrees to
accept, compress, transport and redeliver, (i) up to one hundred thirty
(130) MMCF per day of gas on a firm basis during the months of April through
October and up to an additional (thirty) (30) MMCF per day of gas on an
interruptible basis, and (ii) up to one hundred forty-five (145) MMCF per
day of gas on a firm basis during the months of November through March and
up to an additional fifteen (15) MMCF per day of gas on an interruptible
basis. Except for events of force majeure and scheduled maintenance, WR
cannot refuse to accept, compress, transport or redeliver gas delivered by
Shipper on a firm basis up to the maximum firm quantities specified above.
WR shall redeliver volumes of gas, containing the same number of BTU's,
equivalent gallons of ethane and heavier hydrocarbon products, and
equivalent cubic feet of helium as the gas contained when accepted by WR,
except for any reduction for any natural gas liquids which may occur as a
result of natural condensation in the compression or transportation process,
to the point(s) of interconnect as set forth on Exhibit "B," attached hereto
and made a part hereof, hereinafter called the "Redelivery Point(s)," or at
such other points as the parties may mutually agree and place on Exhibit
"B." The acceptance and inclusion of additional Delivery and Re-delivery
Points under this Agreement shall be at WR's sole discretion.
2.2 Shipper shall separately deliver to WR at the outlet of the
Satanta Plant a daily volume of residue gas equivalent to the volume fuel
actually incurred in providing the services hereunder at WR's Ulysses
compressor station and in WR's pipeline facilities between the Delivery and
Redelivery Point(s), up to a maximum of two and thirty-eight hundredths
percent (2.38%) of the volumes accepted from Shipper by WR for compression
and transportation at the Intermediate Delivery Point hereunder. On July 1,
1996, and each succeeding July 1st during the remaining term of this
Agreement, at WR's option, said maximum percentage may be redetermined by
WR. WR shall use its best judgement in redetermining said percentage based
on actual fuel consumption incurred in providing the service hereunder at
WR's Ulysses compressor station and in WR's pipeline facilities between the
Delivery and Redelivery Point(s).
2.3 Commencing on the date of first acceptance by WR of gas at the
Delivery Point(s), and continuing thereafter during the term hereof, WR
shall redeliver at the Redelivery Point(s), volumes of gas containing the
same number of BTU's equivalent gallons of ethane and heavier hydrocarbon
products, and equivalent cubic feet of helium as the gas contained when
accepted by WR, except for any reduction for any natural gas liquids which
may occur as a result of natural condensation in the compression or
transportation process, from Shipper under said Paragraph 2.1 at the
Intermediate Delivery Point. Measurement of gas at the Redelivery Point(s)
shall be through facilities installed, operated and maintained by the party
owning such facility or as new delivery points may be added, by WR or others
as may be designated.
2.4 Delivery and redelivery may be at points through which other
volumes of gas are being measured; therefore, the measurement of the
volumes of gas delivered and redelivered under this Agreement shall be
considered as part of the total volumes measured through the meter. Each
party hereto will furnish or cause to be furnished to the other party hereto
all data required to accurately account for all gas delivered and
redelivered hereunder.
2.5 Nothing in this contract shall require WR to increase the capacity
of the existing compressor station or pipeline system. WR shall sustain the
capacity of the existing compressor station and pipeline system at current
levels and shall maintain such facilities in good working order.
<PAGE>
ARTICLE III
-----------
SCHEDULING, REPORTING AND BALANCING DELIVERIES
----------------------------------------------
3.1 At least ten (10) days prior to the first day of each quarter of
each calendar year, or at such other times as may be mutually agreeable to
the parties hereto, Shipper shall furnish to WR a written schedule showing
the estimated daily quantity of gas it desires to WR to transport hereunder
during each month of the following four quarterly periods. This schedule is
prepared only to allow the parties hereto to schedule maintenance on
compressors and other facilities. Both parties understand and agree that
this schedule reflects estimates only and such estimates may change from
time to time. WR agrees to use its best efforts to schedule and reasonable
commercial efforts to perform maintenance on its compressors and other
facilities in a manner which would allow Shipper to produce the estimated
quantities of gas provided pursuant to this Section 3.1, as such estimates
may change from time to time.
3.2 Shipper shall on a daily basis by nine o'clock (9:00) a.m. or on
some other mutually agreeable basis, verbally advise WR's Gas Control
Department as to the volumes and estimated BTU content of the gas by
delivery point which Shipper desires transported hereunder.
3.3 Either party of its designee owning the measurement facilities
will report or cause to be reported to the other party on a daily basis, the
volumetric activity regarding that delivery or redelivery point. Such
reported volumes will be a field approximation and not of accounting
accuracy.
3.4 Notwithstanding the quarterly estimate discussed in Paragraph 3.1
above, Shipper may nominate, in writing, a transport volume by the 20th of
each month specifying the daily volumes to be transported, and WR shall
notify Shipper, in writing by the 25th of its acceptance of such original
nomination (the Original Nomination). When such Original Nomination is
subsequently modified by both parties, in writing, then such nomination, as
changed, shall nevertheless be deemed the Original Nomination for the
applicable transport month.
3.5 Whenever during any month, Shipper desires to change its
transportation nomination for the remaining day(s) in that month or desires
to change its transportation nomination on a daily basis or for any hour(s)
on any particular day(s), it may do so provided (i) Shipper requires such a
change(s), in writing, at least four hours prior to such change being
effective and (ii) WR accepts such change(s), in writing, within two hours
of Shipper's required change(s) in its nomination(s). WR shall charge the
rate provided for herein on the actual monthly transport volume. If the
actual monthly transport volume is less than ninety percent (90%) of the
Original Nomination, Shipper shall nevertheless pay WR as though ninety
(90%) of the Original Nomination had been transported if (1) such shortfall
was not the result of force majeure, (2) such shortfall was not caused by WR
and (3) WR demonstrates to Shipper that WR was unable to transport such
volumes for other parties for the month as a result of Shipper's Original
Nomination.
3.6 While it is the intent of the parties hereto that gas delivered to
WR hereunder be redelivered concurrently, it is recognized that due to
operating conditions, the volumes of gas delivered may not be equal to the
volume of gas redelivered on any one particular day. The parties shall use
their best efforts to keep such variances to a minimum, and therefore agree
to undertake to balance deliveries and redeliveries monthly on a BTU basis.
Any monthly BTU imbalance shall be eliminated within the next thirty (30)
days or some other mutually agreeable time period. Upon termination of this
Agreement, any party owning gas hereunder shall tender for delivery or
redelivery at the point herein designated the amount of such deficiency
within sixty (60) days from the date of such termination. It is understood
and agreed that there will be complete balancing upon or following
termination of this Agreement and that the provisions of this Paragraph
shall survive the termination of the other portions of this Agreement until
such time as such balancing is attained. Should, after a period of sixty
(60) days, Shipper be unable to eliminate a balance of gas residing in WR's
system due to Shipper's failure to provide for the redelivery of said gas,
then WR shall purchase said gas from Shipper at the spot market price
discussed below, expressed in dollars per MMBTU dry, in effect for the month
said gas is purchased. Should, after a period of sixty (60) days, Shipper
not delver gas to make-up a shortage in its account on WR's system, Shipper
shall pay WR for each MMBTU required to eliminate said shortage at one
hundred five percent (105%) of the spot market price discussed below,
expressed in dollars per MMBTU dry, in effect for the month in which the
shortage is eliminated. Said spot market price shall be equal to the
arithmetic average of the five (5) "Index" MMBTU price postings representing
deliveries to the pipeline systems of ANR Pipeline Co. (Oklahoma region),
Natural Gas Pipeline Co. of America (Oklahoma and Kansas region), Northern
Natural Gas Co. (Texas, Oklahoma and Kansas region), Panhandle Eastern
Pipeline Co. (Texas and Oklahoma region) and the Williams Natural Gas Co.
(Texas, Oklahoma and Kansas region) as reported in the first issue of Inside
FERC Gas Marketing Report for the month in which said gas is purchased by WR
or said shortage is eliminated by Shipper, respectively.
ARTICLE IV
----------
QUANTITY
--------
4.1 Shipper shall deliver to WR each contract year a minimum quantity
of twenty (20) BCF at the Delivery Point(s), with daily quantities delivered
to and accepted by WR at the Delivery Point(s) up to the maximum quantities
as specified in Section 2.1.
4.2 It is understood that WR is currently obligated to transport up to
thirteen (13) MMCF per day on a firm basis for other customers from the
Initial Delivery Point to the Final Redelivery Point. In the event
insufficient firm capacity is available to transport both the quantities
specified in Section 2.1 and the firm quantity stated above which WR is
currently obligated to serve, the total available firm capacity will be
allocated among WR's firm customers based on the ratio between each
customer's firm (MDQ's) WR is obligated to serve. Notwithstanding the
above, the total available firm capacity allocated to Shipper will not be
less than ninety-one and eight tenths percent (91.8%) of the total available
firm capacity in the months of November through March and will not be less
than ninety and nine tenths percent (90.9%) of the total available firm
capacity in the months of April through October.
ARTICLE V
---------
QUALITY
-------
5.1 All natural gas delivered and redelivered under the terms of this
Agreement shall be of merchantable quality and conform to the following
specifications:
(a) Oxygen - the gas shall be free of oxygen
(b) Hydrogen Sulfide - the hydrogen sulfide content shall not exceed
one quarter (1/4) grain per one hundred (100) cubic feet).
(c) Carbon Dioxide - the carbon dioxide content shall not exceed five
hundred (500) parts per million.
(d) Liquids - the gas shall be free of water and hydrocarbons in
liquid form at the temperature and pressure at which the gas is
delivered. the gas delivered at the Intermediate Delivery Point
and the Final Redelivery Point shall in no event contain water
vapor in excess of seven pounds (7#) per million cubic feet.
(e) Dust, Gums and Solid Matter - the gas shall be commercially free
of dust, gum and other solid matter.
(f) Heating Value - the gas shall have a heating content of not less
than nine hundred and fifty (950) BTU per cubic foot at fourteen
and seventy-three hundredths pounds per square inch absolute
(14.73 psia) saturated.
(g) Total Sulphur - the gas shall not contain more than twenty (20)
grains of total sulphur per one hundred (100) cubic feet of gas as
determined by a method generally acceptable for use in the gas
industry.
5.2 If, at any time, gas tendered for delivery and/or redelivery
hereunder shall fail to conform to any of the quality specifications set
forth above, the receiving party may, at its option, refuse to accept
delivery and/or redelivery and be absolved of any further obligation to
perform, pending correction of the deficiency by the delivering party. The
receiving party shall notify the delivery party of the deficiency as soon as
possible after its occurrence. However, if Shipper delivers to WR gas which
conforms to all of the quality specifications set forth above, the WR must
redeliver to Shipper gas which conforms to all of the quality specifications
set forth above and WR will perform whatever work is required to cause the
gas to meet such quality specifications.
ARTICLE VI
----------
PRESSURES
---------
6.1 Shipper shall deliver gas to WR at the Initial Delivery Point at a
pressure of not less than one hundred (100) psig. After compression by WR,
the gas shall be delivered to Shipper at the Intermediate Redelivery Point
at a pressure not more than six hundred (600) psig nor less than five
hundred (500) psig. After dehydration or processing by Shipper, the
pressure of the gas or residue gas redelivered to WR at the Intermediate
Delivery Point shall not decline by more than ten (10) psi if dehydrated
only, or more than twenty-five (25) psi if dehydrated and processed from the
pressure such gas was delivered at the Intermediate Redelivery Point. WR
shall deliver gas dehydrated by Shipper, back to Shipper at the inlet to the
Satanta Processing Plant at a pressure of not less than four hundred ninety
(490) psig.
ARTICLE VII
-----------
MEASUREMENT AND HEATING VALUE DETERMINATION
-------------------------------------------
7.1 Gas delivered to WR under this Agreement shall be measured at
prevailing meter pressures and the volumes thereof shall be calculated and
accounted for as between the parties hereto on the basis of a standard cubic
foot of gas at a pressure of fourteen and sixty-five hundredths pounds per
square inch (14.65 psia) and a temperature of sixty degrees Fahrenheit (60
degrees sign F), computed in accordance with Boyle's Law governing pressure
and volume of gases (with correction for deviation as hereinafter provided).
7.2 Gas redelivered under this Agreement by WR shall be measured and
calculated by the party owning said measurement facilities or his designee
at the point(s) of redelivery as described in Exhibit "B." The basis of
measurement shall be as described in Paragraph 7.1 above. All delivery and
re-delivery measurement shall be expressed or re-expressed on the same
pressure base for balancing and billing purposes as provided for herein.
7.3 Gas volumes and BTU/CF measurements shall be corrected to reflect
the actual water vapor content of the gas as delivered or redelivered. Any
gas which contains water vapor of seven pounds (7#) per MMCF or less shall
be deemed "dry".
7.4 The specific gravity of the gas delivered or redelivered hereunder
shall be determined by the party currently operating the measurement
facilities as often as is found necessary in practice and in accordance with
an approved method, provided that such test shall be preceded by reasonable
notice to the other parties in order that they may have a representative
present.
7.5 The temperature of the gas delivered and redelivered hereunder
shall be determined by means of recording thermometers of standard
manufacture so installed that they may properly record the temperature of
the gas delivered and redelivered through meters. The arithmetical average
of the hourly temperature recorded for each period shall be used in
correcting the volume of gas measured during said period to the standard
provided in Paragraph 7.1 and 7.2 above.
7.6 The deviation of the gas from Boyle's Law at the pressure and
temperatures at which the gas is measured shall be by tests and analyses
performed as often as the parties hereto deem necessary. The method of
making such tests or analyses shall be determined by mutual agreement.
7.7 It is assumed and agreed that the values of the Reynolds number
factor and the expansion factor are ONE (1).
7.8 The pressure and uncorrected volumes of gas delivered and
redelivered hereunder shall be measured by standard type metering equipment
constructed as required by WR, at the Point(s) of Delivery and Redelivery
hereunder. Orifice metering facilities shall be constructed in accordance
with Gas Measurement Committee Report No. 3, dated April 1955, of the
Natural Gas Department of the American Gas Association and any subsequent
amendments thereof which are mutually agreeable to the parties hereto, and
volumes shall be calculated in accordance with said Gas Measurement
Committee Report No. 3, or as hereafter amended.
7.9 Either party shall have access to the metering equipment at all
reasonable times, but calibrations and adjustments thereof and changing of
charts shall be done by the employees or agents of the owning party and such
party shall change the charts in accordance with good practice and shall
keep said meters accurate and in good repair. The meters shall be tested
and calibrated by the owning party monthly, or as often as is found
necessary in practice, provided that such tests shall be preceded by
reasonable notice to the parties in order that the parties may have
representatives present. Either party may challenge the accuracy of any
meter and if, after testing, such meter is found by the owning party to be
inaccurate by an amount exceeding one percent (1%), high or low, then said
party shall repair the meter and make the necessary volume corrections,
based on the extent of the inaccuracy and adjusting back to zero percent
(0%), for the time the meter has been inaccurate, provided that in no event
shall corrections extend back beyond the date of the preceding tests. If
the meter, when challenged, is found to be accurate within one percent (1%),
high or low, then the cost of the test shall be borne by the requesting
party and the meter shall be repaired to measure accurately. If for any
reason any meter shall be out of service or repair so that the amount of gas
delivered cannot be ascertained or computed from the reading thereof, the
gas delivered during the period the meter is out of service or repair shall
be estimated and agreed upon by the parties upon the basis of the best data
available suing the first of the following methods which is feasible: (1)
By using the registration of any check meter(s) installed and accurately
measuring; (2) By correcting the error if the percentage of error is
ascertainable by calibration, test or mathematical calculation; (3) By
estimating the quantity of delivery by deliveries during preceding periods
under similar conditions when the meter was registering accurately. If the
period that the meter is out of service or repair not known or agreed upon,
the correction shall be made for a period equal to one half (1/2) the time
since the date of the last test, but not exceeding thirty (30) days.
7.10 The charts and records from the metering equipment shall remain
the property of the owning party but, upon request of the other party, the
owning party shall submit same to the other party together with calculations
therefrom, for such party's inspection and verification, subject to return
within twenty (20) days from receipt thereof, after which the charts and
records shall be kept on file by the owning party for a period of time not
less than specified by Kansas law and may then, at the owning party's
option, be destroyed.
7.11 The gross heating value of the gas delivered and redelivered
hereunder shall be determined monthly by gas chromatography from a
continuous sample of the gas taken at the Intermediate Delivery Point. From
this analysis, a determination of the gross heating value will be made in
accordance with the latest published procedures by the Gas Processors
Association. The continuous sample will be taken such that the monthly
measured volume and monthly BTU/CF content are for the same period and will
be used together in payment calculations for the gas delivered to WR and
redelivered by WR.
7.12 In the event daily BTU calculations are required, the monthly
BTU/CF determination derived from the analysis of the monthly continuous or
periodic sample would be applicable to each and every daily volume in the
given month. As an alternative to gas chromatography, WR may determine the
gross heating value of the monthly continuous or periodic sample by a
calorimeter employing the Thomas Principle of Calorimetry described in
Research Paper #519 published by the U.S. Department of Commerce. In the
event a continuous sample is lost or inadvertently destroyed, the previous
month's gross heating value will be applied unless a mutually agreeable
alternate source of accurate data is available for that month. All tests
and analyses of samples shall be preceded by reasonable notice to the other
party in order that such party may have a representative present.
7.13 If during the term hereof, any new and improved method or
technique is developed for gas measurement or for determination of factors
used in gas measurement, such new and improved method or technique may be
substituted for the gas measurement described herein by mutual agreement of
the parties.
ARTICLE VIII
------------
RATES
-----
8.1 For gas transported on behalf of Shipper hereunder, Shipper shall
pay WR a transportation rate equal to six cents ($.06) for each MCF of gas
transported from the Initial Delivery Point to the Final Redelivery Point
based on the volumes of gas actually delivered by WR for Shipper's account
at the Final Redelivery Point. The transportation rate shall escalate at
four percent (4%) on each annual anniversary date beginning June 1, 1996.
8.2 The parties hereto agree that transportation of gas hereunder
shall not include storage service.
8.3 Should it appear to WR that it will be required to incur
additional costs of any kind, excluding property, ad valorem, franchise and
income taxes and costs of administering this agreement or operating,
maintaining, or replacing existing capacity, equipment, pipelines, or
facilities used and useful in the performance of this Agreement and not
otherwise identified in this Agreement, WR shall advise Shipper of its
estimate of such costs with supporting workpapers, the reasons such costs
are expected to be incurred to provide service, and the changes required in
Shipper's nominations and scheduling of gas transportation needed to avoid
incurrence of such costs in writing before WR incurs such costs. Shipper
shall have the right to alter its nominations and schedules to avoid the
necessity for WR to incur such additional costs. The notice provided for in
this Section 8.3 will allow Shipper a reasonable time, not less than thirty
(30) business days, in which to take action to avoid the incurrence of such
costs by WR. If Shipper does not take appropriate action in the period
specified in the notice, WR will be authorized to increase the rates and
charges to Shipper hereunder in an amount sufficient to allow it to recover
such additional costs over the then-remaining term of this agreement.
8.4 In each contract year during the term of this Agreement, Shipper
shall purchase or pay for an annual quantity of natural gas transportation
service equal to the minimum annual quantity specified in Article IV (20 BCF
per contract year) at the then effective transportation rate. If Shipper
transports less than the annual minimum amount and such deficiency was not
caused by WR, WR shall, in its first invoice after the end of the applicable
contract year, invoice Shipper for the difference between Shipper's actual
annual transportation quantity and such minimum annual quantity in the
applicable contract year at the transportation rate in effect in the last
month of the applicable contract year and Shipper shall be obligated to pay
such charges. In any contract year after Shipper has, by virtue of this
Paragraph 8.4, been required to pay transportation charges for volumes not
transported, Shipper may transport such deficient volumes on an
interruptible basis by providing WR written notice of the volume to be
transported hereunder and subject to the availability of capacity to
transport such volumes. Shipper may not transport such deficient volumes
hereunder in any contract year until it shall have first transported under
this Agreement the minimum annual quantity Specified in Article IV for that
contract year. In connection with the transportation of such deficient
volumes, Shipper shall, in addition to the charges previously paid to WR,
pay WR the difference between the transportation rate in effect hereunder
when such volumes are actually transported and the rate which was in effect
and applied to such deficient volumes at the time such deficiency was
incurred. Shipper shall have six (6) months after termination of the
Agreement to make up any deficient volumes that may have previously
occurred.
ARTICLE IX
----------
BILLING AND PAYMENT
-------------------
9.1 Following the commencement of deliveries and redeliveries pursuant
to Paragraph 2.1 and 2.3 herein, WR shall on or before the tenth (10th) day
of each month submit to Shipper a statement of the total MCF and MMBTU of
gas delivered and redelivered pursuant to this Agreement during the
preceding months as well as a billing for the transportation fee as
determined in accordance with Article VII herein.
9.2 Shipper shall pay WR the amount shown as due by such billing
within fifteen (15) days from the date of receipt of said statement, or by
the twenty-fifth (25th) day of the month, whichever is later.
9.3 Each party shall have the right at all reasonable times to examine
the books, records, and charts of the other party to the extent necessary to
verify the accuracy of any statement, charge, computation or demand made
under or pursuant to any of the provisions of this contract.
9.4 If an error should be discovered in any billing, such error shall
be adjusted within thirty (30) days of the determination thereof, provided
that claim therefor shall have been made in writing within twenty-four (24)
months from the date of such billing.
ARTICLE X
---------
INDEMNIFICATION
---------------
10.1 As between the parties hereto, Shipper shall be deemed to be in
control and possession of the gas deliverable hereunder and responsible for
any loss, claim, demands, expenses, damages or injuries caused thereby,
except those occasioned solely by the negligence of WR, until the same shall
have been delivered to WR at the points of delivery provided for herein, and
Shipper fully indemnifies and holds WR harmless with respect thereto. As
between the parties hereto, after delivery of such gas, WR shall be deemed
to be in exclusive control and possession of the gas and responsible for any
loss, claims, demands, expenses, injuries or damages caused thereby, except
for those occasioned solely by the negligence of Shipper, and WR fully
indemnifies and holds Shipper harmless with respect thereto.
10.2 Shipper warrants the gas delivered to WR for redelivery shall be
free from all adverse claims, liens and encumbrances. The party having
control and possession of the gas shall do all things necessary to prevent
and void any adverse claims, liens or encumbrances on the gas and shall
indemnify and save harmless the other party from and against all suits,
action, causes of action, claims and demands arising from or out of any
adverse claims by third parties claiming ownership of or an interest in the
gas which is delivered or of the account of the other party under this
Agreement, and which are caused by the failure to so protect clear title of
the gas.
ARTICLE XI
----------
TERM
----
11.1 The term of this agreement shall be for a primary period of five
(5) contract years from June 1, 1995, and shall continue in effect from
year-to-year thereafter; provided, however, after the primary period, either
party, by giving twelve (12) months' written notice to the other party prior
to an anniversary date may cancel and terminate this agreement without
further liability hereunder, except as to any then existing imbalance,
outstanding bill and the warranties expressed in Section 10.2.
ARTICLE XII
-----------
PROCESSING RIGHTS
-----------------
12.1 Shipper shall retain all processing rights associated with the
gas to be transported hereunder. WR will not process any gas delivered to
it by Shipper. WR will redeliver to Shipper a volume of gas containing the
same number of BTU's, equivalent gallons of ethane and heavier hydrocarbon
components and equivalent cubic feet of helium as the gas contained when
accepted by WR, except for any reduction for any natural gas liquids which
may occur as a result of natural condensation in the compression or
transportation process. Such natural gas liquids recovered shall be
delivered for Shipper's account to MESA's Satanta Plant facilities.
ARTICLE XIII
------------
DISPUTE RESOLUTION
------------------
13.1 DISPUTE RESOLUTION. No party to this Agreement shall be entitled
to take legal action with respect to any dispute relating hereto until it
has complied in good faith with the following alternative dispute resolution
procedures. This Section 13.1 shall not apply if it is deemed necessary to
take legal action immediately to preserve a party's adequate remedy.
13.2 Negotiation. The parties shall attempt promptly and in good
faith to resolve any dispute arising out of or relating to this Agreement,
through negotiations between representatives who have authority to settle
the controversy. Any party may give the other party(ies) written notice of
any such dispute not resolved in the normal course of business. Within
twenty (20) days after delivery of such notice, representatives of both
parties shall meet at a mutually acceptable time and place, and thereafter
as often as they reasonable deem necessary, to exchange information and to
attempt to resolve the dispute, until the parties conclude that the dispute
cannot be resolved through unassisted negotiation. Negotiations extending
sixty (60) days after notice shall be deemed at an impasse, unless otherwise
agreed by the parties.
13.3 If a negotiator intends to be accompanied at a meeting by an
attorney, the other negotiator(s) shall be given at least three (3) working
days' notice of such intention and may also be accompanied by an attorney.
All negotiations pursuant to this clause are confidential and shall be
treated as compromise and settlement negotiations for purposes of the
Federal and State Rules of Evidence.
13.4 ADR Procedure. If a dispute with more than twenty thousand
dollars ($20,000.00) at issue has not been resolved within sixty (60) days
of the disputing party's notice, a party wishing resolution of the dispute
("Claimant") shall initiate assisted Alternative Dispute Resolution (ADR)
proceedings as described in this Section 13.4. Once the Claimant has
notified the other ("Respondent") of a desire to initiate ADR proceedings,
the proceedings shall be governed as follows: By mutual agreement, the
parties shall select the ADR method they wish to use. The ADR method may
include arbitration, mediation, mini-trial, or any other method which best
suits the circumstances of the dispute. The parties shall agree in writing
to the chosen ADR method and the procedural rules to be followed within
thirty (30) days after receipt of notice of intent to initiate ADR
proceedings. To the extent the parties are unable to agree on procedural
rules in whole or in part, the current Center for Public Resources (CPR)
Model Procedure for Mediation of Business Disputes, CPR Model Mini-trial
Procedure, or CPR Commercial Arbitration Rules--whichever applies to the
chosen ADR method--shall control, to the extent such rules are consistent
with the provisions of this Section 13.4. If the parties are unable to
agree on an ADR method, the method shall be arbitration.
13.5 The parties shall select a single Neutral third party to preside
over the ADR proceedings, by the following procedure: within fifteen (15)
days after an ADR method is established, the Claimant shall submit a list of
five (5) acceptable Neutrals to the Respondent. Each Neutral listed shall
be sufficiently qualified, including demonstrated neutrality, experience and
competence regarding the subject matter of the dispute. A Neutral shall be
deemed to have adequate experience if an attorney or former judge. None of
the Neutrals may be present or former employees, attorneys or agents of
either party. The list shall supply information about each Neutral,
including address, and relevant background and experience (including
education, employment history and prior ADR assignments). Within fifteen
(15) days after receiving the Claimant's list of Neutrals, the Respondent
shall select one Neutral from the list, if at least one individual on the
list is acceptable to the Respondent. If none on the list are acceptable to
the Respondent, the Respondent shall submit a list of five (5) Neutrals,
together with the above background information, to the Claimant. Each of
the Neutrals shall meet the conditions stated above regarding Claimant's
Neutrals. Within fifteen (15) days after receiving the Respondent's list of
Neutrals, the Claimant shall select one Neutral, if at least one individual
on the list is acceptable to the Respondent. If none on the list are
acceptable to the Claimant, then the parties shall request assistance from
the Center for Public Resources, Inc., to select a Neutral.
13.6 The ADR proceeding shall take place within thirty (30) days after
the Neutral has been selected. The Neutral shall issue a written decision
within thirty (30) days after the ADR proceeding is complete. Each party
shall be responsible for an equal share of the costs of the ADR proceeding.
The parties agree that any applicable statute of limitations shall be tolled
during the pendency of the ADR proceedings, and no legal action may be
brought in connection with this agreement during the pendency of an ADR
proceeding.
13.7 The Neutral's written decision shall become final and binding on
the parties, unless a party objects in writing within thirty (30) days of
receipt of the decision. The objecting party may then file a lawsuit in any
court allowed by this Agreement. The Neutral's written decision shall be
admissible in the objecting party's lawsuit.
ARTICLE XIV
-----------
REGULATORY AUTHORIZATIONS
-------------------------
14.1 The transportation of gas hereunder is made pursuant to the
authority under WR's certificate of convenience and necessity granted by the
Kansas Corporation Commission. If at any time during the term of this
Agreement, any governmental authority shall take action as to WR, excluding
however, any action relating to the rates prescribed under Article VIII or
the costs of providing the services hereunder, and/or Shipper whereby the
sale/purchase or transportation of gas hereunder is prescribed or subject to
conditions or restraint that, in the sole judgment of the party affected is
unacceptable, such party, upon written notice to the other, may cancel and
terminate this Agreement without further liability hereunder, except as to
any then existing imbalance, outstanding bill and the warranties expressed
in Section 10.2 herein. Any obligations of Shipper under Section 8.4 herein
shall automatically cease for that contract year and any subsequent contract
year.
14.2 The parties hereto shall respectively proceed with diligence in
the preparation, filing and prosecution of any applications, filings and
notices with federal and/or other governmental agencies as may be required.
Each party shall promptly provide the other with a copy of all applications,
filings, notices, and approvals. Shipper agrees to reimburse WR for any
filing fees imposed by regulatory agencies upon such filing.
14.3 If required, WR shall, pursuant to the rules and regulations
promulgated by the regulatory agency having authority, promptly file for
approval of the rates prescribed under Article VIII. In the event any such
filling is not approved within sixty (60) days of the execution of this
Agreement, WR or Shipper shall have the right to terminate this Agreement
effective upon written notice given to one by the other.
14.4 If at any time during the term of this Agreement, WR and Shipper
mutually agree upon changes in the rates prescribed under Article VIII, WR
shall promptly file for the approval of such revised rates. In the event
any such filing shall be disapproved, WR and Shipper shall attempt to agree
upon new rates. Should WR and Shipper be unable to agree upon new rates
within a period of sixty (60) days after the disapproval of such rates by
the regulatory agency having jurisdiction, then either party, by giving
twelve (12) months written notice to the other party, may cancel and
terminate this Agreement. Absent approval of revised rates, the existing
(old) rates shall remain in effect while this Agreement remains effective.
ARTICLE XV
----------
NOTICES
-------
15.1 Any formal notice, request or demand which either party may
desire to give to the other respecting this Agreement, shall be in writing
and shall be considered as duly delivered when mailed by registered or
certified mail by said party to the other party hereto, as follows:
NOTICE AND PAYMENTS:
MESA Operating Co.
5205 N. O'Connor Blvd, Suite 1400
Irving, Texas 75039-3746
Attn: Marketing Department
Facsimile: (214) 444-4394
NOTICES:
WESTERN RESOURCES, INC.
P. O. Box 889
Topeka, Kansas 66601
Attn.: Gas Supply
Gas Control Facsimile: 913-575-8137
PAYMENTS:
WESTERN RESOURCES, INC.
P.O. Box 758500
Topeka, KS 66675-8500
or to such other address as either party shall designate by formal written
notice. Routine communications shall be considered as duly delivered as of
the postmarked date when mailed by ordinary mail. Nominations and
confirmations thereof may be made by facsimile. Operating communications by
telephone or other mutually agreeable means shall be considered as duly
delivered without subsequent written confirmation, unless written
confirmation is requested by either party.
ARTICLE XI
----------
FORCE MAJEURE
-------------
16.1 Neither party shall be liable for failure of performance (other
than to make payments due hereunder) due to labor controversies, fires,
strikes, floods, lack of water, winds, lightning, accidents, required
maintenance and repair of equipment and lines of pipe, the inability of any
party hereto to obtain right-of-way grants necessary to enable such party to
fulfill any obligation hereunder, or the delay or failure on the party of
such party in acquiring such right-of-way grants due to cost, which in the
opinion of such party is unreasonable or excessive, or any other
circumstances beyond the control of the party failing to perform, whether of
similar or dissimilar nature. Settlement of strikes and lockouts shall be
wholly within the discretion of the party involved in any such strike or
lockout.
Failure by Shipper or WR to meet the quality, reliability and
measurement standards provided herein shall not constitute force majeure.
Immediately upon becoming aware of the occurrence or termination of an
event of force majeure, the party claiming force majeure shall give notice
thereof to the other party describing such event.
ARTICLE XVII
------------
LAWS AND REGULATIONS
--------------------
17.1 This Agreement shall be subject to all valid statutes and valid
rules and regulations of any duly constituted Federal or State regulatory
body having jurisdiction herein.
<PAGE>
ARTICLE XVIII
-------------
NONWAIVER OF FUTURE DEFAULT
---------------------------
18.1 No waiver by any party of any one or more defaults by the other
in performance of any of the provisions of this Agreement shall operate or
be construed as a waiver of any other existing or future default or
defaults, whether of a like or of a different character.
ARTICLE XIX
-----------
SUCCESSORS AND ASSIGNS
----------------------
19.1 Any company which shall succeed by purchase, merger of
consolidation to the properties or which shall take tile, at the wellhead,
of the gas transported hereunder, substantially as an entirety, shall be
subject to the obligations of its predecessor in title under this Agreement.
No other assignment of this Agreement or any of the rights or obligations
hereunder shall be made unless there first shall have been obtained the
consent thereto of the other party, which such consent shall not be
unreasonably withheld. Furthermore, either party may assign the interest in
and to and under this Agreement to a trustee or trustees, individual or
corporate, as security for bonds or other obligations or securities without
the necessity of any such assignee becoming in any respect obligated to
perform the obligation of the assignor under this Agreement and, if any such
trustee be a corporation, without its being required to qualify to do
business in any state in which performance of this Agreement may occur.
ARTICLE XX
----------
DEHYDRATION FUEL AGREEMENT
--------------------------
20.1 This Agreement does not modify the obligations of WR or HCLP
under the terms of the Dehydration Fuel Agreement dated April 16, 1993.
<PAGE>
ARTICLE XXI
-----------
COMPRESSION OF GAS BY SHIPPER
-----------------------------
21.1 In the event WR's compression capacity is being fully utilized,
Shipper may provide compression services on an interruptible basis for gas
being transported by WR. Shipper may stop providing compression services in
whole or in party at any time for any reason. WR shall pay Shipper five
cents ($0.05) plus fuel for each MCF of gas compressed by Shipper and
delivered to the Intermediate Redelivery Point. Such gas compressed by
Shipper shall be measured at the inlet to Shipper's compression facilities
in accordance with the measurement procedures set forth in Article VII
herein.
ARTICLE XXII
------------
MISCELLANEOUS
-------------
22.1 Any modification of terms or amendments of provisions of this
agreement shall become effective only by supplemental written agreement
between the parties hereto.
22.2 As to all matters of construction and interpretation, this
Agreement shall be interpreted, construed and governed by the laws of the
State of Kansas.
22.3 Transportation hereunder shall be effected pursuant to any and
all applicable regulations, of the regulatory agency having authority, and
the parties hereto agree to comply with all said regulations in their
performance of this Agreement.
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused two (2) originals of
this Agreement to be executed, by their officers duly authorized, as of the
day and year first hereinabove written.
WESTERN RESOURCES, INC.
WITNESS:
/s/ Larry G. Willer(?) By: /s/ R. H. Tangeman
----------------------- ------------------------------------
R. H. Tangeman,
Assistant Vice President, Gas Supply
WITNESS:
MESA OPERATING CO. acting on behalf of
/s/ D'Nard Hemphill itself and as agent for Hugoton Capital
----------------------- Limited Partnership
By: /s/ Paul W. Cain
------------------------------------
Title: Paul W. Cain
-----------------------------------
President
<PAGE>
Exhibit "A"
to
Gas Transport 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
Delivery Points
---------------
Initial Delivery Point -
Interconnect between Shipper and WR at the inlet of WR's Ulysses
compressor station located in Grant County, Kansas (Sec. 10-T30S-R37W).
Intermediate Delivery Point -
Interconnect between Shipper and WR at the outlet of Shipper's Ulysses
Processing Plant located in Grant County, Kansas (Sec. 10-T30S-R37W).
<PAGE>
Exhibit "B"
to
Gas Transport 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
Redelivery Points
-----------------
Intermediate Redelivery Point -
Interconnect between WR and the inlet of Shipper's Ulysses Processing Plant
located in Grant County, Kansas (Sec. 10-T30S-R37W).
Final Redelivery Point -
Interconnect between WR and the inlet to Shipper's Satanta Processing Plant
in Grant County, Kansas (Sec. 5-T30S-R35W).
EXHIBIT 22
MESA INC.
Subsidiaries
As of December 31, 1994 Place of Incorporation
----------------------- ----------------------
Subsidiary Corporations:
Garretson Equipment Co., Inc. Iowa
Hugoton Capital Corporation Delaware
Hugoton Management Company Texas
Mesa Capital Corporation Delaware
Mesa Environmental Ventures Co. Delaware
Mesa Holding Co. Delaware
Mesa Operating Co. Delaware
Mesa Transmission Co. Delaware
Pioneer Natural Gas Company Texas
Pioneer Production Corporation International Texas
Pioneer Uravan, Inc. Texas
Subsidiary Limited Partnership:
Hugoton Capital Limited Partnership Delaware
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND> THIS SCHEDULE CONTAINS SUMMARY FINANCIAL
INFORMATION EXTRACTED FROM THE MESA INC. AND
SUBSIDIARIES DECEMBER 31, 1994 FINANCIAL
STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<CASH> 143,422
<SECURITIES> 19,112
<RECEIVABLES> 41,006
<ALLOWANCES> 3,168
<INVENTORY> 1,987
<CURRENT-ASSETS> 204,844
<PP&E> 1,911,678
<DEPRECIATION> 781,230
<TOTAL-ASSETS> 1,483,959
<CURRENT-LIABILITIES> 89,189
<BONDS> 1,192,756
0
0
<COMMON> 640
<OTHER-SE> 123,932
<TOTAL-LIABILITY-AND-EQUITY> 1,483,959
<SALES> 228,737
<TOTAL-REVENUES> 228,737
<CGS> 0
<TOTAL-COSTS> 200,054
<OTHER-EXPENSES> 112,036
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 144,757
<INCOME-PRETAX> (83,353)
<INCOME-TAX> 0
<INCOME-CONTINUING> (83,353)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (83,353)
<EPS-PRIMARY> (1.42)
<EPS-DILUTED> (1.42)
</TABLE>
EXHIBIT 28
SUMMARY REPORT
dated
FEBRUARY 28, 1995
on
RESERVES and REVENUE
as of
DECEMBER 31, 1994
from
CERTAIN PROPERTIES
owned by
MESA OPERATING CO.
MESA HOLDING CO.
and
HUGOTON MANAGEMENT CO.
MESA Inc. has prepared estimates, as of December 31, 1994, of the extent and
value of the proved crude oil, condensate, natural gas liquids, natural gas,
helium, and carbon dioxide reserves of certain properties owned by Mesa
Operating Co. (MOC), Mesa Holding Co. (MHC) and Hugoton Management Co.
(HMC). MESA Inc., a Texas corporation, is the sole owner of three
subsidiary corporations as of the date hereof. These three subsidiaries
are:
1. MOC, which holds title to most of the appraised properties and a
98.6 percent interest in Hugoton Capital Limited Partnership
(HCLP);
2. MHC, which holds .9 percent of HCLP; and
3. HMC, which holds .5 percent of HCLP.
Together, MOC, MHC and HMC own 100 percent of HCLP, which owns most of the
appraised properties in the Hugoton and Panoma fields. Tabulations of
reserves and revenue from the Texas Panhandle properties, all minor
properties, and Mesa Offshore Trust properties included in this report show
the interest of MESA Inc. while tabulations of reserves and revenue from the
Hugoton Area and the Mesa Royalty Trust properties show the collective
interests of Hugoton Capital Limited Partnership hereinafter referred to as
"HCLP". The properties appraised are in the property groups listed below.
The HCLP Hugoton Area -- Kansas Hugoton and Panoma Fields
HCLP Share -- Mesa Royalty Trust Properties
The Hugoton Area (non-HCLP Royalties)
The Texas Panhandle -- Contract "B" and Royalty
The Texas Panhandle -- Other
Remaining MESA interests in the Mesa Offshore Trust Properties.
The Gulf Coast Area
The Rocky Mountain Area
The HCLP share -- Mesa Royalty Trust Properties are located in the Hugoton
and Panoma fields in Kansas. These properties are burdened by a 10.29282
percent net royalty interest owned by the Mesa Royalty Trust and a .0057
percent overriding royalty interest owned by others. The remaining MESA
Inc. interests in the Mesa Offshore Trust Properties consist of the
remaining interests of MESA Inc. after the transfer (effective December 1,
1982) to the Mesa Offshore Royalty Partnership, a partnership owned 99.99
percent by the Mesa Offshore Trust, of a 90 percent net profits interest in
10 MESA Inc. leases located in the Gulf of Mexico offshore from Louisiana
and Texas.
The reserve estimates are based on a detailed study of MESA Inc.'s
properties and were prepared by the use of standard geological and
engineering methods generally accepted by the petroleum industry. The
method or combination of methods utilized in the analysis of each reservoir
was tempered by experience in the area, quality and completeness of basic
data, and production history.
Reserves in this report are expressed as net reserves. Gross reserves are
defined as the total estimated petroleum hydrocarbons including helium
remaining to be produced after December 31, 1994. Net reserves are defined
as that portion of the gross reserves attributable to the interest owned by
MESA Inc. after deducting royalties and other interests owned by others. In
making these reserve estimates, all interest reversions were taken into
account.
Values shown herein are expressed in terms of future gross revenue, future
net revenue, and present worth. Future gross revenue is that revenue which
will accrue to the appraised interests from the production and sale of the
estimated net reserves. Future net revenue is calculated by deducting
estimated production taxes, ad valorem taxes, operating expenses, and
capital costs from the future gross revenue. Future income tax expenses
were not taken into account in the preparation of these estimates. Present
worth is defined as future net revenue discounted at a specified arbitrary
discount rate compounded monthly over the expected period of realization.
In this report, present worth values using a discount rate of 10 percent are
reported.
Estimates of reserves and future net revenue should be regarded only as
estimates that may change as further production history and additional
information become available. Not only are such reserve and revenue
estimates based on that information which is currently available, but such
estimates are also subject to the uncertainties inherent in the application
of judgmental factors in interpreting such information.
Data used in the preparation of MESA Inc.'s portion of this report were
obtained from MESA Inc.'s records and from reports filed with the regulatory
agencies of the states or areas in which the properties are located.
The development status shown herein represents the status applicable on
December 31, 1994. In the preparation of the study, data available from
wells drilled on the appraised properties through December 31, 1994 were
used in estimating gross ultimate recovery. Gross production estimated to
December 31, 1994, was deducted from gross ultimate recovery to arrive at
the estimates of gross reserves. In some fields, this required that the
production rates be estimated for up to seven months since production data
for certain properties were available only through May 1994.
Reserves and revenue values shown in this report for the HCLP Share -- Mesa
Royalty Trust Properties and the Remaining MESA Inc. interests in the Mesa
Offshore Trust Properties were estimated from projections of reserves and
revenue attributable to the combined HCLP Share and Mesa Royalty Trust
interests or the combined Remaining MESA Inc. and Mesa Offshore Royalty
Partnership interests. Reserves attributable to the trust interests in each
of the royalty trusts were estimated by allocating a portion of the
estimated combined net reserves of each of the property groups based on
future net revenue. The estimated reserves for each of the trusts were
subtracted from the combined net reserves for each trust to arrive at the
estimated reserves of MESA Inc. and HCLP in the trust properties.
Since the reserve volumes attributable to the MESA Inc. interests in the
trust properties are estimated using an allocation of reserves based on
estimates of future revenue, a change in prices or costs will result in
changes in the estimated reserves of MESA Inc. and HCLP.
Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs
under existing economic and operating conditions and assuming continuation
of current regulatory practices using conventional production methods and
equipment. In the analyses of production decline curves, reserves were
estimated only to the limit of economic rates of production under existing
economic and operating conditions using prices and costs as of the date the
estimate is made, including consideration of changes in existing prices
provided only by contractual arrangements but not including escalations
based upon future conditions. The petroleum reserves are classified as
follows:
Proved
------ -- Reserves that have been proved to a high degree of
certainty by analysis of the producing history of a reservoir and/or by
volumetric analysis of adequate geological and engineering data.
Commercial productivity has been established by actual production,
successful testing, or in certain cases by favorable core analyses and
electrical-log interpretation when the producing characteristics of the
formation are known from nearby fields. Volumetrically, the structure,
areal extent, volume, and characteristics of the reservoir are well
defined by a reasonable interpretation of adequate subsurface well
control and by known continuity of hydrocarbon-saturated material above
known fluid contacts, if any, or above the lowest known structural
occurrence of hydrocarbons.
Developed
--------- -- Reserves that are recoverable from existing wells with
current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells
producing from present completion intervals with normal operating
methods and expenses. Developed nonproducing reserves are in
reservoirs behind the casing or at minor depths below the producing
zone and are considered proved by production from other wells in the
field, by successful drill-stem tests, or by core analyses from the
particular zones. Nonproducing reserves require only moderate expense
to be brought into production.
Undeveloped
----------- -- Reserves that are recoverable from additional wells yet
to be drilled.
Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves
requires drilling of additional wells, major deepening of existing
wells, or installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending upon
the extent to which such enhanced recovery methods are in operation. These
reserves are considered to be proved only in cases where a successful fluid-
injection program is in operation, a pilot program indicates successful
fluid injection, or information is available concerning the successful
application of such methods in the same reservoir and it is reasonably
certain that the program will be implemented.
Nonhydrocarbon helium and carbon dioxide reserves were classified using the
same standards as those described in the foregoing definitions of petroleum
reserves. Because these two gases are mixed in and produced with the
natural gas reserves, the term gas as used herein applies to all three
gases, where appropriate, and the term natural gas is used to refer to
hydrocarbon gas.
Estimates of the net proved reserves of MESA Inc, as of December 31, 1994,
are as follows:
Total
TOTAL PROVED RESERVES ---------
Natural Gas (MMcf)................ 1,303,187
Oil and Condensate (Mbbl)......... 5,032
Natural Gas Liquids (Mbbl)........ 84,397
Helium (MMcf)..................... 4,457
Carbon Dioxide (MMcf)............. 46,459
PROVED DEVELOPED RESERVES
Natural Gas (MMcf)................ 1,257,883
Oil and Condensate (Mbbl)......... 4,311
Natural Gas Liquids (Mbbl)........ 81,345
Helium (MMcf)..................... 4,419
Carbon Dioxide (MMcf)............. 16,308
Significant proved natural gas liquids reserves and helium reserves are
included herein for the Satanta plant in the Hugoton field in Kansas.
Proved helium reserves also are included for a helium recovery unit at the
Fain gas processing plant in the Panhandle field in Texas.
Substantial volumes of gas and natural gas liquids reserves are included for
properties owned by MESA Inc. in the Kansas Hugoton field. A state order
has been issued that permits an optional second well on each 640 acre
proration unit (480 acres minimum) in this field. MESA Inc., as the
operator, has drilled or participated in 381 such working interest wells,
and projections of reserves and revenue in this report were based on the
assumption that this development will continue on the MESA Inc. Hugoton
properties and be completed in 1996. MESA Inc. plans to drill or
participate in about 20 additional working interest infill wells in this
field. A portion of the reserves included for these wells would be produced
by existing wells if the infill wells are not drilled; only the estimated
incremental portion of reserves to be recovered from the undrilled infill
wells are classified as undeveloped.
The KCC held hearings from August 1992 to September 1993 to consider changes
to the methods in which fieldwide allowables are allocated among individual
wells within the Hugoton field. Specifically, the KCC considered proposals
from various producers to amend calculations of well deliverability, the
allocation of allowables for infilled units, and the make up of underages
from prior periods. On February 2, 1994, the KCC issues an order, effective
as of April 1, 1994, establishing new field rules which modify the formulas
and calculations used to allocate allowables among wells in the field. The
standard pressure used in each wells' calculated deliverability was reduced
by 35%, greatly benefitting MESA Inc. high deliverability wells. Also, the
new rules assign a 30% greater allowable to 640-acre units with infill wells
than similar units without infill wells. Essentially all of MESA Inc.
Hugoton infill wells have been drilled, resulting in an increase to MESA
Inc. in assigned allowables for 1994. The new field rules also allow
Hugoton producers to make up pre-1994 cancelled underages over a 10-year
period.
MESA Inc. estimates its production will increase by approximately 5% in 1995
which is attributable to the new field rules being in effect for the full
year. The 1995 total production levels are expected to be relatively
constant for the next four years. MESA Inc. is continuing to upgrade the
well-gathering system, which improves deliverability of the wells. This
increase in deliverability and the associated costs have been incorporated
in the estimates included herein.
With the exception of a few properties in this report known as the "Texas
Panhandle -- Other," the West Panhandle field properties are subject to an
operating agreement with Colorado Interstate Gas Company, hereinafter
referred to as "CIG." The properties subject to this agreement are
collectively referred to as the "B" Contract area. MESA Inc.'s share of the
"B" Contract area gas is processed through MESA Inc.'s Fain gasoline plant
in Potter County, Texas, and is subject to special royalty payments. An
agreement effective January 1, 1991, allocates 77 percent of the remaining
production from the "B" Contract properties to MESA Inc. and the remaining
23 percent to CIG. CIG receives a 20-percent overriding royalty interest on
MESA Inc.'s share of the helium produced at this plant.
Agreements reached by MESA Inc. and CIG during 1993 provide that MESA Inc.
is entitled to a maximum of 32 Bcf at the Fain plant inlet for each of the
years 1994, 1995, and 1996, with CIG having the rights to the remainder of
the "B" Contract production in these years. CIG is entitled to a maximum of
8.5 Bcf for each of the years 1997, 1998, and 1999, with MESA Inc. being
entitled to take the rest of the "B" Contract production in these years.
CIG's maximum take for the year 2000 is 7.56 Bcf, with a maximum of 7.0 Bcf
in years thereafter, until it has produced the full 23 percent of the
January 1, 1991, reserves to which it is entitled. In addition to its gas
take limitations, CIG has the right to take gas for use as field fuel until
July 2000. The projected volumes in this report assume that MESA Inc. will
take the maximum volume to which it is entitled under the contract, for as
long as the projection of allowables and deliverability will permit, after
which the projected deliverability is used. One of the provisions of the
agreement eliminates the previous requirement that MESA Inc. had to take,
use, process, and sell its gas within the "City of Amarillo, Texas, and its
environs." MESA Inc. can now sell its share of the "B" Contract gas to
markets anywhere, whether inside or outside of the City of Amarillo or
inside or outside of the State of Texas.
Since January 1, 1991, CIG has overproduced its 23 percent share of the gas.
This overproduction of gas by CIG and the subsequent gas balancing has been
accounted for in this report by adjusting MESA Inc.'s gas interests in the
"B" Contract Area over time. For accounting purposes, the CIG gas imbalance
discussed above is treated as production income to MESA Inc. at the time CIG
produced the gas; this revenue is then recorded as an account receivable
from CIG. This difference in treatment must be considered when using this
report with the accounting records. The cumulative gas imbalance as of
December 31, 1994 is tabulated below. These amounts have not been deducted
from this report.
Net Salable Gas, Mcf................ 13,887,402
Net Natural Gas Liquids, Bbl........ 1,974,775
Net Condensate, Bbl................. 16,718
Net Helium, Mcf..................... 71,170
Under a workover plan in the "B" Contract Area, approximately 350 wells were
worked over, deepened, or redrilled during the past four years. The
workover plan, a continuing project, is reevaluated each year to determine
the following year's work. This report includes proved reserves to be
developed over the next three years from zones below current completions in
35 wells. MESA Inc. expects that numerous compressors will be installed on
the gathering system for this field near the wellheads to improve gas
deliverability. Approximately 110 compressors are currently installed and
we have assumed that 200 compressors will be installed during the next four
years.
The expected acceleration of production from these programs has been
incorporated in the estimated production rates. The expense of these
programs initially will be paid by CIG but will be repaid by MESA Inc. As
provided by the operating agreement between MESA Inc. and CIG, this
repayment has been amortized herein over the remaining lives of the
properties on a unit-of-production basis.
Future oil and gas producing rates estimated for this report are based on
production rates considering the most recent figures available. The rates
used for future production are rates that are believed to be within the
capacity of the well or reservoir to produce. Information on proration of
gas production has been considered in arriving at the rates projected.
Gas volumes are expressed at a temperature of 60 degrees Fahrenheit and at
the legal pressure base of the states in which the gas reserves are located.
Gross volumes are reported as wet gas and the net volumes are reported as
salable gas; however, neither the gross nor net volumes were reduced for
plant fuel usage, which is estimated to be 43.7 billion cubic feet of gross
wet gas. The value of this fuel is deducted as part of the plant operating
costs. Condensate reserves estimated herein are those to be obtained by
conventional lease separation.
Revenue values in this report were estimated using current prices and costs.
Future prices were estimated using guidelines established by the Securities
and Exchange Commission and the Financial Accounting Standards Board. The
initial and future prices and producing rates used in this report are those
that MESA Inc. can reasonably expect to be received over the life of the
properties. The assumptions used for estimating future prices and costs are
as follows:
Oil and Condensate Prices
=========================
Oil and condensate prices were held constant for the life of the properties.
Natural Gas, Helium, and Carbon Dioxide Prices
==============================================
Natural gas prices were held constant for the life of the properties except
for some 79 percent of the gas in the Texas Panhandle field.
Under existing contractual arrangements in the Panhandle properties, about
79 percent of the total gas is sold to Energas under a long-term contract.
In 1992, MESA Inc. and Energas negotiated a new pricing formula for the next
five years of gas sales to Energas. Seventy percent of the gas sold to
Energas will be sold at a fixed price that escalates by a total of $0.75 per
thousand cubic feet from 1993 to 1997. The remaining 30 percent of such gas
will be sold at the "spot-market" gas price plus $0.10 per thousand cubic
feet. The pricing formula will be renegotiated for periods after 1997. In
this report, the prices applicable under the current contract pricing
formula were used through 1997. Beginning in 1998, the 1995 weighted
average price was applied to the subsequent Energas sales.
Helium and carbon dioxide prices were held constant for the life of the
properties.
Natural Gas Liquids Prices
==========================
Natural gas liquids prices were held constant for the life of the
properties.
Operating and Capital Costs
===========================
Estimates of operating costs based on current costs were used for the life
of the properties with no increases in the future based on inflation.
Future capital expenditures were estimated using 1994 values and were not
adjusted for inflation.
Oil and condensate production taxes were calculated using net removal prices
after deducting transportation charges.
Economic estimates were made, as of December 31, 1994, under the
aforementioned assumptions concerning future prices and costs and are
summarized as follows:
Total
---------
Future Gross Revenue (M$)............. 3,513,282
Production Taxes (M$)................. 114,752
Ad Valorem Taxes (M$)................. 200,803
Operating Costs (M$).................. 876,450
Capital Costs (M$).................... 95,441
Future Net Revenue (M$)(1)............ 2,225,836
Present Worth at 10 Percent (M$)(1)... 988,325
(1) Future income tax expenses were not taken into account in the
preparation of these estimates.
Included above is revenue from nonhydrocarbon reserves (helium and carbon
dioxide) that will be produced with and separated from certain natural gas
as it is produced. It is estimated that about 3 percent of the present
worth shown above is attributable to this planned helium and carbon dioxide
recovery.
The information relating to estimated proved reserves, estimated future net
revenue from proved reserves, and present worth of estimated future net
revenue from proved reserves of oil, condensate, natural gas liquids, and
gas contained in this report has been prepared in accordance with Paragraphs
10-13, 15 and 30(a)-(b) of Statement of Financial Accounting Standards No.
69 (November 1982) of the Financial Accounting Standards Board and Rules 4-
10(a)(1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the
Securities and Exchange Commission; provided, however, certain estimated
data have not been provided with respect to changes in reserve information,
(i) future income tax expenses have not been taken into account in
estimating the future net revenue and present worth values set forth herein,
and (ii) minor amounts of revenue from nonhydrocarbon gases are included
herein.
To the extent the above-enumerated rules, regulations, and statements
require determinations of an accounting or legal nature or information
beyond the scope of this report, MESA Inc. is necessarily unable to express
an opinion as to whether the above-described information is in accordance
therewith or sufficient therefor.
Submitted,
Dennis E. Fagerstone
Vice President-Exploration and Production
Signed: /s/ Dennis E. Fagerstone
------------------------
