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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
{X} ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
{ } 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)
2600 TRAMMELL CROW CENTER
2001 ROSS AVENUE
DALLAS, TEXAS 75201
(Address of Principal Executive (Zip Code)
Offices)
(214) 969-2200
(Registrant's Telephone Number, Including Area Code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common stock, $.01 par value...................................... New York Stock Exchange
12% Subordinated Notes due August 1, 1996......................... New York Stock Exchange
13 1/2% Subordinated Notes due May 1, 1999........................ New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. {X}
Number of shares outstanding as of the close of business on March 4, 1994:
47,762,109.
Aggregate market value of 44,822,008 shares held by nonaffiliates of
Registrant at the closing price on March 4, 1994, of $6.875: $308,151,305.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 1994 Annual Meeting of
Stockholders are incorporated by reference into Part III hereof.
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TABLE OF CONTENTS
PART I
Item 1. Business................................................................... 1
Item 2. Properties................................................................. 16
Item 3. Legal Proceedings.......................................................... 16
Item 4. Submission of Matters to a Vote of Security Holders........................ 18
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters...... 19
Item 6. Selected Financial Data.................................................... 19
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations................................................................. 20
Item 8. Consolidated Financial Statements and Supplementary Data................... 28
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................. 28
PART III
Item 10. Directors and Executive Officers of the Registrant......................... 28
Item 11. Executive Compensation..................................................... 28
Item 12. Security Ownership of Certain Beneficial Owners and Management............. 28
Item 13. Certain Relationships and Related Transactions............................. 28
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........... 28
SIGNATURES................................................................. 32
FINANCIAL STATEMENT SCHEDULES.............................................. S-1
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PART I
ITEM 1. BUSINESS
GENERAL
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 properties. As of December 31, 1993, Mesa owned
approximately 1.7 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 reserves are
proved developed reserves. The estimated future net cash flows before income
taxes from Mesa's proved reserves, as determined in accordance with the
regulations of the Securities and Exchange Commission (the "Commission") as of
December 31, 1993, were approximately $2.3 billion and had a net present value
(discounted at 10%) before income taxes of approximately $1.1 billion. Estimates
of reserves for approximately 96% of the quantities shown herein have been
prepared by DeGolyer and MacNaughton ("D&M"), independent petroleum engineering
consultants. 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 strategy includes (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, and (v)
promoting the use of natural gas as a transportation fuel and developing and
marketing 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 executive offices
at 2001 Ross Avenue, Suite 2600, Dallas, Texas 75201, where its telephone number
is (214) 969-2200. At December 31, 1993, Mesa employed 383 persons.
PROPERTIES
Over 96% of Mesa's 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 3500 feet or less, are known for their stable long-life production
profiles. Although the two fields are part of the same reservoir, Mesa's
interests in these fields are operated separately and are subject to different
contractual and marketing arrangements. Due to the long-life nature of the
Hugoton and West Panhandle properties, Mesa expects to be able to maintain a
relatively stable production profile for the remainder of the decade, regardless
of exploration or development success in other areas. Mesa's other properties
are primarily in the Gulf of Mexico.
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,
additional compression and gathering facilities, and 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 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 rights 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
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contracts will expire in 1995, thus giving Mesa a substantial amount of
uncommitted deliverability available for sale after that date.
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 total field, are
concentrated in the center of the field on over 230,000 net acres, covering
approximately 400 square miles. The gas from these properties is produced from
over 1,000 wells, approximately 950 of which are operated by Mesa, in which Mesa
has an average working interest of 95%. 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
well bore 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 wellhead natural gas per day. Substantially all of Mesa's
Hugoton production is processed through its newly constructed Satanta natural
gas processing plant ("Satanta Plant"). After processing, Mesa has available to
market over 175 MMcf of residue (processed) gas and 13 thousand barrels
("MBbls") of NGLs on a peak production day. Mesa's 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.
Substantially all of Mesa's Hugoton properties are owned by a wholly owned
subsidiary, Hugoton Capital Limited Partnership ("HCLP"). Mesa Hugoton
properties accounted for 64% of Mesa's equivalent proved reserves and 71% of the
present value of estimated future net cash flows before income taxes, determined
as of December 31, 1993 in accordance with Commission guidelines. The Hugoton
properties accounted for approximately 48%, 40% and 44% of Mesa's oil and gas
revenues for the years ended December 31, 1993, 1992 and 1991, 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, in 1992 and 1993, 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 586 wells which Mesa operates on 191,000
net acres. All of Mesa's West Panhandle production is processed through Mesa's
recently expanded Fain natural gas processing plant (the "Fain Plant").
Mesa's West Panhandle reserves are owned and produced pursuant to contracts
(collectively called the "B Contract") with Colorado Interstate Gas Company
("CIG"), originally executed in 1928 by predecessors of both companies. A recent
amendment to the B Contract, 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 B Contract and
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.
Mesa's West Panhandle properties are owned by Mesa Operating Co. ("MOC"), a
wholly owned subsidiary. As of December 31, 1993, Mesa's West Panhandle
properties represented approximately 32% of Mesa's equivalent proved reserves,
and approximately 29% 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 40%,
39% and 36% of Mesa's oil and gas revenues for the years ended December 31,
1993, 1992 and 1991, respectively. Although the West Panhandle properties are
long-life, the percentage of Mesa's revenues represented by West Panhandle
production has been greater than
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the percentage of equivalent proved reserves represented by such properties.
This is a result of higher 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 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.
Gulf Coast and Other
Mesa's Gulf Coast properties are located offshore Texas and Louisiana. Mesa
has operated in the Gulf of Mexico since 1970 and currently owns interests in 37
blocks which have produced approximately 400 Bcfe (net to Mesa's interest) over
their productive lives. As of December 31, 1993, these properties had an
estimated 26 Bcfe of remaining proved reserves. In previous years, Mesa owned
interests in approximately 200 blocks in the Gulf of Mexico. In addition, Mesa
maintains a seismic database covering over 100,000 miles in the Gulf of Mexico
and an office in Lafayette, Louisiana to oversee production from its properties.
Mesa's working interests in 7 of its 37 blocks are subject to a net profits
interest owned by the Mesa Offshore Trust. Mesa's other producing properties are
located in the Rocky Mountain area in the United States. Together, Mesa's Gulf
Coast and other producing properties accounted for 4% of 1993 year-end reserves.
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 5% of the net book value of Mesa's properties.
RESERVES
Proved reserve estimates for Mesa's Hugoton and West Panhandle properties
were prepared in accordance with Commission guidelines by D&M. The reserve
estimates for Mesa's Gulf Coast and Rocky Mountain properties were prepared by
Mesa engineers, also in accordance with Commission guidelines. The properties on
which reserves were estimated by D&M represent approximately 96% of Mesa's total
proved 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, 1993 (dollar amounts in thousands):
Proved reserves:
Natural gas (MMcf)..................................................... 1,202,444
Natural gas liquids, oil and condensate (MBbls)........................ 82,446
Future cash flows:
Future cash inflows.................................................... $3,723,760
Operating costs........................................................ (897,244)
Production and ad valorem taxes........................................ (439,980)
Development and abandonment costs...................................... (80,310)
Future income taxes.................................................... (240,017)
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Future net cash flows.......................................... $2,066,209
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Present value of future net cash flows
discounted at 10% ("Present Value") after income taxes................. $ 986,931
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Present Value before income taxes........................................ $1,068,740
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In accordance with Commission guidelines, future prices for natural gas
were based on market prices as of December 31, 1993 without future escalation
and, where applicable, contract terms (including fixed and determinable price
escalations under existing contracts). Market prices as of December 31, 1993
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 year-end 1993, with no escalation.
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Natural gas prices in effect at December 31, 1993 (having a weighted
average of $2.14 per Mcf) may not be the most appropriate or representative
prices to use for estimating future cash flows from the reserves since such
prices are influenced by the seasonal demand for natural gas. The average price
received by Mesa for sales of natural gas in 1993 was $1.79 per Mcf. Assuming
all other variables used in the calculation of reserve data are held constant,
Mesa estimates that each $.10 change in the average sales price per Mcf for
natural gas would affect Mesa's estimated future net cash flows and the present
value thereof, both before income taxes, by $108 million and $48 million,
respectively.
The following table summarizes estimated proved reserves as of December 31,
1993 by major area of operation:
NATURAL GAS
GAS NGLS OIL EQUIVALENTS
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(MMCF) (MBBLS) (MBBLS) (MMCFE)
Hugoton.................................. 869,229 36,663 -- 1,089,207
West Panhandle........................... 282,899 42,447 1,767 548,183
Other.................................... 50,316 40 1,529 59,730
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Total.......................... 1,202,444 79,150 3,296 1,697,120
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Estimates of reserves for approximately 96% of the quantities shown above
have been prepared by D&M. Mesa's internal estimates of proved reserves as of
December 31, 1993, for the Hugoton and West Panhandle areas, exceed those of D&M
by about 450 Bcfe or approximately 27%. The higher reserve estimates are
primarily attributable to higher recoveries that Mesa expects to realize from
the 381 infill wells that have been drilled on its Hugoton properties, most of
which were drilled between 1987 and 1990.
Petroleum engineering is not an exact science. Information relating to
Mesa's 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 variable 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 and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of the
future net revenues expected therefrom prepared by different engineers or by the
same engineers at different times may vary substantially. Actual production,
revenues and expenditures with respect to Mesa's reserves will likely vary from
estimates, and such variances may be material.
The present values of future net revenues referred to herein should not be
construed as the current market value of the estimated oil and gas reserves
attributable to Mesa's properties. In accordance with applicable requirements of
the Commission, the estimated discounted future net revenues from proved
reserves are generally based on prices and costs as of the date of the estimate,
whereas actual future prices and costs may be materially higher or lower. Actual
future net revenues also will be affected by factors such as the amount and
timing of actual production, supply and demand for oil and gas, curtailments or
increases in consumption by gas purchasers, changes in governmental regulations
or taxation and the impact of inflation on costs. Mesa's producing properties in
the Hugoton field and the West Panhandle field are subject to production
limitations imposed by state regulatory authorities, by contracts or both, and
any future limitation on production would affect the expected decline in
reserves. The timing of actual future net revenues from proved reserves, and
thus their actual present value, will be affected by the timing of both the
production and the incurrence of expenses in connection with development and
production of oil and gas properties. In addition, the 10% discount factor,
which is required by the Commission to be used to calculate discounted future
net revenues for reporting purposes, is not necessarily the most appropriate
discount factor based on interest rates in effect from time to time and risks
associated with the oil and gas industry.
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During 1993, Mesa filed Form EIA-23, which includes reserve estimates
prepared by D&M, with the Energy Information Administration of the Department of
Energy ("EIA"). Such reserve estimates did not vary from those estimates
contained herein by more than five percent.
The estimated quantities of proved oil and gas reserves, the standardized
measure of future net cash flows from proved oil and gas reserves ("Standardized
Measure") and the changes in the Standardized Measure for each of the three
years in the period ended December 31, 1993 are included under "Supplemental
Financial Data" in the Consolidated Financial Statements of the Company.
PRODUCTION
Mesa's Hugoton and West Panhandle fields are both mature reservoirs that
are substantially developed and have long-life production profiles. Assuming
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 through the end
of this decade that approximates or exceeds such properties' 1993 equivalent
production of approximately 115 Bcfe. Certain factors affecting production in
Mesa's various fields are discussed in greater detail below.
Hugoton Field
Natural gas production from the Hugoton field is subject to numerous state
and federal laws and Federal Energy Regulatory Commission ("FERC") regulations.
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 5,000 wells in the
field.
Twice each year, the KCC sets the fieldwide allowable production at a level
estimated to be necessary to meet the Hugoton market demand for the summer and
winter production periods. The fieldwide allowable is then allocated among
individual wells based on 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
1993 was 578 Bcf. Between 1989 and 1991, Mesa's percentage of actual field
production increased from a historical average of 13% to 16% because other
operators produced less than their assigned allowables, and because Mesa
produced its assigned allowable share and its underages (cumulative allowables
not produced in the periods assigned) from prior years. Mesa also increased its
productive capacity by substantially completing its infill well development
program before other producers. In 1992 and 1993, Mesa's share of allowables was
reduced, essentially presenting other producers with an opportunity to catch up
to Mesa's more aggressive production rate from 1989 through 1991. In 1992 and
1993, Mesa's net Hugoton production totaled 55.5 Bcfe and 57.0 Bcfe,
respectively, compared to 72.1 Bcfe in 1991.
The KCC held hearings from August 1992 to September 1993 to consider
changes to the manner 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 makeup of underages
from prior periods. On February 2, 1994, the KCC issued 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. For example,
the standard pressure against which each wells' deliverability is measured will
be 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 similar units without infill wells. Substantially all of Mesa's Hugoton
infill wells have been drilled, resulting in an increase to Mesa in assigned
allowables for 1994. The new field rules also allow Hugoton producers to make up
underages over a 10-year period. The KCC reported underages for the entire field
of approximately
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950 Bcf, of which Mesa's share is 27 Bcf. Mesa expects to continue producing its
underages during the make-up period.
Mesa anticipates that the implementation of the new Hugoton field rules,
the increased yield of NGLs from the Satanta Plant and certain other factors
will result in an approximately 25% increase in its Hugoton field production in
1994 to over 70 Bcfe, assuming continuation of existing economic and operating
conditions.
Excluding reserve acquisitions, Mesa has invested over $120 million in
capital expenditures in Hugoton since 1986, but expects future capital
expenditures to be substantially lower. The previous capital expenditures
included $54 million to drill 381 infill wells, $43 million to construct the new
Satanta Plant and related facilities, and $26 million to upgrade compression
facilities, production equipment and pipeline interconnects in order to increase
production capacity and marketing flexibility. During periods of peak demand,
Mesa's wells in the Hugoton field are capable of producing more than 260 MMcf of
wet gas per day on a sustained basis.
West Panhandle Field
Mesa's production of wet gas from the West Panhandle field (i.e., gas
production at the wellhead before processing and before reduction for royalties)
is governed by the B Contract. Mesa was entitled to wet gas production of 35 Bcf
for 1993 and will be entitled to 32 Bcf per year for 1994 through 1996. After
deductions for processing and royalties, Mesa expects that 32 Bcf of wet gas
production will result in annual net production volumes of 21 Bcf of residue gas
and 3 million Bbls 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 B Contract. Assuming
continuation of existing economic and operating conditions, Mesa expects its
existing West Panhandle properties will be able to produce an average of 33 Bcf
of wet gas per year for sale in the years 1997 through 2000.
The PAA contains provisions which allocate 77% of ultimate production from
the B Contract properties after January 1, 1991 to Mesa and 23% to CIG. As a
result, Mesa records 77% of total annual B Contract 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, 1993, a long-term gas balancing receivable of $34.3 million
relating to the B Contract 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, like other producers, processes its natural gas production for the
extraction of NGLs because the components of the gas stream have higher market
value in processed form than in non-processed, wet gas form. 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 propane, butane,
ethane, isobutane and natural gasolines. The NGLs and helium are then sold
pursuant to contracts providing for market based prices. Mesa produced 5 million
Bbls of NGLs in 1993.
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Satanta Natural Gas Processing Plant
Historically, approximately one-half of Mesa's Hugoton production was
processed through the Ulysses natural gas processing plant for the extraction of
NGLs. In the third quarter of 1993, Mesa completed 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 December 1993, the Satanta
Plant averaged 225 MMcf per day of inlet gas and produced a daily average of 11
MBbls of NGLs, 430 Mcf of crude helium and 175 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 other natural
gas fields. Mesa completed an expansion of the Fain Plant in late 1992 to
increase its inlet capacity from 90 MMcf per day to 120 MMcf per day. In
December 1993, the Fain Plant averaged 107 MMcf per day of inlet gas and
produced a daily average of 10.7 MBbls of NGLs, 280 Mcf of crude helium and 80
MMcf of residue natural gas.
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SALES AND MARKETING
Following the processing of the wet gas, Mesa sells the dry, or residue,
natural gas and the NGLs pursuant to various short-term 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 nature of 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 table shows Mesa's natural gas and natural gas liquids
production and prices by area for the past three years.
PRODUCTION 1993 1992 1991
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Natural gas (MMcf)
Hugoton................................................... 47,476 48,592 63,367
West Panhandle............................................ 23,786 26,380 23,591
Other(1).................................................. 8,558 14,555 21,564
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Total............................................. 79,820 89,527 108,522
------- ------- --------
------- ------- --------
Natural gas liquids (MBbls)
Hugoton................................................... 1,481 898 1,235
West Panhandle............................................ 3,480 3,794 3,279
Other(1).................................................. 89 148 211
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Total............................................. 5,050 4,840 4,725
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(1) Includes production through the date of sale from properties that have been
sold. The most significant property sales occurred in 1991. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" for disclosure of production from sold properties.
PRICES 1993 1992 1991
------------------------------------------------------------- ------ ------ ------
Weighted average sales price:
Natural gas (per Mcf)
Hugoton................................................. $ 1.78 $ 1.56 $ 1.29
West Panhandle.......................................... 1.72 1.80 1.85
Other................................................... 2.04 1.74 1.94
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Average(1)......................................... 1.79 1.72 1.54
Natural gas liquids (per Bbl)
Hugoton................................................. $12.35 $13.98 $14.65
West Panhandle.......................................... 12.04 11.92 12.58
Other................................................... 12.55 12.50 11.44
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Average............................................ 12.14 12.32 13.07
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(1) The average natural gas price for all properties for the years 1990, 1991
and 1992 reflects $(.01) per Mcf, $.08 per Mcf and $.06 per Mcf,
respectively, related to hedges of natural gas production in the natural
gas futures market.
Hugoton Gas Sales Contracts
A substantial portion of Mesa's Hugoton field production is subject to gas
purchase contracts with Western Resources, Inc. ("WRI"). The WRI contracts,
which became effective January 1, 1990 and expire in May 1995, provide WRI the
right to annual purchases of 34.0 Bcf in 1993, 37.5 Bcf in 1994 and 19.9 Bcf
during the first five months of 1995. These volumes are subject to minimum
seasonal purchase volumes. The
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contracts also provide that any gas not nominated for purchase by WRI is
released to Mesa for sale to other parties. WRI pays market prices for volumes
purchased as determined monthly based on a price index published by a third
party. WRI purchased 29.5 Bcf in 1993 at an average price of $1.85 per Mcf.
Under a purchase contract with Williams Natural Gas Company ("Williams"),
effective as of December 1, 1989, Williams has the right, for the life of the
leases on the properties governed by the contract, to purchase certain volumes
of natural gas during each winter season from leases representing approximately
35% of Mesa's Hugoton production. Williams has not exercised its right to
purchase gas pursuant to this agreement in previous years, and Mesa has sold
such gas to other buyers at market prices.
Mesa's attempts to maximize its annual production and to direct natural gas
sales to the most favorable markets available, consistent with regulatory and
contractual requirements. Any Hugoton production not taken under the applicable
contracts by WRI or Williams 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 gas is sold pursuant to gas
purchase contracts with two major customers in the Texas panhandle area.
Approximately 10 Bcf per year of residue 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 in effect since 1949. The contract contains a pricing formula
for the five-year period 1993 through 1997. Beginning in 1993, 70% of the
volumes sold to the gas utility under this contract are sold at fixed prices of
$2.71 per Mcf in 1993, and escalating 5% per annum in 1994 and 1995 and then at
7 1/2% per annum in 1996 and 1997. The other 30% of the 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 1993 was $2.52 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 7 Bcf in 1993, 8.4
Bcf in 1994 and 8.4 Bcf in 1995 at fixed prices per MMBtu of $1.64, $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. In 1993,
Mesa sold approximately 11 Bcf to the pipeline for an average price of $1.59 per
Mcf.
Other industrial customers purchase natural gas from Mesa under short to
intermediate term contracts. These sales totaled approximately 4 Bcf in 1993 and
5 Bcf in 1992. 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 by the B Contract 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 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 the Fain Plants are sold by
component pursuant to a seven year contractual arrangement with Mapco Oil and
Gas Company ("Mapco"), a major transporter and
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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 of Notes to Consolidated Financial Statements for information
on sales to major customers.
RESERVE REPLACEMENT
In the last three years, Mesa's capital budget has been directed
principally toward the construction of NGL processing facilities and
improvements in its compression and gathering systems, rather than toward
reserve replacement. While Mesa expects to direct additional capital
expenditures (see "-- Management's Discussion and Analysis of Financial
Condition and Results of Operations") toward reserve replacement in 1994 and in
future years, Mesa does not expect that the presently budgeted amounts will be
sufficient to replace annual production with new reserve additions. However, as
Mesa progresses in its plan to deleverage its capital structure, it expects that
cash flows formerly devoted to debt service will be used to increase the level
of capital expenditures for reserve replacement.
Mesa's strategy for replacing its annual production with new reserve
additions is based on a multi-step approach, including (i) developing additional
reserves in certain deeper portions of the West Panhandle field reservoir; (ii)
development and exploratory drilling in the Gulf of Mexico based on evaluation
of three-dimensional ("3-D") seismic data, principally on existing properties;
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.
West Panhandle Development
In the last three years, Mesa has deepened or redrilled 39 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 reservoir not currently reached by existing wells. Mesa
anticipates development of the reserves over the next three to four years, in
anticipation of its contractual right to increase its share of B Contract
production in 1997 (see -- "Production -- West Panhandle Production").
Gulf Coast Development and Exploration
Mesa currently owns interests held by production on 37 offshore blocks
encompassing 22 producing fields. Mesa has operated in the Gulf of Mexico since
1970, and has an extensive data base, including over 100,000 miles of seismic
data. Over the last three years, Mesa has evaluated its offshore producing
properties utilizing conventional well information, seismic and production data,
combined with new 3-D seismic surveys to identify further development and
exploration potential. Mesa currently has six 3-D seismic surveys under analysis
and plans to obtain an additional nine surveys in 1994. Mesa has currently
identified three prospects it plans to drill in 1994 and expects to complete
evaluation of 10 other blocks in 1994. Mesa intends to continue its evaluation
and identify 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, if any, on line more quickly and at lower
development costs than have been typical for offshore production.
Acquisitions
Mesa has also maintained a large geological and geophysical data base
covering the Midcontinent and other areas where it has historically operated. As
capital becomes available and conditions permit, Mesa intends to exploit its
data base and make 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.
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DRILLING ACTIVITIES
The following table shows the results of Mesa's drilling activities for the
last five years.
1993 1992 1991 1990 1989
------------ ------------ ------------ ------------- ------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----- ----- ----
Exploratory wells:
Productive................. -- -- 5 4.1 6 4.7 -- -- 5 1.6
Dry........................ 1 1.0 1 .4 1 .2 5 3.1 5 2.6
Development wells:
Productive................. 43 29.1 22 16.5 26 10.9 146 120.8 151 88.6
Dry........................ -- -- -- -- -- -- -- -- 2 .2
----- ---- ----- ---- ----- ---- ----- ----- ----- ----
Total................... 44 30.1 28 21.0 33 15.8 151 123.9 163 93.0
----- ---- ----- ---- ----- ---- ----- ----- ----- ----
----- ---- ----- ---- ----- ---- ----- ----- ----- ----
At December 31, 1993, the Company was not participating in the drilling of
any wells.
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, 1993 is set forth in the
table below.
UNDEVELOPED
PRODUCING ACREAGE PRODUCING WELLS ACREAGE
------------------- ---------------- -----------------
GROSS NET GROSS NET GROSS NET
------- ------- ----- ------ ------ ------
Onshore U.S.:
Kansas...................... 258,994 231,367 1,339 985.1 5,280 5,280
Texas....................... 241,353 191,044 589 451.6 5,164 4,592
Wyoming..................... 11,715 4,603 6 1.3 16,415 11,214
North Dakota................ 5,600 4,141 10 5.9 3,931 2,602
Other....................... 4,573 2,700 8 1.3 34,767 24,233
------- ------- ----- ------- ------ ------
Total Onshore............ 522,235 433,855 1,952 1,445.2 65,557 47,921
------- ------- ----- ------- ------ ------
Offshore U.S.:
Louisiana................... 88,274 46,022 77 34.5 -- --
Texas....................... 73,808 15,233 50 8.4 -- --
------- ------- ----- ------- ------ ------
Total Offshore........... 162,082 61,255 127 42.9 -- --
------- ------- ----- ------- ------ ------
Grand Total................... 684,317 495,110 2,079 1,488.1 65,557 47,921
------- ------- ----- ------- ------ ------
------- ------- ----- ------- ------ ------
Mesa has interests in 2,015 gross (1,467.3 net) gas wells and 64 gross
(20.8 net) oil wells in the United States. Mesa also owns approximately 84,643
net acres of producing minerals and 40,732 net acres of nonproducing minerals in
the United States.
THE NGV BUSINESS
Mesa believes that the natural gas vehicle ("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 principal objectives are (i) to increase public awareness and
acceptance of natural gas as a premium fuel for use in the transportation
sector, thus creating a potentially large, high-value market for natural gas;
and (ii) to become a leading provider of NGV conversion equipment and fueling
services. Mesa's present strategies to accomplish these objectives are (i) the
development, manufacture and sale of engine-
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specific, conversion equipment which meets the most stringent emissions
standards; (ii) pursuing conversion equipment sales, fleet conversions, fueling
installations and administration of conversion and fueling programs; and (iii)
pursuing developing opportunities for related products such as fuel tanks,
compressors and dispenser systems.
As of December 31, 1993, Mesa had invested approximately $14 million in its
indirect, wholly owned subsidiary, Mesa Environmental Ventures Co. ("Mesa
Environmental"), to fund its overhead and business development. Mesa
Environmental is a start-up business in a newly developing industry and the
ultimate capital investment required to insure its viability is uncertain. In
addition, Mesa cannot predict when, or if, Mesa Environmental's operations will
begin to earn a profit.
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 HCLP, into corporate form.
Pursuant to these mergers, Mesa Operating Limited Partnership ("MOLP") was
merged into 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 the number of shares of common stock of Mesa, as contemplated by
the 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. The Company's significant subsidiaries
are described below:
MOC
MOC owns Mesa's properties in the West Panhandle field of Texas and its
interests in the Gulf of Mexico and the Rocky Mountain area. MOC also owns a 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 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. In 1991, MOC
entered into a services agreement with HCLP pursuant to which MOC operates
HCLP's Hugoton field properties and provides certain services necessary to
market production therefrom, process remittances of production revenues and
perform certain other administrative functions in exchange for a services fee.
The services fee totaled approximately $11.4 million in 1993.
HCLP
Substantially all of Mesa's Hugoton 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
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, or 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., 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
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HCLP's debt. To the extent cash flows exceed these requirements, such excess
cash is generally available for distribution to the Mesa subsidiaries that own
HCLP's equity.
Other Subsidiaries
MHC principally conducts various investment activities. At December 31,
1993, MHC (including its predecessors) held $92 million of cash and securities
and a 19% limited partnership interest in HCLP and had an intercompany payable
to MOC of $123 million. The payable to MOC was repaid to a balance of $4.5
million on February 28, 1994 with a combination of cash and the transfer of an
18% limited partnership interest in HCLP to MOC. After the subsidiary merger and
intercompany transaction, MHC owns all of the equity of Mesa Environmental, a 1%
limited partnership interest in HCLP and approximately $63 million of cash and
securities as of February 28, 1994.
Mesa Capital Corporation is a wholly owned finance subsidiary of MOC.
Neither MHC nor Mesa Environmental is an obligor with respect to any of Mesa's
debt securities.
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 1960's, 1970's and early
1980's as a result of successful exploration, development and acquisitions.
Original Mesa conducted operations in the U.S. 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 has also made significant acquisitions, principally in the Hugoton and
West Panhandle fields. 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 and made cash distributions to Partnership unitholders
of over $1.1 billion from 1986 through 1991. The increased debt associated with
the acquisitions, the distributions and declining gas prices through the
mid-1980's and early 1990's, 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 through the end of
1995.
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" above)
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.
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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, environmental and
other laws relating to the petroleum industry, by changes in such laws and by
constantly changing administrative regulations.
Natural Gas Regulations
Prior to January 1, 1993, various aspects of Mesa's natural gas operations
were subject to regulations by the FERC under the Natural Gas Act of 1938 (the
"NGA") and the Natural Gas Policy Act of 1978 (the "NGPA") with respect to
"first sales" of natural gas, including price controls and certificate and
abandonment authority regulations. However, as a result of the enactment of the
Natural Gas Decontrol Act of 1989, the remaining "first sales" restrictions
imposed by the NGA and the NGPA terminated on January 1, 1993.
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 has 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. Order 636, issued by the FERC 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 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 will do so in
direct competition with all other sellers pursuant to private contracts;
however, pipeline companies and their affiliates are not required to remain
"merchants" of gas, and some of the interstate pipeline companies have or will
become "transporters only." In subsequent orders, the FERC largely affirmed
Order 636 and denied a stay of the implementation of the new rules pending
judicial review. In addition, the FERC has generally accepted rate filings
implementing Order 636 on essentially every interstate pipeline as of the end of
1993. 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
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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 recently adopted or considered adopting measures that alter the methods
previously used to prorate gas production from wells located in these states.
For example, the new 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 the new prorationing regulations will have on its
production of gas or whether other states will adopt similar or other gas
prorationing procedures.
On October 24, 1992, comprehensive national energy legislation was enacted
which focused on electrical power, renewable energy sources and conservation.
The legislation requires equal treatment of domestic and imported natural gas
supplies, mandates expanded use of natural gas and other alternative fuels
vehicles, funds natural gas research and development, permits continued offshore
drilling and use of natural gas feedstock for electric generation, and adopts
various conservation measures designed to reduce consumption of imported oil.
Mesa cannot predict what effect, if any, this legislation will have on its
business.
Mesa owns, directly or indirectly, certain natural gas facilities that it
believes meet the traditional tests the FERC has used to establish a pipeline's
status as a gatherer not subject to FERC jurisdiction under the NGA. Mesa
transports its own gas through these facilities. Mesa also has gas that is
transported through gathering facilities owned by others, including interstate
pipelines. 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 may receive greater regulatory scrutiny at both the state and federal
levels as the pipeline restructuring under Order 636 is implemented. For
example, Oklahoma recently enacted a prohibition against discriminatory
gathering rates. In certain recent cases the FERC has implied that it has
ancillary NGA jurisdiction over gathering activities of interstate pipelines and
their affiliates. In addition, the FERC recently convened a conference to
consider issues relating to gathering services performed by interstate pipelines
or their affiliates. The FERC intends to use information obtained to reevaluate
the appropriateness of its traditional gathering criteria and the
appropriateness of regulating gathering in light of Order 636, and to establish
consistent policies for gathering rates and services for both interstate
pipelines and their affiliates. It is not possible at this time to predict the
outcome of this proceeding although it could ultimately affect access to and
rates of interstate gathering service.
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
("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
recently been transferred to the United States District Court in Washington,
D.C. Because this lawsuit is pending and because of the complex nature of the
calculations necessary to determine potential additional
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royalty liability under the DOI's theories, it is impossible to predict what, if
any, additional or different royalty obligation the DOI may assert with respect
to any of Mesa's prior natural gas contract settlements. Likewise, Mesa cannot
predict what effect, if any, the DOI's claims will have on it.
Environmental Matters
Mesa's operations are subject to numerous United States 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 "Superfund Law." Such regulations, among other
things, impose absolute liability on 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 ("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 materially adversely affect Mesa's operations in the Gulf
of Mexico.
Mesa is not involved in any administrative or judicial proceedings arising
under federal, state or local environment 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
UNOCAL SETTLEMENT
On January 11, 1994, Mesa settled a lawsuit brought by Unocal Corporation
("Unocal") and a purported stockholder of Unocal against Mesa and certain other
defendants. The Unocal lawsuit was originally filed in 1986 against Original
Mesa, certain subsidiaries of Original Mesa and certain other parties. The
lawsuit alleged that the defendants had purchased and sold Unocal common shares
within a six-month period in 1985
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in transactions subject to Section 16(b) of the Securities Exchange Act of 1934,
resulting in alleged short-swing profits of approximately $99 million that were
recoverable by Unocal under Section 16(b). The plaintiffs also asked the Court
to grant prejudgment interest, which amount could have exceeded $50 million.
Mesa and the other defendants contended that none of the transactions in the
Unocal shares were subject to Section 16(b) and, further, that no profit was
realized. However, in light of the significant uncertainties relating to
continuing the litigation and other relevant circumstances, Mesa determined that
entering into a settlement agreement with Unocal (the "Unocal Settlement") would
be in the best interests of Mesa and its stockholders. The settlement was
approved by the U.S. District Court for the Central District of California at a
hearing held on February 28, 1994.
Pursuant to the Unocal Settlement, Mesa and the other defendants agreed to
pay Unocal an aggregate of $47.5 million, of which $42.75 million was paid by
Mesa and $4.75 million was paid by certain other defendants not affiliated with
Mesa. On March 2, 1994, Mesa issued and sold approximately $48.2 million face
amount of 12 3/4% Secured Discount Notes due 1998 in a registered public
offering to certain institutional investors. The proceeds of the sale
(approximately $42.75 million) were used to fund Mesa's portion of the Unocal
Settlement.
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 have been 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 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 defendants allegedly did not obtain the requisite opinion of independent
counsel regarding certain 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. In August
1993, Mesa and Mr. Pickens filed a motion for summary judgment in the individual
action, and such motion is awaiting decision by the Court. Discovery has
commenced and is proceeding in the class action, in which the Court has set an
August 1994 trial date.
Mesa and the other defendants have denied the plaintiffs' allegations.
Several lawsuits making allegations substantially the same as those referenced
in clauses (i) and (ii) above were filed by preference unitholders in Delaware
Chancery Court in 1991 following the proposal of the corporate conversion. In
December 1991, the Chancery Court denied the plaintiffs' request for a
preliminary injunction to enjoin consummation of the corporate conversion. In
August 1992, the Chancery Court granted a motion by the plaintiffs to dismiss
the Delaware lawsuits and awarded attorneys' fees to plaintiffs' counsel.
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 under 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
17
20
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 pricing 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, 1988. 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 use of an
erroneous price in calculating royalties 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 have recently filed court papers alleging royalty
underpayments of approximately $450 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 substantial
defenses to plaintiffs' claims, including (i) that the royalties for all periods
were properly computed and paid and (ii) that plaintiffs' claims with respect to
all periods prior to October 1, 1988 (which appear to account for the large
majority of the claims) were explicitly released by a 1988 written agreement
among plaintiffs, CIG and Mesa and are further barred by the statute of
limitations. If the plaintiffs were to prevail, the manner in which any
resulting liability would be shared between Mesa and CIG would depend on the
resolution of issues relating to the contractual agreements and the relationship
between Mesa, CIG and the lessors during the period in question. No trial date
has been set, but Mesa expects that the Court may set a trial date in 1994.
OTHER
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.
18
21
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
---- ---
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
1992:
First Quarter............................................................. $ 7 1/2 $2 1/2
Second Quarter............................................................ 7 1/4 2 5/8
Third Quarter............................................................. 13 3/8 6 1/4
Fourth Quarter............................................................ 12 3 5/8
- ---------------
Mesa's common stock currently trades on the New York Stock Exchange under the
symbol MXP. At December 31, 1993, there were 46,511,439 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" for a discussion of restrictions
on the payment of dividends.
At March 4, 1994, there were 26,701 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
----------------------------------------------------------------------
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues..................... $ 222,204 $ 237,112 $ 249,546 $ 329,597 $ 326,909
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Operating income............. $ 22,012 $ 26,221 $ 34,128 $ 43,389 $ 28,225
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net loss..................... $ (102,448) $ (89,232) $ (79,163) $ (200,276) $ (60,414)
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net loss per common share.... $ (2.61) $ (2.31) $ (2.05) $ (5.19) $ (1.56)
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Dividends per share.......... $ -- $ -- $ -- $ .85 $ 6.80
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Total assets................. $1,533,382 $1,676,523 $1,832,816 $2,168,002 $2,625,623
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Long-term debt, including
current maturities......... $1,241,294 $1,286,155 $1,310,705 $1,521,740 $1,631,490
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
19
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
For the years ended December 31, 1993, 1992 and 1991, Mesa reported
consolidated net losses of $102.4 million, $89.2 million and $79.2 million,
respectively. The results of operations for each year have been influenced by
certain income and expenses which are either non-recurring or not directly
associated with Mesa's primary operations. See discussion of these items under
"Other Income (Expense)" below. The following table presents a summary of the
results of operations of Mesa for the years indicated.
YEARS ENDED DECEMBER 31
-------------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
Revenues........................................ $ 222,204 $ 237,112 $ 249,546
Operating and administrative costs.............. (100,093) (96,958) (98,342)
Depreciation, depletion and amortization........ (100,099) (113,933) (117,076)
--------- --------- ---------
Operating income................................ 22,012 26,221 34,128
Interest expense, net of interest income........ (131,298) (129,888) (134,258)
Other........................................... 6,838 14,435 20,967
--------- --------- ---------
Net loss........................................ $(102,448) $ (89,232) $ (79,163)
--------- --------- ---------
--------- --------- ---------
In 1993, Mesa sold primarily oil producing properties in the deep Hugoton
and Rocky Mountain areas. In 1992, Mesa sold oil and gas properties located in
Canada and in 1991 sold oil and gas properties located primarily in Oklahoma,
the Texas Panhandle and the San Juan Basin of New Mexico. Results from
operations related to sold properties are included in Mesa's results through the
closing dates of such sales. The following table presents the contribution made
to Mesa's operating results by the sold properties.
YEARS ENDED DECEMBER 31
--------------------------------
1993 1992 1991
------- ------- --------
(DOLLARS IN THOUSANDS)
Revenues............................................. $ 3,424 $11,477 $ 26,297
Production costs..................................... (1,088) (2,327) (9,496)
------- ------- --------
$ 2,336 $ 9,150 $ 16,801
------- ------- --------
------- ------- --------
Proceeds from sales.................................. $26,118 $11,424 $428,063
------- ------- --------
------- ------- --------
Production:
Natural gas (MMcf)................................. 289 1,336 7,857
Natural gas liquids (MBbls)........................ 30 25 177
Oil and condensate (MBbls)......................... 176 487 381
Proved reserves sold (MMcfe)......................... 24,481 19,435 414,063
20
23
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
----------------------------------
1993 1992 1991
-------- -------- --------
Revenues (in thousands):
Natural gas...................................... $141,798 $157,672 $169,907
Natural gas liquids.............................. 61,427 59,669 62,031
Oil and condensate............................... 12,428 18,701 16,111
-------- -------- --------
Total......................................... $215,653 $236,042 $248,049
-------- -------- --------
-------- -------- --------
Natural Gas Production (MMcf):
Hugoton.......................................... 47,476 48,592 63,367
West Panhandle................................... 23,786 26,380 23,591
Other............................................ 8,558 14,555 21,564
-------- -------- --------
Total......................................... 79,820 89,527 108,522
-------- -------- --------
-------- -------- --------
Natural Gas Liquids Production (MBbls):
Hugoton.......................................... 1,481 898 1,235
West Panhandle................................... 3,480 3,794 3,279
Other............................................ 89 148 211
-------- -------- --------
Total......................................... 5,050 4,840 4,725
-------- -------- --------
-------- -------- --------
Oil and Condensate Production (MBbls):
Hugoton.......................................... 104 249 226
West Panhandle................................... 153 -- --
Other............................................ 481 735 541
-------- -------- --------
Total......................................... 738 984 767
-------- -------- --------
-------- -------- --------
Average Prices:
Natural gas (per Mcf)*........................... $ 1.79 $ 1.72 $ 1.54
Natural gas liquids (per Bbl).................... $ 12.14 $ 12.32 $ 13.07
Oil and condensate (per Bbl)..................... $ 16.63 $ 18.86 $ 20.23
- ---------------
* The average natural gas prices reported above for the years ended December
31, 1992 and 1991 reflect gains of $.06 per Mcf and $.08 per Mcf,
respectively, related to hedges of natural gas production in the natural
gas futures market.
Natural gas revenues decreased from 1991 to 1993 as a result of decreased
production partially offset by increased average prices for each year. Natural
gas liquids revenues did not fluctuate significantly as increases in natural gas
liquids production from 1991 to 1993 were offset by decreases in the average
prices received. Oil and condensate revenues increased in 1992 compared with
1991 as a result of increased production from Gulf Coast properties and from new
development in the Rocky Mountain area. The decrease in 1993 compared to 1992 is
a result of decreased production from the Gulf Coast properties and the sale of
a portion of the Rocky Mountain properties. Average oil prices received
decreased in each year from 1991 through 1993.
Natural gas production decreased by 18% from 1991 to 1992 and an additional
11% from 1992 to 1993. The decrease from 1991 to 1992 resulted primarily from
Mesa's reduced share of allowables in the Hugoton field. The decrease from 1992
to 1993 resulted primarily from a 5.4 Bcf decrease in Gulf Coast production and
a 6.1 Bcf decrease in West Panhandle field production recorded as gas balancing
sales. Gulf Coast natural gas production for 1993 declined, in part, because
1992 production included over 2.6 Bcf allocated to Mesa for the recovery of
capital costs paid by Mesa, as operator, on behalf of the Mesa Offshore Trust
(the "Trust"). Upon full recovery of costs (which occurred in late 1992), Mesa's
share of production from properties subject to the Trust's interest declined.
Hugoton field production in 1993 was relatively flat compared with 1992. Sales
from
21
24
the West Panhandle field, excluding gas balancing, increased by 3.4 Bcf in 1993
due to increased sales to industrial customers. Effective January 1, 1991, Mesa
and CIG entered into a contract which entitles Mesa to 77% of the ultimate
reserves and production from the West Panhandle field. As a result of this
contract, Mesa records its share of the total field production as revenue, even
though its actual sales volumes are presently less than 77% of the total
cumulative field production. Entitlement production in excess of sales totaled
4.8 Bcf in 1991, 6.8 Bcf in 1992 and .7 Bcf in 1993. See additional 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.
Allowables are assigned to individual wells based on a series of calculations
which are influenced 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. In October 1991, Mesa's share of
Hugoton field allowables was substantially reduced below historical levels. This
reduction resulted from Mesa's aggressive production and drilling practices
between 1989 and 1991, which caused the pressures and deliverability of Mesa's
wells to decline relative to those of other operators in the field. The KCC has
recently issued new regulations relating to calculations of well deliverability,
allocation of allowables, and makeup of underages in the Hugoton field.
Generally, Mesa expects the new regulations to increase its allowable share and
add 15 to 20 Bcf to production volumes over the next three years.
Natural gas liquids production increased by approximately 7% from 1991 to
1993 as a result of increases in West Panhandle and Hugoton field liquids
production. In the fourth quarter of 1992, Mesa completed the expansion of its
Fain natural gas processing plant in the West Panhandle field, increasing its
natural gas inlet capacity from 90 MMcf per day to 120 MMcf per day. In the
third quarter of 1993, the Satanta plant in the Hugoton field was completed. The
new 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.
Natural gas prices increased from 1991 to 1992 and increased again in 1993.
According to the American Gas Association, aggregate domestic demand for natural
gas has increased in each of the last three years. Prices were positively
affected by colder-than-normal spring temperatures in 1993 and a hurricane in
the Gulf of Mexico in 1992.
Oil and condensate prices decreased in each year from 1991 through 1993
reflecting the continuing downturn in market prices since the end of the Persian
Gulf war in early 1991. Natural gas liquids prices generally fluctuate with oil
prices.
COSTS AND EXPENSES
Mesa's aggregate costs and expenses declined by approximately 5% from 1992
to 1993 due primarily to decreases in exploration and depreciation, depletion
and amortization expenses partially offset by an increase in lease operating
expenses. Lease operating expenses were $8.0 million greater in 1993 than in
1992 due to increased production costs in the West Panhandle field. Exploration
charges were $7.3 million lower in 1993 than in 1992 as a result of exploratory
dry hole expense in the Gulf Coast area in 1992. Depreciation, depletion and
amortization expense was $13.8 million lower in 1993 than in 1992 due primarily
to lower production in 1993.
Mesa's aggregate costs and expenses in 1992 were slightly lower than in
1991. Exploration charges were $5.3 million greater in 1992 than in 1991 as a
result of exploratory dry hole expense in the Gulf Coast area in 1992.
Depreciation, depletion and amortization expense was $3.1 million lower in 1992
than in 1991 primarily due to lower production in 1992. Certain components of
lease operating expenses and production and other taxes decreased in 1992 from
1991 as a result of the 1991 property sales. These decreases, however, were
substantially offset by an increase in ad valorem taxes in Kansas and the
increase in production and gathering costs associated with entitlement
production in the West Panhandle field. See additional discussion below under
"Production Allocation Agreement."
22
25
The table below presents Mesa's lease operating costs by area of operation
(in thousands):
YEARS ENDED DECEMBER 31
-------------------------------
1993 1992 1991
------- ------- -------
Hugoton............................................... $10,001 $ 9,251 $ 9,113
West Panhandle........................................ 29,897 23,230 21,224
Other................................................. 11,921 11,378 16,532
------- ------- -------
$51,819 $43,859 $46,869
------- ------- -------
------- ------- -------
Hugoton field operating expenses have not increased substantially over the
last three years. The 1993 increase is a result of additional costs from added
compression facilities and from the new Satanta processing plant. West Panhandle
field operating expenses increased significantly in 1992 and in 1993. The
increases are primarily a result of increased gathering and administrative fees
paid to CIG as operator of the gathering system in the West Panhandle field.
Operating expenses in Mesa's other producing areas decreased in 1992 from 1991
due to property sales.
OTHER INCOME (EXPENSE)
Interest expense in 1993 was not materially different than 1992 as average
aggregate debt outstanding did not materially change. Interest expense decreased
by $7.4 million from 1991 to 1992 primarily due to a $49 million decrease in
weighted average debt outstanding.
Results of operations for the years 1993, 1992 and 1991 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
------------------------------------
1993 1992 1991
-------- ------- -------
Securities gains (losses)........................ $ 3,954 $ 7,808 $(2,060)
Gains on dispositions of oil and gas
properties..................................... 9,600 12,250 33,749
Gain from collection of note receivable.......... 18,450 -- --
Litigation settlement............................ (42,750) -- --
Gain from adjustment of contingency reserve...... 24,000 -- --
Expense of debt exchange transaction............. (9,651) -- --
Expense of corporate conversion transaction...... -- (2,144) (6,500)
Other............................................ 3,235 (3,479) (4,222)
-------- ------- -------
$ 6,838 $14,435 $20,967
-------- ------- -------
-------- ------- -------
The securities gains (losses) relate to Mesa's investments in marketable
securities and futures contracts that are not accounted for as hedges of
production. See discussion above under "Results of Operations" regarding oil and
gas property sales. The gain recorded from collection of a note receivable
relates to a note receivable from Bicoastal Corporation, which was in
bankruptcy. Mesa's claims in the bankruptcy exceeded its recorded receivable. As
of year-end 1993, Mesa had collected the full amount of its allowed claims plus
a portion of the interest due on such claims.
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 Mesa's predecessor 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. The Court approved the settlement on February 28, 1994
and Mesa issued additional 12 3/4% secured discount notes due June 30, 1998 with
a face amount of $48.2 million. Mesa used the proceeds from the issuance of
notes of $42.8 million to pay its share of the settlement.
23
26
In the fourth quarter of 1993, Mesa completed a settlement with the
Internal Revenue Service ("IRS") resolving all tax issues relating to the 1984
through 1987 tax returns of Mesa's predecessor. 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 debt
exchange completed in 1993. See additional discussion under "Capital Resources
and Liquidity" below. The corporate conversion expense relates to costs
associated with the year-end 1991 conversion of Mesa Limited 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 1993, 1992 and 1991, Mesa produced and sold 74%, 61% and
58%, 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.
YEARS ENDED DECEMBER 31
------------------------------------
1993 1992 1991
------- -------- -------
(DOLLARS IN THOUSANDS)
Revenues accrued................................. $ 5,145 $ 23,270 $17,378
Costs and expenses accrued....................... (1,059) (6,073) (4,362)
Depreciation, depletion and amortization......... (1,244) (10,764) (7,741)
------- -------- -------
$ 2,842 $ 6,433 $ 5,275
------- -------- -------
------- -------- -------
Production Accrued:
Natural gas (MMcf)............................. 740 6,772 4,834
Natural gas liquids (MBbls).................... 106 972 671
At December 31, 1993, the long-term gas balancing receivable from CIG, net
of accrued costs, relating to the PAA was $34.3 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 natural 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
its entire 35 Bcf entitlement in 1993.
CAPITAL RESOURCES AND LIQUIDITY
Financial Condition and Cash Requirements
Mesa is a highly leveraged company with $1.2 billion of long-term debt. In
recent years, Mesa has repaid or refinanced over $1.6 billion of its long-term
debt. The most recent transaction was completed in 1993 when almost $600 million
of subordinated notes and $100 million of bank debt was restructured in a debt
exchange transaction. See additional discussion below. In 1994, Mesa intends to
continue efforts to reduce, refinance and restructure its debt, including
through the issuance of new equity securities.
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27
Mesa owns and operates its oil and gas properties through direct and
indirect subsidiaries. HCLP owns substantially all of Mesa's Hugoton field
natural gas properties. HCLP was established in 1991 to own these properties and
to issue the HCLP Secured Notes. The assets and cash flows of HCLP are dedicated
to service HCLP's debt and are not available to pay creditors of Mesa or its
subsidiaries other than HCLP. 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, 1993, MOC owned an approximate 81% limited partnership interest in
HCLP. Subsequent to December 31, 1993, MOC received an additional 18% interest
in HCLP from another subsidiary as partial payment for intercompany debt.
The following table summarizes certain components of Mesa's financial
position and cash flows as of and for the year ended December 31, 1993 (in
thousands):
OTHER
SUBSIDIARIES
MOLP(A) HCLP COMBINED TOTAL
-------- -------- ------------ ------------
Debt:
HCLP Secured Notes..................... $ -- $541,600 $ -- $ 541,600
Credit Agreement and other............. 64,453 -- -- 64,453
12 3/4% secured discount notes(b)...... 472,939 -- -- 472,939
12 3/4% unsecured discount notes....... 148,576 -- -- 148,576
12% subordinated notes................. 6,336 -- -- 6,336
13 1/2% subordinated notes............. 7,390 -- -- 7,390
-------- -------- ------------ ------------
$699,694 $541,600 $ -- $ 1,241,294
-------- -------- ------------ ------------
-------- -------- ------------ ------------
Cash and securities(c)................... $ 16,198 $ 40,446 $ 93,384 $ 150,028
-------- -------- ------------ ------------
-------- -------- ------------ ------------
Working capital (deficit)................ $ (8,494) $ (9,692) $ 94,344 $ 76,158
-------- -------- ------------ ------------
-------- -------- ------------ ------------
Restricted cash (in noncurrent assets)... $ -- $ 62,649 $ -- $ 62,649
-------- -------- ------------ ------------
-------- -------- ------------ ------------
Operating cash flows before interest..... $ 34,976 $ 72,154 $ (529) $ 106,601
Interest payments, net(d)................ (30,547) (50,185) 2,051 (78,681)
-------- -------- ------------ ------------
Cash flows from operating activities..... $ 4,429 $ 21,969 $ 1,522 $ 27,920
-------- -------- ------------ ------------
-------- -------- ------------ ------------
- ---------------
(a) MOLP was merged into MOC on January 5, 1994.
(b) In March 1994, the Company 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)."
(c) Included in working capital (deficit).
(d) Cash interest payments, net of interest income.
The HCLP Secured Notes, for which HCLP is the sole obligor, are secured by
its 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. Mesa's bank credit agreement, as amended (the "Credit
Agreement"), is a credit facility under which approximately $59 million of
borrowings and $10 million of letter of credit obligations were outstanding at
December 31, 1993. Obligations under the Credit Agreement are secured by a first
lien on MOC's West Panhandle properties, Mesa's equity interest in MOC and a 76%
equity interest in HCLP. Borrowings under the Credit Agreement are due in
various installments through June 1995. Mesa and MOC are obligors under the
Credit Agreement. The 12 3/4% secured discount notes are due in 1998 and are
secured by second liens on MOC's West Panhandle properties and a 76% equity
interest in HCLP. The 12 3/4% unsecured discount notes are due in 1996. The 12%
subordinated notes are unsecured and have a stated maturity of August 1996 and
the 13 1/2% subordinated notes (also unsecured) have a stated maturity of May
1999. The 12 3/4% secured discount notes, 12 3/4% unsecured discount notes
(together, the "Discount Notes") and both issues of subordinated notes are
obligations of MOC, Mesa and Mesa Capital Corporation, a financing subsidiary of
MOC.
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28
On August 26, 1993, Mesa completed a debt exchange (the "Debt Exchange")
whereby new debt securities (primarily the Discount Notes) and $13.2 million in
cash were issued in exchange for substantially all of the 12% and 13 1/2%
subordinated notes ("Subordinated Notes") and accrued interest thereon. Prior to
the completion of the Debt Exchange, there had been $600 million of principal
outstanding under the Subordinated Notes and approximately $55.0 million of
accrued interest. The new Discount Notes accrue, but do not pay, interest
through June 30, 1995, after which interest will be payable semiannually in
cash, commencing December 31, 1995. The Debt Exchange results in deferrals of
$75 million per year of interest payments which would have been paid from
mid-1993 through June 30, 1995.
In connection with the Debt Exchange, Mesa and its bank lenders amended the
Credit Agreement in order to extend the payment of a portion of the outstanding
principal, which was scheduled to mature in June 1994 (or earlier as a result of
the then current default in the payment of interest on the Subordinated Notes,
which default was cured upon completion of the Debt Exchange), and to amend
certain covenants thereunder, including a reduction in Mesa's tangible adjusted
equity requirement, as defined. In return, the banks received, among other
things, additional security, earlier payment of a portion of the outstanding
principal and an increase in the rate of interest payable on the loans.
The following tables summarize Mesa's 1993 actual and 1994 through 1997
forecast cash requirements, assuming no changes in its capital structure, for
interest, debt principal and capital expenditures (in thousands):
ACTUAL FORECAST
------- -----------------------------------------
1993 1994 1995 1996 1997
------- -------- -------- -------- --------
HCLP:
Interest payments, net(a).......... $50,185 $ 48,100 $ 43,600 $ 38,500 $ 33,600
Principal repayments............... 39,250 42,900 39,300 45,400 46,700
Capital expenditures(b)............ 8,090 9,700 9,200 3,900 --
------- -------- -------- -------- --------
$97,525 $100,700 $ 92,100 $ 87,800 $ 80,300
------- -------- -------- -------- --------
------- -------- -------- -------- --------
MOC:
Interest payments, net(a).......... $30,547 $ 1,900 $ 52,700 $103,300 $101,500
Principal repayments(c)............ 40,852 24,800 39,600 185,100 --
Capital expenditures(b)............ 20,622 17,800 19,200 20,400 8,700
------- -------- -------- -------- --------
$92,021 $ 44,500 $111,500 $308,800 $110,200
------- -------- -------- -------- --------
------- -------- -------- -------- --------
- ---------------
(a) Cash interest payments, net of interest income.
(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.
Contractual commitments with a major gas purchaser in the Hugoton field
require expenditures, primarily for compression, of approximately $7.1
million by HCLP during 1994 and 1995, which amounts are included in
amounts set forth in the table for such years. Mesa may incur capital
expenditures in addition to those reflected in the table.
(c) Does not consider potential acceleration if Mesa's tangible adjusted equity
falls below the requirement set forth in the Credit Agreement. See
discussion under "Debt Covenants."
Debt Covenants
The Credit Agreement contains restrictive covenants which require Mesa to
maintain tangible adjusted equity, as defined, of at least $50 million and a
ratio of cash flow and available cash to debt service, as each is defined, of at
least 1.50 to 1. At December 31, 1993, tangible adjusted equity was $114.9
million and the ratio was 2.32 to 1.
Assuming no changes in its capital structure or in existing business
conditions, Mesa's financial forecasts indicate that it will continue to report
net losses and that tangible adjusted equity, as defined, is likely to fall
below the $50 million requirement in the second half of 1994. The financial
forecasts also indicate that Mesa
26
29
will have adequate financial resources, including available cash and securities,
to satisfy any obligations which may become due under the Credit Agreement in
the event the tangible adjusted equity covenant is not satisfied and cannot be
renegotiated or compliance therewith waived. At December 31, 1993, Mesa had
approximately $110 million of cash and securities excluding cash held at HCLP.
In addition, payment of the settlement amount to Unocal did not cause the ratio
of cash flow and available cash to debt service to fall below the required
level.
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 and Alternatives
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 HCLP properties, together with cash held
within HCLP, are expected, under Mesa's current operating plan, to generate
sufficient cash flow to meet HCLP's required principal, interest and capital
obligations. However, HCLP cash flows are not expected to be sufficient to
permit HCLP to distribute any excess cash until at least 1995. In addition, Mesa
may advance as much as $10 million to HCLP in 1994 to cover HCLP capital
expenditures in excess of required scheduled capital expenditures. Mesa expects
production and prices related to MOC's properties to generate cash from
operating activities which, together with available cash and securities
balances, are expected to be sufficient to cover MOC's debt principal and
interest obligations and capital expenditures through December 31, 1995.
On December 31, 1995, Mesa will begin making interest payments on the
Discount Notes. Assuming no changes in Mesa's capital structure prior to such
date, Mesa will be required to make cash interest payments related to the
Discount Notes totaling approximately $51 million on December 31, 1995 and cash
interest payments totaling approximately $90 million during 1996. In addition,
the 12 3/4% unsecured discount notes in the amount of $178.8 million and 12%
subordinated notes in the amount of $6.3 million become due in mid-1996. Mesa's
current financial forecasts indicate that Mesa will be unable to fund such
payments in 1996 with cash flows from operating activities and available cash
and securities balances. Depending on industry and market conditions, Mesa may
generate cash by issuing new equity or debt securities or by selling assets.
However, Mesa has limited ability to sell assets since its two largest assets,
its interests in the Hugoton and West Panhandle fields, are pledged under
long-term debt agreements. Mesa intends to continue its efforts to strengthen
its financial condition by raising equity capital and applying the proceeds
thereof to retire debt, and to issue new lower-cost debt to refinance its
existing higher-cost debt securities. There can be no assurance that Mesa will
be able to raise equity capital or otherwise refinance its debt.
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 3% of total equivalent production in
1993 compared with 12% during the same period in 1992. 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
and in commodity and 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.
27
30
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements, and notes thereto, together with
report of Arthur Andersen & Co. dated March 4, 1994, and supplementary data are
included in this Form 10-K under Item 14 on pages F-2 through F-32.
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 Mesa appears in
Mesa's Proxy Statement for the 1994 Annual Meeting of Stockholders ("Proxy
Statement"), which is to be filed with the Commission, 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, which is to be filed with the Commission, and such information
(other than information that is not required to be set forth in this 10-K) is
incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The presentation of the Security Ownership of Certain Beneficial Owners and
Management of the Registrant appears in the Proxy Statement, which is to be
filed with the Commission, and such information is incorporated by reference
herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information in Item 11, "Executive Compensation," and in the Proxy
Statement under "Election of Directors," which is to be filed with the
Commission, 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-28
(a)(2) Consolidated Financial Statements and Schedules
Schedule V -- Property, Plant and Equipment................................ S-2
Schedule VI -- Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment........................... S-3
Schedule X -- Supplementary Income Statement Information................... S-4
28
31
Schedules other than those listed above are 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
(Exhibit 4(f) to the Company's Form 10-Q/A dated June 30, 1993).
*4.2 -- 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).
*4.3 -- 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/A dated June 30, 1991).
*4.4 -- 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).
*4.5 -- 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).
*4.6 -- 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).
The Registrant agrees to furnish to the Commission upon request any
instruments defining the rights 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).
29
32
*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 -- 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).
*10.13 -- 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).
*10.14 -- 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).
*10.15 -- "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).
*10.16 -- 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).
*10.17 -- 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).
30
33
*10.18 -- 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).
*10.19 -- 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).
*10.20 -- 1991 Stock Option Plan of the Company (Exhibit 10(v) to the Company's
Form 10-K dated December 31, 1991).
*10.21 -- 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).
*10.22 -- 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).
*10.23 -- Conversion Agreement dated as of December 31, 1991 between the
Company, Boone Pickens and Pickens Operating Co. (Exhibit 10(y) to
the Company's Form 10-K dated December 31, 1991).
*10.24 -- 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).
*10.25 -- Split-Dollar Insurance Agreements dated June 29, 1992 by and between
Mesa Operating Limited Partnership and Boone Pickens and Paul Cain,
respectively, and Collateral Assignments dated as of June 29, 1992 by
Boone Pickens and Paul Cain, respectively (Exhibit 10(aa) to the
Company's Form 10-K dated December 31, 1992).
*10.26 -- 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).
10.27 -- Agreement of Merger, dated as of January 5, 1994, entered into by and
among MESA Inc., Boone Pickens and certain other parties.
22 -- List of Subsidiaries of the Company.
24 -- Consent of DeGolyer and MacNaughton.
28 -- Summary Report of Mesa relating to proved oil and gas reserves at
December 31, 1993.
(b) Reports on Form 8-K
1. Current Report on Form 8-K dated January 11, 1994 regarding a series of
merger transactions resulting in the conversion of each of Mesa's subsidiary
partnerships, other than Hugoton Capital Limited Partnership, to corporate form.
2. Current Report on Form 8-K dated January 12, 1994 regarding the Unocal
litigation settlement.
31
34
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
(Boone Pickens,
Chief Executive Officer)
Date: March 8, 1994
---------------------
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 8, 1994
(Boone Pickens) Chairman of the Board of
Directors (Principal
Executive Officer)
/s/ PAUL W. CAIN President and Director March 8, 1994
(Paul W. Cain)
/s/ WILLIAM D. BALLEW Controller (Principal March 8, 1994
(William D. Ballew) Accounting Officer and Acting
Principal Financial Officer)
/s/ JOHN S. HERRINGTON Director March 8, 1994
(John S. Herrington)
/s/ WALES H. MADDEN, JR. Director March 8, 1994
(Wales H. Madden, Jr.)
/s/ FAYEZ S. SAROFIM Director March 8, 1994
(Fayez S. Sarofim)
/s/ ROBERT L. STILLWELL Director March 8, 1994
(Robert L. Stillwell)
/s/ J. R. WALSH, Jr. Director March 8, 1994
(J. R. Walsh, Jr.)
32
35
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-28
F-1
36
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, 1993 and 1992, 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, 1993. These financial statements and the schedules referred to below are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and schedules 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 the Company will be unable to
fund certain principal and interest payments on its debt in 1996 with cash flows
from operating activities and available cash and securities balances. Depending
on industry and market conditions, the Company may generate cash by issuing new
equity or debt securities or selling assets. However, the Company has a limited
ability to sell assets and there can be no assurances that the Company will be
able to raise equity capital or otherwise 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, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedules listed
in Item 14(a)(2) are presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic financial statements.
These schedules have been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Houston, Texas
March 4, 1994
F-2
37
MESA INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEARS ENDED DECEMBER 31
-------------------------------------
1993 1992 1991
--------- --------- ---------
Revenues:
Natural gas........................................... $ 141,798 $ 157,672 $ 169,907
Natural gas liquids................................... 61,427 59,669 62,031
Oil and condensate.................................... 12,428 18,701 16,111
Other................................................. 6,551 1,070 1,497
--------- --------- ---------
222,204 237,112 249,546
--------- --------- ---------
Costs and Expenses:
Lease operating....................................... 51,819 43,859 46,869
Production and other taxes............................ 20,332 18,631 18,945
Exploration charges................................... 2,705 10,008 4,691
General and administrative............................ 25,237 24,460 27,837
Depreciation, depletion and amortization.............. 100,099 113,933 117,076
--------- --------- ---------
200,192 210,891 215,418
--------- --------- ---------
Operating Income........................................ 22,012 26,221 34,128
--------- --------- ---------
Other Income (Expense):
Interest income....................................... 10,704 13,504 16,512
Interest expense...................................... (142,002) (143,392) (150,770)
Gains on dispositions of oil and gas properties....... 9,600 12,250 33,749
Securities gains (losses)............................. 3,954 7,808 (2,060)
Litigation settlement................................. (42,750) -- --
Minority interest in loss............................. 4,318 3,854 3,419
Other................................................. 31,716 (9,477) (14,141)
--------- --------- ---------
(124,460) (115,453) (113,291)
--------- --------- ---------
Net Loss................................................ $(102,448) $ (89,232) $ (79,163)
--------- --------- ---------
--------- --------- ---------
Net Loss Per Common Share............................... $ (2.61) $ (2.31) $ (2.05)
--------- --------- ---------
--------- --------- ---------
Weighted Average Common Shares Outstanding.............. 39,272 38,571 38,571
--------- --------- ---------
--------- --------- ---------
(See accompanying notes to consolidated financial statements.)
F-3
38
MESA INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31
----------------------
1993 1992
--------- ---------
ASSETS
Current Assets:
Cash and cash investments.......................................... $ 138,709 $ 157,197
Marketable securities.............................................. 11,319 11,918
Accounts receivable................................................ 43,442 44,637
Other.............................................................. 2,732 5,498
---------- ----------
Total current assets....................................... 196,202 219,250
---------- ----------
Property, Plant and Equipment:
Oil and gas properties, wells and equipment, using
the successful efforts method of accounting..................... 1,846,237 1,851,555
Office and other................................................... 41,064 40,601
Accumulated depreciation, depletion and amortization............... (695,455) (611,905)
---------- ----------
1,191,846 1,280,251
---------- ----------
Other Assets:
Restricted cash of subsidiary partnership.......................... 62,649 64,339
Notes receivable................................................... -- 30,315
Gas balancing receivable........................................... 47,101 42,089
Other.............................................................. 35,584 40,279
---------- ----------
145,334 177,022
---------- ----------
$1,533,382 $1,676,523
---------- ----------
---------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt............................... $ 67,657 $ 44,555
Accounts payable and accrued liabilities........................... 33,375 39,397
Interest payable................................................... 19,012 32,445
---------- ----------
Total current liabilities.................................. 120,044 116,397
---------- ----------
Long-Term Debt....................................................... 1,173,637 1,241,600
---------- ----------
Deferred Revenue..................................................... 22,707 25,982
---------- ----------
Other Liabilities.................................................... 102,133 100,231
---------- ----------
Contingencies
Minority Interest.................................................... 2,732 7,961
---------- ----------
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 46,511,439 and 38,570,544 shares, respectively...... 465 386
Additional paid-in capital......................................... 303,344 273,198
Accumulated deficit................................................ (191,680) (89,232)
---------- ----------
112,129 184,352
---------- ----------
$1,533,382 $1,676,523
---------- ----------
---------- ----------
(See accompanying notes to consolidated financial statements.)
F-4
39
MESA INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31
-------------------------------------
1993 1992 1991
--------- --------- ---------
Cash Flows From Operating Activities:
Net loss.............................................. $(102,448) $ (89,232) $ (79,163)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization........... 100,099 113,933 117,076
Gains on dispositions of oil and gas properties.... (9,600) (12,250) (33,749)
Accreted interest on discount notes................ 49,160 -- --
Accrued interest exchanged for discount notes...... 15,395 -- --
Litigation settlement.............................. 42,750 -- --
Gain from adjustment of contingency reserves....... (24,000) -- --
Increase in gas balancing receivables.............. (4,942) (17,772) (15,520)
Decrease in deferred natural gas revenue........... (3,370) (10,287) (5,296)
Settlement of prior year federal income tax
claims........................................... (12,931) -- --
Natural gas hedging activities..................... 324 (8,357) 4,413
Securities (gains) losses.......................... (3,954) (7,808) 2,060
Minority interest in loss.......................... (4,318) (3,854) (3,419)
(Increase) decrease in accounts receivable......... 1,986 (585) 18,611
Increase (decrease) in payables and accrued
liabilities...................................... (15,887) (7,814) 11,909
Other.............................................. (344) 15,587 18,056
--------- --------- ---------
Net cash provided by (used in) operating
activities....................................... 27,920 (28,439) 34,978
--------- --------- ---------
Cash Flows From Investing Activities:
Capital expenditures.................................. (29,636) (69,201) (31,864)
Proceeds from dispositions of oil and gas
properties......................................... 26,118 11,424 428,063
Sales of marketable securities........................ 39,283 126,217 164,071
Purchases of marketable securities.................... (34,711) (102,161) (132,051)
Collection of notes receivable........................ 47,501 28,181 224
Other................................................. (6,461) (11,494) (28,764)
--------- --------- ---------
Net cash provided by (used in) investing
activities....................................... 42,094 (17,034) 399,679
--------- --------- ---------
Cash Flows From Financing Activities:
Repayments of long-term debt.......................... (80,102) (24,550) (927,585)
Long-term borrowings.................................. -- -- 716,550
Funding of restricted cash balance.................... -- -- (66,061)
Debt issuance costs................................... (9,651) -- (15,621)
Other................................................. 1,251 (4,935) (17,589)
--------- --------- ---------
Net cash used in financing activities.............. (88,502) (29,485) (310,306)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Investments.... (18,488) (74,958) 124,351
Cash and Cash Investments at Beginning of Year.......... 157,197 232,155 107,804
--------- --------- ---------
Cash and Cash Investments at End of Year................ $ 138,709 $ 157,197 $ 232,155
--------- --------- ---------
--------- --------- ---------
(See accompanying notes to consolidated financial statements.)
F-5
40
MESA INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(IN THOUSANDS)
COMMON STOCK ADDITIONAL
---------------- PAID-IN ACCUMULATED
SHARES AMOUNT CAPITAL DEFICIT
------ ------ ---------- -----------
Balance, December 31, 1990........................... 38,571 $386 $ 352,361 $ --
Net loss........................................... -- -- (79,163) --
------ ------ ---------- -----------
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)
------ ------ ---------- -----------
------ ------ ---------- -----------
(See accompanying notes to consolidated financial statements.)
F-6
41
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
MESA Inc., a Texas corporation, was formed in 1991 in connection with a
transaction (the Corporate Conversion) which reorganized the business of Mesa
Limited Partnership (the Partnership). The Partnership was formed in 1985 to
succeed to the business of Mesa Petroleum Co. (Original Mesa). Unless the
context otherwise requires, as used herein the term "Company" refers to MESA
Inc. and its subsidiaries taken as a whole and includes its predecessors.
Pursuant to the Corporate Conversion, the Partnership transferred
substantially all its assets and liabilities to the Company on December 31, 1991
in exchange for all outstanding shares of the Company's common stock. The common
units and general partner interests in the Partnership that were held by Boone
Pickens (the General Partner) (which would otherwise have been converted into
4.14% of the Company's common stock) were converted into a 4.14% general partner
interest in each direct subsidiary partnership of the Company. The Partnership
allocated 1.0 share of the Company's common stock for each common unit and 1.35
shares of the Company's common stock for each preference unit to its unitholders
(other than the General Partner). Concurrently, the Company effected a
one-for-five reverse split of the common stock and the Partnership distributed
to its former unitholders (other than the General Partner) .2 shares of common
stock for each common unit and .27 shares of common stock for each preference
unit.
Principles of Consolidation
The Company owns and operates its oil and gas properties and other assets
through various direct and indirect subsidiaries. At the beginning of 1993, the
Company owned a 95.86% limited partnership interest and the General Partner
owned a 4.14% general partner interest in the direct subsidiary partnerships.
The debt exchange described in Notes 2, 4 and 7 included issuance of
approximately $29.3 million of 0% convertible notes which were converted into
approximately 7.5 million shares of common stock prior to December 31, 1993. In
addition, on December 31, 1993, the General Partner converted approximately
one-fourth of his general partner interests into 416,890 shares of common stock.
As a result of these issuances of common stock, the Company's interest in the
direct subsidiaries increased to 97.38% and the general partner interest
decreased to 2.62%. The accompanying consolidated financial statements reflect
the consolidated accounts of the Company and its subsidiaries after elimination
of intercompany transactions. The general partner interest is reflected as a
minority interest.
In January 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 1,250,670 shares of common
stock, thereby eliminating the minority interest.
Certain reclassifications have been made to amounts reported in previous
years to conform to 1993 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
Investments in marketable securities are stated at the lower of cost or
market value and are classified as current or noncurrent, depending on
management's intent at the balance sheet date. Periodic changes in the stated
value of the marketable securities portfolios are reflected in income in the
case of current investments and in stockholders' equity in the case of
noncurrent investments. The cost of securities sold is determined on
F-7
42
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the first-in, first-out basis. The Company also enters into various futures
contracts which are not intended to be hedges of future natural gas or crude oil
production and are periodically adjusted to market prices. Gains and losses from
such contracts are included in securities gains (losses) in the consolidated
statements of operations.
In May 1993, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain
Investments in Debt and Equity Securities," which is required to be adopted in
1994. SFAS No. 115 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 current portfolio of securities
would be classified as trading securities under the provisions of SFAS No. 115
and would be reported at fair value, with unrealized gains and losses included
in earnings. The Company's securities transactions are currently reported as
cash flows from investing activities in the consolidated statements of cash
flows. Under the provisions of SFAS No. 115, cash flows from transactions in
trading securities will be classified as cash flows from operating activities.
The Company does not expect the adoption of SFAS No. 115 to have a material
effect on its financial position or results of operations.
Oil and Gas Properties
Under the successful efforts method of accounting, all costs of acquiring
unproved oil and gas properties and drilling and equipping exploratory wells are
capitalized pending determination of whether the properties have proved
reserves. If an exploratory well is determined to be nonproductive, the drilling
and equipment costs of the well are expensed at that time. All development
drilling and equipment costs are capitalized. Capitalized costs of proved
properties and estimated future dismantlement and abandonment costs are
amortized on a property-by-property basis using the unit-of-production method.
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 (SEC) 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.
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 natural
gas sales exceed its ownership share of production, the excess is recorded as
deferred revenue. Gas balancing receivables are recorded when the Company's
ownership share of production exceeds
F-8
43
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
its natural gas sales. The Company also accrues production expenses based on its
ownership share of production. At December 31, 1993, the Company had produced
and sold a net 13.6 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 $27.5 million. Substantially all of the
Company's gas balancing receivables and deferred revenue is 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 $8.3 million and $5.6
million in 1991 and 1992, respectively, and net losses of $.3 million in 1993
related to hedging activities. The Company did not enter into any new hedge
contracts in 1993. At December 31, 1993, the Company had no deferred gains or
losses related to hedging activities and did not own any natural gas futures
contracts accounted for as hedges.
Taxes
The Company provides for income taxes using the asset and liability method
under which deferred income taxes are recognized for the tax consequences of
"temporary differences" by applying enacted statutory tax rates applicable to
future years to differences between the financial statement carrying amounts and
the tax bases of existing assets and liabilities. The effect on deferred taxes
of a change in tax laws or tax rates is recognized in income in the period that
includes the enactment date.
(2) RESOURCES AND LIQUIDITY
The Company is highly leveraged but in recent years has repaid or
refinanced over $1.6 billion of long-term debt. The most recent transaction was
completed in 1993 when substantially all of the Company's $600 million of
subordinated notes and $100 million of bank debt was restructured in a debt
exchange transaction. In 1994, the Company intends to continue efforts to
reduce, refinance and restructure its debt, including through the issuance of
new equity securities.
At December 31, 1993, the Company's long-term debt, net of current
maturities, totaled approximately $1.2 billion (see Note 4). The Company also
had approximately $76 million of working capital; cash and securities totaled
approximately $150 million. Included in the $150 million of cash and securities
is $40 million of cash held by Hugoton Capital Limited Partnership (HCLP), an
indirect subsidiary partnership. The assets of HCLP (which include substantially
all of the Company's Hugoton field natural gas properties and approximately $63
million of restricted cash) are dedicated to service HCLP's $542 million of
secured debt (the HCLP Secured Notes) and are not available to pay creditors of
the Company or its other subsidiaries. See Note 4 for additional discussion. The
Company's cash flows from operating activities are substantially dependent on
the amount of oil and gas produced and the prices received for such production.
Production and prices received from HCLP properties, together with cash held by
HCLP, are expected, under the Company's current operating plan, to generate
sufficient cash flow to meet HCLP's required principal, interest and capital
obligations. However, HCLP's cash flows are not expected to be sufficient to
permit HCLP to distribute any excess cash to other Company subsidiaries until at
least 1995. The Company may advance as much as $10 million to HCLP in 1994 to
cover HCLP capital expenditures in excess of required scheduled capital
expenditures.
During the third quarter of 1993, the Company completed the debt exchange
(Debt Exchange) described in Note 4. The notes issued in the Debt Exchange
replaced substantially all of the Company's $600 million of previously
outstanding subordinated notes. The Debt Exchange resulted in the deferral of
cash interest requirements of approximately $75 million annually from mid-1993
through June 30, 1995. Completion of the Debt Exchange also resulted in an
amendment to the Company's bank credit agreement (Credit Agreement), which
advanced the maturity of $41 million of principal payments from 1994 to 1993 but
also extended the maturity of $40 million of principal and $10 million of letter
of credit obligations from 1994 to 1995. The
F-9
44
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company believes that completion of the Debt Exchange and amendments to the
Credit Agreement have increased its ability to obtain traditional equity or debt
financing to repay or refinance its indebtedness.
As a result of the completion of the Debt Exchange and the amendments to
the Credit Agreement, the Company expects to service its debt obligations and
meet capital expenditure requirements through 1995 with cash flows from
operating activities and available cash and securities balances. On December 31,
1995, the Company will begin making interest payments on the 12 3/4% secured
discount notes due June 30, 1998 and the 12 3/4% unsecured discount notes due
June 30, 1996 (together, the Discount Notes) issued in the Debt Exchange.
Assuming no changes in the Company's capital structure prior to such date, the
Company will be required to make cash interest payments related to the Discount
Notes totaling approximately $51 million on December 31, 1995 and approximately
$90 million during 1996. In addition, 12 3/4% unsecured discount notes in the
amount of $178.8 million and 12% subordinated notes in the amount of $6.3
million become due in mid-1996. The Company's current financial forecasts
indicate that the Company will be unable to fund such payments in 1996 with cash
flows from operating activities and available cash and securities balances.
Depending on industry and market conditions, the Company may generate cash by
issuing new equity or debt securities or selling assets. However, the Company
has a limited ability to sell assets since its two largest assets, its interests
in the Hugoton and West Panhandle fields, are pledged under long-term debt
agreements. The Company intends to continue its efforts to strengthen its
financial condition by raising equity capital and applying the proceeds thereof
to retire debt, and to issue new lower-cost debt to refinance its existing
higher-cost debt securities. However, there can be no assurances that the
Company will be able to raise equity capital or otherwise refinance its debt.
(3) MARKETABLE SECURITIES
The value of marketable securities is as follows (in thousands):
DECEMBER 31
---------------------
1993 1992
------- -------
Cost........................................................... $11,788 $12,167
Unrealized loss................................................ (469) (249)
------- -------
Market value................................................. $11,319 $11,918
------- -------
------- -------
For the year ended December 31, 1993, the Company recognized a net gain of
$4.0 million from its investments in securities and futures contracts compared
with a net gain of $7.8 million in 1992 and a net loss of $2.1 million in 1991.
The net securities 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 gains and losses recognized during a period include both
realized and unrealized gains and losses. During 1993, the Company realized net
gains of $2.3 million from securities transactions and futures contracts. The
Company realized a net gain from securities transactions and futures contracts
of $10.0 million in 1992 and a net loss of $7.8 million in 1991.
F-10
45
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) LONG-TERM DEBT
Long-term debt and current maturities are as follows (in thousands):
DECEMBER 31
-----------------------
1993 1992
--------- ---------
HCLP Secured Notes.......................................... $ 541,600 $ 580,850
Credit Agreement............................................ 59,148 100,000
12 3/4% secured discount notes.............................. 472,939 --
12 3/4% unsecured discount notes............................ 148,576 --
12% subordinated notes...................................... 6,336 300,000
13 1/2% subordinated notes.................................. 7,390 300,000
Other....................................................... 5,305 5,305
---------- ----------
1,241,294 1,286,155
Current maturities.......................................... (67,657) (44,555)
---------- ----------
Long-term debt.............................................. $1,173,637 $1,241,600
---------- ----------
---------- ----------
HCLP SECURED NOTES
HCLP holds substantially all of the Company's Hugoton field natural gas
properties. In 1991, HCLP issued $616 million of secured notes in a private
placement with a group of institutional lenders. The issuance replaced $550
million of bank debt and funded a $66 million restricted cash balance within
HCLP. The restricted cash balance 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 restricted cash balance is reduced
proportionately.
The HCLP Secured Notes were issued in 15 series and have final stated
maturities extending through 2012 but are expected to be retired earlier based
on the rate of production from the Hugoton properties. As of December 31, 1993,
approximately $75.0 million of principal has been repaid as scheduled. In
February 1994, an additional $21.4 million of principal was repaid as scheduled.
The HCLP Secured Notes outstanding at December 31, 1993 bear interest at fixed
rates ranging from 8.80% to 11.30% (weighted average 10.21%). Principal and
interest payments are made semiannually. Provisions in the HCLP Secured Note
agreements require interest rate premiums to be paid to the noteholders in the
event that the HCLP Secured Notes are repaid more rapidly or slowly than
scheduled in the agreements. Such premiums, if required, would increase the
effective interest rate of the HCLP Secured Notes.
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 are dedicated to service HCLP's debt
and are not available to pay creditors of the Company or its subsidiaries other
than HCLP.
Revenues received for production from HCLP's Hugoton properties are
deposited in a collection account maintained by a collateral agent (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. However, HCLP's cash flows are not expected to be sufficient to
permit HCLP to distribute any excess cash to other Company subsidiaries until at
least 1995.
F-11
46
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 (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
(10.21% at December 31, 1993). 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 the first quarter of 1992, the Company contributed $32 million in cash
to HCLP, which funds were previously not subject to the mortgage. A portion of
such funds has been used to supplement HCLP's cash flows in order to make
scheduled principal payments on the HCLP Secured Notes. At December 31, 1993,
approximately $10.3 million of HCLP's cash was not subject to the mortgage. In
February 1994, the Company contributed an additional $5.8 million to HCLP which,
along with the $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. The Company may also advance to HCLP up to $10 million in
1994 to fund expected capital expenditures in excess of scheduled capital
expenditures.
HCLP cash balances were as follows (in thousands):
DECEMBER 31
-------------------
1993 1992
------- -------
Cash included in current assets.................................. $40,446 $64,141
------- -------
------- -------
Restricted cash included in noncurrent assets.................... $62,649 $64,339
------- -------
------- -------
In connection with the formation of HCLP and the issuance of the HCLP
Secured Notes, Mesa Operating Co. (MOC), the successor to Mesa Operating Limited
Partnership, a Company subsidiary which owns substantially all of the limited
partnership interests of HCLP, entered into 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 $11.4 million in 1993 and $10.7 million in 1992.
CREDIT AGREEMENT
As of December 31, 1993, the Company had borrowed approximately $59.1
million under its Credit Agreement and had outstanding approximately $10.4
million in letter of credit obligations secured under the Credit Agreement. Upon
consummation of the Debt Exchange (see "Discount Notes" below and Note 2), the
Company and its bank lenders amended the Credit Agreement. Pursuant to the
amendment, the Credit Agreement was reduced from a $150 million revolving credit
facility to a credit facility providing for $80 million of initial borrowings
and $10 million in letter of credit obligations. The Company had borrowed $100
million under the Credit Agreement prior to completion of the Debt Exchange.
Accordingly, the Company made a $20 million principal payment under the Credit
Agreement on August 26, 1993 and agreed to make additional scheduled principal
payments of $10 million in the fourth quarter of 1993, $30 million in the first
half of 1994, and the remaining balance at final maturity in the second quarter
of 1995 (including an obligation to cash collateralize any remaining letter of
credit obligations outstanding at that time).
The terms of the amended Credit Agreement require prepayment of the next
scheduled principal payment in the amount of one-half of any proceeds from asset
sales or collections from Bicoastal Corporation (Bicoastal) (see Note 8). As a
result of proceeds from asset sales and collections from Bicoastal during 1993,
approximately $10.5 million of the $30 million due under the Credit Agreement in
the first half of 1994 was prepaid in 1993 and an additional $2.7 million was
prepaid in January 1994.
F-12
47
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The rate of interest payable on borrowings under the Credit Agreement is
the prime rate plus 1/2% or the Eurodollar rate plus 2 1/2% until borrowings
are reduced to $50 million, and thereafter reduced, subject to certain
conditions, to a rate equal to the Eurodollar rate plus 1 1/2% or the prime
rate. Obligations under the Credit Agreement are secured by a first lien on the
Company's West Panhandle field properties, by the Company's equity interest in
MOC and by 76% of MOC's equity interest in HCLP.
The amendments to the Credit Agreement reduced the Company's tangible
adjusted equity requirement, as defined, from $150 million to $50 million and
increased the Company's required ratio of cash flow and available cash to debt
service, as each is defined, from at least 1.25 to 1 to 1.50 to 1. At December
31, 1993, the Company's tangible adjusted equity, as defined, was $114.9 million
and the ratio of cash flow and available cash to debt service was 2.32 to 1.
Assuming no changes in its capital structure and in existing business
conditions, the Company's financial forecasts indicate that the Company will
continue to report net losses and that tangible adjusted equity, as defined, is
likely to fall below the $50 million requirement in the second half of 1994. The
financial forecasts also indicate that the Company will have adequate financial
resources, including available cash and securities balances, to satisfy any
obligations which may become due under the Credit Agreement in the event the
tangible adjusted equity covenant is not satisfied and cannot be renegotiated or
compliance therewith waived. At December 31, 1993, the Company had approximately
$110 million of cash and securities excluding cash held at HCLP. In addition,
payment of $42.8 million on March 3, 1994 to settle a lawsuit (see Note 9) did
not cause the ratio of cash flow and available cash to debt service to fall
below the required level.
The provisions of the Credit Agreement prohibit the Company from paying any
dividends to equity holders, other than those paid in the form of equity
securities.
DISCOUNT NOTES
The Debt Exchange was consummated on August 26, 1993. Under the terms of
the Debt Exchange, holders of approximately $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 approximately $28.6 million of
accrued interest claims thereon) received approximately $435.5 million initial
accreted value, as defined, of 12 3/4% secured discount notes due June 30, 1998;
$136.9 million initial accreted value of 12 3/4% unsecured discount notes due
June 30, 1996; $29.3 million principal amount of 0% convertible notes due June
30, 1998; and, in the case of 13 1/2% subordinated noteholders, $13.2 million in
cash. The new notes, which rank pari passu with each other, are senior in right
of payment to the remaining 12% and 13 1/2% subordinated notes (together, the
Subordinated Notes) and subordinate to all permitted first lien debt, as
defined, including the Credit Agreement.
The Discount Notes will bear no interest through June 30, 1995; however,
the accreted value, as defined, of both series will increase from May 1, 1993
through June 30, 1995 at 12 3/4% per year, compounded semiannually, with the
first compounding date being June 30, 1993. 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. The 0% convertible
notes earned no interest and were converted into approximately 7.5 million
shares of common stock in December 1993.
The 12 3/4% secured discount notes are secured by second liens on the
Company's West Panhandle field properties and on 76% of MOC's equity interest in
HCLP, both of which currently 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.
F-13
48
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company incurred approximately $9.6 million of costs associated with
completion of the Debt Exchange; such costs are included in the 1993
consolidated statement of operations as other income (expense).
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 is 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.
SUBORDINATED NOTES
The 12% subordinated notes are unsecured and mature in 1996. Interest on
these notes is payable quarterly and, at the option of the Company, may be paid
in common stock of the Company. The 13 1/2% subordinated notes are unsecured and
mature in 1999. Interest on these notes is payable semiannually in cash.
INTEREST AND MATURITIES
The aggregate interest payments made during 1993, 1992 and 1991 were
approximately $89.4 million, $142.7 million and $128.1 million, respectively.
Payment of approximately $64.6 million of interest incurred during 1993 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 1993
consolidated statement of operations.
The scheduled principal repayments of long-term debt for the next five
years are as follows (in millions):
1994 1995 1996 1997 1998
------ ------ ------ ------ ------
HCLP Secured Notes............................... $ 42.9 $ 39.3 $ 45.4 $ 46.7 $ 47.5
Credit Agreement(a).............................. 19.5 39.6 -- -- --
12 3/4% secured discount notes(b)................ -- -- -- -- 617.4
12 3/4% unsecured discount notes................. -- -- 178.8 -- --
12% subordinated notes........................... -- -- 6.3 -- --
Other............................................ 5.3 -- -- -- --
------ ------ ------ ------ ------
Total......................................... $ 67.7 $ 78.9 $230.5 $ 46.7 $664.9
------ ------ ------ ------ ------
------ ------ ------ ------ ------
- ---------------
(a) Excludes approximately $10 million in letter of credit obligations currently
outstanding and required to be cash collateralized in 1995.
(b) Includes $48.2 million of notes issued in March 1994 to settle the Unocal
lawsuit.
FAIR VALUE OF LONG-TERM DEBT
Based on borrowing rates currently available for secured debt with similar
maturities and credit rating, the fair value of the HCLP Secured Notes at
December 31, 1993 is estimated to be approximately $615 million.
Based on borrowing rates currently available for bank loans with similar
collateral, the fair value of the borrowings under the Credit Agreement at
December 31, 1993 is estimated to be their carrying value.
The Discount Notes are publicly traded but not listed on a national trading
exchange. Based on trading prices available at December 31, 1993, the fair value
of the 12 3/4% secured discount notes is estimated to be $487 million and the
fair value of the 12 3/4% unsecured discount notes is estimated to be $142
million.
F-14
49
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Subordinated Notes are publicly traded but have not experienced
significant activity since consummation of the Debt Exchange. Based on recent
trades, the fair values of the Subordinated Notes are not materially different
from their carrying value.
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.
(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
primary difference to the Company between the standards is that SFAS No. 109
allows recognition of deferred tax assets under certain circumstances.
In accordance with the SFAS No. 109 transition rules, the Company elected
to adopt the change in method of accounting for income taxes prospectively in
1993. Any cumulative effect on prior years resulting from prospective adoption
is required to be recorded as an adjustment to the Company's net loss 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 JANUARY 1
1993 1993
----------- ---------
Deferred tax asset............................................. $ 208 $ 174
Deferred tax liability......................................... (1) (6)
Valuation allowance............................................ (207) (168)
----------- ---------
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 JANUARY 1
1993 1993
----------- ---------
Tax basis of oil and gas properties in excess of financial
basis....................................................... $ 91 $ 95
Regular tax net operating loss carryforward................... 114 51
Other, net.................................................... 2 22
Valuation allowance........................................... (207) (168)
----------- ---------
Net deferred tax asset...................................... $ -- $ --
----------- ---------
----------- ---------
As of December 31, 1993, the Company had a regular tax net operating loss
carryforward of approximately $290 million. Additionally, the Company had an
alternative minimum tax loss carryforward available to offset future alternative
minimum taxable income of approximately $280 million. If not used, both of these
carryforwards will expire in 2007 and 2008.
On August 10, 1993, the Omnibus Budget Reconciliation Act of 1993 (the Act)
was signed into law resulting in, among other things, an increase in the top
Federal corporate income tax rate from 34% to 35%,
F-15
50
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
effective January 1, 1993. This and other tax law changes resulting from the Act
did not have a material effect on the Company's net deferred tax asset or
related valuation allowance.
The Company's income tax returns for 1991 through 1993, which include all
net operating loss carryforward amounts, and the tax returns of the Partnership
for 1990 and 1991 are subject to examination by the taxing authorities. If
examinations of the Partnership returns result in changes to taxable income or
loss, the taxable income or loss of the former partners and the tax basis of the
Company's assets will be changed accordingly.
The Company assumed from the Partnership any tax liabilities or refunds
which 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 (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. See Note
9 for discussion of a gain recognized in the fourth quarter of 1993 related to
the tax settlement and resolution and revaluation of other contingency amounts.
As of January 1, 1994, there are no remaining open tax years for Original Mesa
for federal income tax purposes.
(6) PROPERTY SALES
In April 1993, the Company sold a portion of its Rocky Mountain area
properties for approximately $7.1 million, after adjustments, and recorded a
gain on the sale of approximately $4.1 million. The Company also retained a
reversionary interest in the properties under which the Company will receive a
50% net profits interest in the properties after the purchaser has recovered its
investment and certain other costs and expenses.
In June 1993, the Company sold its interest in the deep portion of the
Hugoton field not owned by HCLP for approximately $19.0 million, after
adjustments, and recorded a gain on the sale of approximately $5.5 million.
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.
In April 1991, the Company sold its producing gas properties in the San
Juan Basin of New Mexico and Colorado for approximately $161 million in cash and
the assumption by the purchaser of approximately $2 million in liabilities
resulting in a gain of approximately $34 million.
In March 1991, the Company sold certain of its producing oil and gas
properties and undeveloped leasehold acreage in the Texas Panhandle and in
Oklahoma for an aggregate of approximately $267 million in cash and the
assumption by the purchasers of approximately $7 million in liabilities. The
Company recognized a loss of $75 million in 1990 as a result of these
transactions.
(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. Subsequent to year end, the remaining 2.62%
general partner interest was converted into approximately 1.25 million shares of
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.
Pursuant to the Debt Exchange (see Note 4), the Company issued
approximately $29.3 million of 0% convertible notes which were converted into
approximately 7.5 million shares of common stock of the Company in the fourth
quarter of 1993.
F-16
51
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company has authorized 10 million shares of preferred stock. No shares
of preferred stock have been issued as of December 31, 1993.
(8) NOTES RECEIVABLE
As of December 31, 1992, notes receivable consisted primarily of claims
against Bicoastal. A plan of reorganization for Bicoastal was approved by the
Bankruptcy Court in September 1992. At such time, the Company held allowed
claims of $68 million, exclusive of interest. 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 amount representing a portion of
its interest claims. As a result, the Company recorded gains in the third and
fourth quarters of 1993 of approximately $13.8 million and $4.7 million,
respectively, relating to collections in excess of the recorded receivable.
(9) CONTINGENCIES
UNOCAL
The Company was subject to a lawsuit relating to a 1985 investment in
Unocal which asserted that certain profits allegedly realized by Original Mesa
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. The loss is included as other income (expense) in
the 1993 consolidated statement of operations and the obligation is included in
other liabilities in the December 31, 1993 consolidated balance sheet.
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 has 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 is the result of CIG's use of an
improper gas sales price upon which to calculate royalties and that the proper
price should be determined pursuant to a pricing clause in a July 1, 1967
amendment to the Gas Lease. 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 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 $450 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
F-17
52
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
royalties for all periods were properly computed and paid and (ii) that
plaintiffs' claims with respect to all periods prior to October 1, 1988 (which
appear to account for the substantial portion of the claims) were explicitly
released by a 1988 written agreement among plaintiffs, CIG and the Company and
are further barred by the statute of limitations. If the plaintiffs were to
prevail, the manner in which any resulting liability would be shared between the
Company and CIG would depend on the resolution of issues relating to the
contractual agreements and the relationship between the Company, CIG and the
lessors during the period in question.
No determination can be made at this time as to the ultimate outcome of the
litigation and no trial date has been set.
PREFERENCE UNITHOLDERS
The Company is a defendant in lawsuits related to the Corporate Conversion
pending 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 of the Partnership 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. Discovery has commenced and is proceeding in
the litigation for which the Court has set an August 1, 1994 trial date.
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 the Masterson lawsuit, preference unitholder lawsuits
or any of these other matters to have a material adverse effect on its financial
position or results of operations.
The Company assumed certain litigation and tax-related obligations from
Original Mesa and the Partnership and also recorded certain contingent
liabilities relating to various matters, including litigation, office space
leases and retirement benefit obligations, in conjunction with the 1986
acquisition of Pioneer Corporation (Pioneer) and the 1988 acquisition of Tenneco
Inc.'s midcontinent division. During the fourth quarter of 1993, the Company
settled certain claims with the IRS (see Note 5) and resolved or revalued
certain other contingent liabilities to reflect actual or estimated liabilities.
The Company had previously reserved for the IRS claims and certain other
contingencies in excess of the actual or estimated liabilities. As a result, the
Company recorded a net gain of $24 million in the fourth quarter of 1993.
(10) EMPLOYEE BENEFIT PLANS
RETIREMENT PLANS
The Company maintains two defined contribution retirement plans for the
benefit of its employees. The Company expensed $3.2 million in 1993, $3.3
million in 1992, and $3.1 million in 1991 in connection with these plans.
F-18
53
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. The exercise price of 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, 1993, the following
stock options were outstanding:
NUMBER OF
OPTIONS
----------
Outstanding at December 31, 1992.......................................... 1,352,000
Granted................................................................. 605,950
Exercised............................................................... (11,000)
Forfeited............................................................... (13,900)
----------
Outstanding at December 31, 1993.......................................... 1,933,050
----------
----------
The outstanding options at December 31, 1993 are detailed as follows:
NUMBER OF DATE OF EXERCISE PRICE
OPTIONS GRANT PER SHARE EXERCISABLE
------------ -------- -------------- -----------
1,166,000....................................... 01/10/92 $ 6.8125 641,300
10,000....................................... 05/19/92 4.1250 5,500
153,000....................................... 10/02/92 11.6875 84,150
119,050....................................... 05/18/93 5.8125 35,715
485,000....................................... 11/10/93 7.3750 --
--------- -------
1,933,050....................................... 766,665
--------- -------
--------- -------
Options are exercisable from 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, 1993, options for 45,950 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 (Transition Obligation) will be
amortized over the remaining life of the retirees or 20 years, whichever is
shorter.
The Company maintains two separate plans for providing postretirement
medical benefits. One plan covers the Company's retirees and current employees
(the Mesa Plan). The other plan relates to the retirees of Pioneer, which was
acquired by the Company in 1986 (the Pioneer Plan). Under the Mesa Plan,
employees who retire from the Company and who have had at least 10 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
F-19
54
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1993 (in thousands):
MESA PIONEER
PLAN PLAN TOTAL
------- ------- -------
Accumulated postretirement benefit obligation (APBO):
Retirees and dependents................................... $ 956 $11,162 $12,118
Active employees -- fully eligible........................ 330 -- 330
Other active employees.................................... 486 -- 486
------- ------- -------
Total APBO............................................. 1,772 11,162 12,934
Unrecognized Transition Obligation.......................... (1,587) (2,695) (4,282)
------- ------- -------
Accrued postretirement benefit obligation................... $ 185 $ 8,467(a) $ 8,652
------- ------- -------
------- ------- -------
- ---------------
(a) The Company established an accrued liability associated with the Pioneer
Plan in conjunction with its acquisition of Pioneer in 1986.
For measurement purposes, the 1993 annual rate of increase in per capita
cost of covered health care benefits was assumed to be 12.5% for those
participants under age 65 and 11.0% 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, 1993 by approximately $735,000 and the aggregate of the
service and the interest cost components of net periodic postretirement benefit
cost for the year ended December 31, 1993 by approximately $77,000. The net
periodic postretirement benefit cost for the year ended December 31, 1993 was
approximately $1.4 million based on these assumptions.
The discount rate used in determining the APBO as of December 31, 1993 was
8.0%.
The following table presents the Company's cost of postretirement benefits
other than pensions for the years ended December 31 (in thousands):
1993 1992 1991
------ ------ ------
Net periodic postretirement benefit cost:
Service cost.............................................. $ 96 $ -- $ --
Interest cost............................................. 988 -- --
Amortization of Transition Obligation..................... 276 -- --
------ ------ ------
$1,360 $ --(a) $ --(a)
------ ------ ------
------ ------ ------
Actual cost of providing benefits:
Mesa Plan(b).............................................. $ 123 $ 205 $ 131
Pioneer Plan(c)........................................... 909 1,356 952
------ ------ ------
$1,032 $1,561 $1,083
------ ------ ------
------ ------ ------
F-20
55
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(a) SFAS No. 106 was adopted effective January 1, 1993.
(b) Actual costs of providing benefits in 1992 and 1991 under the Mesa Plan were
recorded to expense in the consolidated statements of operations in those
years. Actual cost of providing benefits in 1993 under the Mesa Plan were
applied as incurred against the accrued postretirement benefit obligation.
(c) Actual costs of providing benefits in 1992 and 1991 under the Pioneer Plan
were applied as incurred against the previously accrued liability. Actual
cost of providing benefits in 1993 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 10 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 has fully funded the life insurance
policies and has no further obligations under such policies or under the
deferred compensation agreements.
(11) MAJOR CUSTOMERS
Revenues include sales to Mapco Oil and Gas Company (Mapco) of $60.2
million (27.5%), Western Resources, Inc. (WRI) of $51.8 million (23.6%), and
Natural Gas Clearinghouse of $23.1 million (10.5%) in 1993. In 1992, revenues
included sales to Mapco of $45.7 million (19.4%), WRI of $39.7 million (16.8%)
and Energas Company of $23.7 million (10.0%). In 1991, revenues included sales
to Mapco of $51.9 million (20.9%) and WRI of $27.9 million (11.2%).
(12) CONCENTRATIONS OF CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1993
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, 1993, the Company's direct subsidiary partnerships
were Mesa Operating Limited Partnership (MOLP), Mesa Midcontinent Limited
Partnership (MMLP), and Mesa Holding Limited Partnership (MHLP). At December 31,
1993, MOLP owned 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
81% limited partnership interest in HCLP. At December 31, 1993, MMLP owned an
approximate 19% limited partnership interest in 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 are dedicated to
service the HCLP Secured Notes and are not available to pay creditors of the
Company or its subsidiaries other than HCLP. MOLP and the Company are liable for
the Credit Agreement, the Subordinated Notes and the Discount Notes. Mesa
Capital Corp. (Mesa Capital), a
F-21
56
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
wholly owned financing subsidiary of MOLP, is also an obligor under the
Subordinated Notes and the Discount Notes. Mesa Capital has insignificant assets
and results of operations. Mesa Capital is included with MOLP in the condensed
consolidating financial statements.
In early 1994, the Company effected a series of merger transactions which
resulted in the conversion of each of its subsidiary partnerships, other than
HCLP, to corporate form. Pursuant to these mergers, MOLP was merged into MOC,
and MMLP and MHLP were merged into Mesa Holding Co. (MHC).
As of December 31, 1993, MHC had intercompany payables to MOC of
approximately $123 million. In January 1994, MHC repaid approximately $5 million
of its intercompany payable to MOC. On February 28, 1994, MHC assigned an 18%
limited partnership interest in HCLP (out of its total interest of approximately
19%) to MOC as consideration for $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 percent of interest assigned. MHC also repaid an
additional $24 million of intercompany debt to MOC in cash. As a result of these
transactions, MOC now owns 99% of the limited partnership interest in HCLP, and
substantially all of the Company's intercompany debt has been eliminated.
The following are condensed consolidating financial statements of MESA
Inc., HCLP, MOLP 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, 1993 INC. HCLP MOLP 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 -- 124
Minority interest....................... -- -- -- -- 3 3
Partners'/Stockholders' equity
(deficit)............................ 112 234 (56) 160 (338) 112
----- ----- ----- ------- ------- --------
$ 121 $ 806 $ 785 $ 288 $(467) $1,533
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
F-22
57
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1992 INC. HCLP MOLP SUBS. ELIMIN. CONSOL'D.
- ------------------------------------------ ----- ----- ----- ------- ------- --------
Assets:
Cash and cash investments............... $ -- $ 64 $ 16 $ 77 $ -- $ 157
Other current assets.................... -- 22 31 9 -- 62
----- ----- ----- ------- ------- --------
Total current assets............ -- 86 47 86 -- 219
----- ----- ----- ------- ------- --------
Property, plant and equipment, net...... -- 682 598 -- -- 1,280
Investment in subsidiaries.............. 193 -- 51 191 (435) --
Intercompany receivables................ -- -- 138 -- (138) --
Other noncurrent assets................. -- 91 56 30 -- 177
----- ----- ----- ------- ------- --------
$ 193 $ 859 $ 890 $ 307 $(573) $1,676
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
Liabilities and Equity:
Current liabilities..................... $ -- $ 74 $ 40 $ 2 $ -- $ 116
Long-term debt.......................... -- 542 700 -- -- 1,242
Intercompany payables................... 9 -- -- 142 (151) --
Other noncurrent liabilities............ -- -- 113 13 -- 126
Minority interest....................... -- -- -- -- 8 8
Partners'/Stockholders' equity.......... 184 243 37 150 (430) 184
----- ----- ----- ------- ------- --------
$ 193 $ 859 $ 890 $ 307 $(573) $1,676
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEARS ENDED:
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1993 INC. HCLP MOLP 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) -- --
Securities gains (losses)................ -- -- 6 (2) -- 4
Gains on dispositions of oil and gas
properties............................. -- -- 10 -- -- 10
Equity in loss of subsidiaries........... (102) -- (7) (2) 111 --
Minority interest........................ -- -- -- -- 4 4
Other.................................... -- -- (48) 31 6 (11)
----- ----- ----- ------- ------- --------
Net Income (Loss)........................ $(102) $ (9) $(122) $ 10 $ 121 $ (102)
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
F-23
58
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1992 INC. HCLP MOLP 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) -- --
Securities gains (losses)................ -- -- (3) 11 -- 8
Gains on dispositions of oil and gas
properties............................. -- -- 12 -- -- 12
Equity in loss of subsidiaries........... (87) -- (16) (4) 107 --
Minority interest........................ -- -- -- -- 4 4
Other.................................... (2) -- (18) (2) 13 (9)
----- ----- ----- ------- ------- --------
Net Loss................................. $ (89) $ (20) $ (93) $ (11) $ 124 $ (89)
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1991 INC. HCLP MOLP SUBS. ELIMIN. CONSOL'D.
- ----------------------------------------- ----- ----- ----- ------- ------- --------
Revenues................................. $ -- $ 57 $ 178 $ 15 $ -- $ 250
----- ----- ----- ------- ------- --------
Costs and Expenses:
Operating, exploration and taxes....... -- 13 53 5 -- 71
General and administrative............. -- -- 27 1 -- 28
Depreciation, depletion and
amortization........................ -- 25 81 11 -- 117
----- ----- ----- ------- ------- --------
-- 38 161 17 -- 216
----- ----- ----- ------- ------- --------
Operating Income (Loss).................. -- 19 17 (2) -- 34
----- ----- ----- ------- ------- --------
Interest expense, net of interest
income................................. -- (30) (100) (4) -- (134)
Intercompany interest income (expense)... -- -- 8 (8) -- --
Securities gains (losses)................ -- -- 8 (10) -- (2)
Gains on dispositions of oil and gas
properties............................. -- -- 34 -- -- 34
Equity in loss of subsidiaries........... (73) -- (9) (2) 84 --
Minority interest........................ -- -- -- -- 3 3
Other.................................... (6) -- (23) 15 -- (14)
----- ----- ----- ------- ------- --------
Net Loss................................. $ (79) $ (11) $ (65) $ (11) $ 87 $ (79)
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
F-24
59
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEARS ENDED:
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1993 INC. HCLP MOLP SUBS. ELIMIN. CONSOL'D.
- ----------------------------------------- ----- ----- ----- ------- ------- --------
Cash Flows from Operating Activities..... $ -- $ 21 $ 5 $ 2 $ -- $ 28
----- ----- ----- ------- ------- --------
Cash Flows from Investing Activities:
Capital expenditures................... -- (8) (21) (1) -- (30)
Proceeds from dispositions of oil and
gas properties...................... -- -- 26 -- -- 26
Securities transactions, net........... -- -- 11 (6) -- 5
Other.................................. -- -- 30 46 (35) 41
----- ----- ----- ------- ------- --------
-- (8) 46 39 (35) 42
----- ----- ----- ------- ------- --------
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)
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1992 INC. HCLP MOLP SUBS. ELIMIN. CONSOL'D.
- ----------------------------------------- ----- ----- ----- ------- ------- --------
Cash Flows from Operating Activities..... $ -- $ 16 $ (44) $ -- $ -- $ (28)
----- ----- ----- ------- ------- --------
Cash Flows from Investing Activities:
Capital expenditures................... -- (3) (66) -- -- (69)
Proceeds from dispositions of oil and
gas properties...................... -- -- 11 -- -- 11
Securities transactions, net........... -- -- (8) 32 -- 24
Contributions to subsidiaries.......... -- -- (25) (7) 32 --
Other.................................. -- -- 23 25 (31) 17
----- ----- ----- ------- ------- --------
-- (3) (65) 50 1 (17)
----- ----- ----- ------- ------- --------
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)
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
F-25
60
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER CONSOL. THE
MESA COMPANY AND COMPANY
DECEMBER 31, 1991 INC. HCLP MOLP SUBS. ELIMIN. CONSOL'D.
- ----------------------------------------- ----- ----- ----- ------- ------- --------
Cash Flows from Operating Activities..... $ -- $ 28 $ 8 $ (1) $ -- $ 35
----- ----- ----- ------- ------- --------
Cash Flows from Investing Activities:
Capital expenditures................... -- (2) (29) (1) -- (32)
Proceeds from dispositions of oil and
gas properties...................... -- -- 313 115 -- 428
Securities transactions, net........... -- -- 6 26 -- 32
Contributions to subsidiaries.......... -- -- (28) -- 28 --
Other.................................. -- -- (17) (13) 1 (29)
----- ----- ----- ------- ------- --------
-- (2) 245 127 29 399
----- ----- ----- ------- ------- --------
Cash Flows from Financing Activities:
Long-term borrowings................... -- 617 100 -- -- 717
Repayments of long-term debt........... -- (562) (246) (120) -- (928)
Contributions from equity holders...... -- 28 -- -- (28) --
Other.................................. -- (64) (29) (5) (1) (99)
----- ----- ----- ------- ------- --------
-- 19 (175) (125) (29) (310)
----- ----- ----- ------- ------- --------
Net Increase in Cash and Cash
Investments............................ $ -- $ 45 $ 78 $ 1 $ -- $ 124
----- ----- ----- ------- ------- --------
----- ----- ----- ------- ------- --------
NOTES TO CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
(a) These condensed consolidating financial statements should be read in
conjunction with the consolidated financial statements and notes thereto of
the Company of which this note is an integral part.
(b) As of December 31, 1993, MESA Inc. owned a 97.38% limited partnership
interest in each of MOLP, MMLP and MHLP. The General Partner owned a 2.62%
general partner interest in each of these subsidiary partnerships. These
condensed consolidating financial statements present MESA Inc.'s investment
in its subsidiaries and MOLP's and MMLP'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) In connection with the formation of HCLP, MOLP and MMLP contributed
producing natural gas properties in the Hugoton field and long-term debt to
HCLP in return for limited partnership interests. These transactions did
not require cash and are not reflected in the statements of cash flows of
HCLP, MOLP or MMLP. Non-cash contributions by MOLP and MMLP from inception
(June 12, 1991) to December 31, 1993 are summarized below (in thousands):
MOLP MMLP
--------- --------
Oil and gas properties........................................ $ 447,037 $288,819
Long-term debt................................................ (451,283) (99,206)
Other assets, net of liabilities.............................. 26,822 1,365
General Partner............................................... (114) (964)
--------- --------
$ 22,462 $190,014
--------- --------
--------- --------
(d) The consolidation and elimination entries (i) eliminate the equity method
investment in subsidiaries and equity in loss of subsidiaries, (ii)
eliminate the intercompany payables and receivables, (iii) eliminate other
transactions between subsidiaries including contributions and distributions
and (iv) establish the
F-26
61
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
General Partner's minority interest in the consolidated results of
operations and financial position of the Company.
(e) MOLP was merged into MOC and MMLP and MHLP were merged into MHC in a series
of merger transactions effected in early 1994. In conjunction with these
transactions, the General Partner converted all of his remaining general
partner interests in the Company's subsidiaries into common stock of the
Company, thereby eliminating the minority interest. On February 28, 1994,
MHC repaid substantially all of its intercompany debt to MOC.
F-27
62
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
OIL AND GAS RESERVES AND COST INFORMATION (UNAUDITED)
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 DeGolyer and MacNaughton, independent petroleum engineering
consultants (D&M). These two fields, the Hugoton and West Panhandle fields,
represent over 96% of the Company's net proved equivalent natural gas reserves
at December 31, 1993. The Company's remaining reserves, substantially all of
which are in the Rocky Mountain and Gulf Coast regions, were estimated by
Company engineers. A portion of the Rocky Mountain properties and all of the
Hugoton field deep reserves were sold in 1993. All of the Company's reserves at
December 31, 1993 and 1992 were in the United States. Net proved oil and gas
reserves in the United States and Canada as of December 31, 1991 were estimated
by D&M. The reserves in Canada were less than 2% of the total equivalent
reserves of the Company and are not presented separately in this report. The
Company's interests in Canada were sold in 1992. In accordance with regulations
established by the SEC, 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
6 thousand cubic feet [Mcf] of gas per barrel of liquids) at December 31, 1993
are natural gas. The natural gas prices in effect at December 31, 1993 (having a
weighted average of $2.14 per Mcf) were used in accordance with SEC regulations
but may not be the most appropriate or representative prices to use for
estimating future cash flows from 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 1993 was
$1.79 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 $108
million and $48 million, respectively. At December 31, 1993, the Company's
standardized measure of future net cash flows from proved reserves (Standardized
Measure) and the pre-tax Standardized Measure were less than the net book value
of proved oil and gas properties by approximately $188 million and $106 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.
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. 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, production and development costs; (ii) an
allowance for return on investment; (iii) the value of additional reserves, not
considered proved at present, which may be recovered as a result of further
exploration and development activities; and (iv) other business risks.
F-28
63
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
CAPITALIZED COSTS AND COSTS INCURRED (UNAUDITED)
Capitalized costs relating to oil and gas producing activities at December
31, 1993, 1992 and 1991 and the costs incurred during the years then ended are
set forth below (in thousands):
1993 1992 1991
--------- --------- ---------
Capitalized Costs:
Proved properties...................................... $1,845,483 $1,850,793 $1,785,244
Unproved properties.................................... 754 762 4,980
Accumulated depreciation, depletion and amortization... (670,706) (589,720) (481,218)
---------- --------- ---------
Net............................................ $1,175,531 $1,261,835 $1,309,006
---------- --------- ---------
---------- --------- ---------
Costs Incurred:
Exploration and development:
Proved properties................................... $ 73 $ 64 $ 545
Unproved properties................................. 17 63 4,779
Exploration costs................................... 2,705 15,157 7,924
Development costs................................... 2,381 6,911 12,446
---------- ---------- ---------
Total exploration and development.............. 5,176 22,195 25,694
---------- ---------- ---------
Plant and facilities:
Processing plants................................... 17,501 44,716 5,839
Field compression facilities........................ 4,387 1,509 853
Other............................................... 2,257 3,301 3,599
---------- ---------- ---------
Total plant and facilities..................... 24,145 49,526 10,291
---------- ---------- ---------
Total costs incurred................................... $ 29,321 $ 71,721 $ 35,985
---------- ---------- ---------
---------- ---------- ---------
Depreciation, depletion and amortization............... $ 96,774 $ 110,340 $ 112,860
---------- ---------- ---------
---------- ---------- ---------
F-29
64
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED)
YEARS ENDED DECEMBER 31
--------------------------------
NATURAL GAS (MMCF) 1993 1992 1991
- ------------------------------------------------------------ -------- -------- --------
Proved Reserves:
Beginning of year......................................... 1,276,049 1,367,968 1,920,797
Extensions and discoveries............................. 5,132 37,100 2,643
Purchases of producing properties...................... 166 583 1,267
Revisions of previous estimates........................ 7,284 (24,462) (95,228)
Sales of producing properties.......................... (6,367) (15,613) (352,989)
Production............................................. (79,820) (89,527) (108,522)
--------- --------- ---------
End of year............................................... 1,202,444 1,276,049 1,367,968
--------- --------- ---------
--------- --------- ---------
Proved Developed Reserves:
Beginning of year......................................... 1,223,672 1,338,856 1,853,523
--------- --------- ---------
--------- --------- ---------
End of year............................................... 1,159,453 1,223,672 1,338,856
--------- --------- ---------
--------- --------- ---------
YEARS ENDED DECEMBER 31
NATURAL GAS LIQUIDS, --------------------------------
OIL AND CONDENSATE (MBBLS) 1993 1992 1991
- ------------------------------------------------------------ -------- -------- --------
Proved Reserves:
Beginning of year......................................... 87,392 83,225 101,667
Extensions and discoveries............................. 778 7,591 1,250
Purchases of producing properties...................... -- 9 46
Revisions of previous estimates........................ 3,083 3,028 (4,067)
Sales of producing properties.......................... (3,019) (637) (10,179)
Production............................................. (5,788) (5,824) (5,492)
-------- -------- --------
End of year............................................... 82,446 87,392 83,225
-------- -------- --------
-------- -------- --------
Proved Developed Reserves:
Beginning of year......................................... 82,439 82,406 99,494
-------- -------- --------
-------- -------- --------
End of year............................................... 79,294 82,439 82,406
-------- -------- --------
-------- -------- --------
- ---------------
* Proved natural gas liquids, oil and condensate reserve quantities
include oil and condensate reserves at December 31 of the respective
years as follows: 1993, 3,296 MBbls; 1992, 7,268 MBbls; and 1991, 3,956
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: 1993, 5,198 MMcf of helium and 46,376 MMcf
of CO2; 1992, 5,634 MMcf of helium and 46,457 MMcf of CO2; and 1991,
5,705 MMcf of helium and 44,837 MMcf of CO2.
* The General Partner's minority interest in the proved natural gas and
natural gas liquids, oil and condensate reserves of the Company at
December 31 of the respective years was as follows: 1993, 31,504 MMcf
and 2,160 MBbls, respectively; 1992, 52,828 MMcf and 3,618 MBbls,
respectively; and 1991, 56,634 MMcf and 3,446 MBbls, respectively. The
General Partner converted all of his general partner interests in the
direct subsidiary partnerships of the Company into common stock of the
Company on January 5, 1994, thereby eliminating the minority interest.
F-30
65
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS FROM PROVED RESERVES (UNAUDITED)
DECEMBER 31
--------------------------------------
1993 1992 1991
---------- ---------- ----------
(IN THOUSANDS)
Future cash inflows................................... $3,723,760 $3,802,614 $4,078,322
Future production and development costs:
Operating costs and production taxes................ (1,337,224) (1,271,799) (1,297,999)
Development and abandonment costs................... (80,310) (122,860) (181,350)
Future income taxes................................... (240,017) (302,492) (394,743)
---------- ---------- ----------
Future net cash flows................................. 2,066,209 2,105,463 2,204,230
Discount at 10% per annum........................... (1,079,278) (1,068,282) (1,209,016)
---------- ---------- ----------
Standardized Measure.................................. $ 986,931 $1,037,181 $ 995,214
---------- ---------- ----------
---------- ---------- ----------
Future net cash flows before income taxes............. $2,306,226 $2,407,955 $2,598,973
---------- ---------- ----------
---------- ---------- ----------
Standardized Measure before income taxes.............. $1,068,740 $1,167,694 $1,181,013
---------- ---------- ----------
---------- ---------- ----------
- ---------------
* 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.
* The General Partner's minority interest in the Standardized Measure at
December 31 of the respective years was as follows: 1993, $25.9 million;
1992, $42.9 million; and 1991, $41.2 million. The General Partner
converted all of his general partner interests in the direct subsidiary
partnerships of the Company into common stock of the Company on January
5, 1994, thereby eliminating the minority interest.
F-31
66
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
CHANGES IN STANDARDIZED MEASURE (UNAUDITED)
YEARS ENDED DECEMBER 31
-----------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
Standardized Measure at beginning of year................ $1,037,181 $ 995,214 $1,667,148
---------- ---------- ----------
Revisions of reserves proved in prior years:
Changes in prices and production costs................. 6,178 (77,527) (365,430)
Changes in quantity estimates.......................... 17,616 (3,995) (83,342)
Changes in estimates of future development and
abandonment costs................................... 8,054 (2,468) (30,088)
Net change in income taxes............................. 48,703 55,287 201,170
Accretion of discount.................................. 116,769 118,101 205,412
Other, primarily timing of production.................. (108,371) 12,687 (86,815)
---------- ---------- ----------
Total revisions................................ 88,949 102,085 (159,093)
Extensions, discoveries and other additions, net of
future production and development costs................ 4,456 65,737 12,013
Purchases of proved properties........................... 138 457 1,952
Sales of oil and gas produced, net of production costs... (143,502) (173,552) (182,235)
Sales of producing properties............................ (26,907) (14,473) (367,308)
Previously estimated development and abandonment costs
incurred during the period............................. 26,616 61,713 22,737
---------- ---------- ----------
Net changes in Standardized Measure...................... (50,250) 41,967 (671,934)
---------- ---------- ----------
Standardized Measure at end of year...................... $ 986,931 $1,037,181 $ 995,214
---------- ---------- ----------
---------- ---------- ----------
QUARTERLY RESULTS (UNAUDITED)
QUARTERS ENDED(2)
---------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
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)
-------- -------- ------------ -----------
-------- -------- ------------ -----------
1992
- ----
Revenues....................................... $ 58,919 $ 51,556 $ 48,171 $ 78,466
-------- -------- ------------ -----------
-------- -------- ------------ -----------
Gross profit(1)................................ $ 44,181 $ 36,733 $ 33,608 $ 60,100
-------- -------- ------------ -----------
-------- -------- ------------ -----------
Operating income (loss)........................ $ 9,173 $ (2,479) $ 172 $ 19,355
-------- -------- ------------ -----------
-------- -------- ------------ -----------
Net loss....................................... $(21,973) $(20,622) $(29,128) $ (17,509)
-------- -------- ------------ -----------
-------- -------- ------------ -----------
Net loss per common share...................... $ (.57) $ (.53) $ (.76) $ (.45)
-------- -------- ------------ -----------
-------- -------- ------------ -----------
- ---------------
(1) Gross profit consists of total revenues less lease operating expenses and
production and other taxes.
(2) See Notes 8 and 9 to the Company's consolidated financial statements for
information on items affecting fourth quarter 1993 results.
F-32
67
(A)(2) CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
PAGE IN
FORM 10-K
---------
Schedule V -- Property, Plant and Equipment....................................... S-2
Schedule VI -- Accumulated Depreciation, Depletion and Amortization of
Property, Plant and Equipment................................................... S-3
Schedule X -- Supplementary Income Statement Information.......................... S-4
S-1
68
SCHEDULE V
MESA INC.
PROPERTY, PLANT AND EQUIPMENT
AS OF DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
BALANCE, BALANCE,
BEGINNING ADDITIONS, RETIREMENTS END OF
CLASSIFICATION OF PERIOD AT COST OR SALES PERIOD
------------------------------------ ---------- ---------- ----------- ----------
AS OF DECEMBER 31, 1993:
Oil and Gas Properties, Wells and
Equipment...................... $1,851,555 $ 26,616 $ (31,934) $1,846,237
Office and Other.................. 40,601 1,696 (1,233) 41,064
---------- ---------- ----------- ----------
$1,892,156 $ 28,312 $ (33,167) $1,887,301
---------- ---------- ----------- ----------
---------- ---------- ----------- ----------
AS OF DECEMBER 31, 1992:
Oil and Gas Properties, Wells and
Equipment...................... $1,790,224 $ 61,713 $ (382) $1,851,555
Office and Other.................. 41,861 1,392 (2,652) 40,601
---------- ---------- ----------- ----------
$1,832,085 $ 63,105 $ (3,034) $1,892,156
---------- ---------- ----------- ----------
---------- ---------- ----------- ----------
AS OF DECEMBER 31, 1991:
Oil and Gas Properties, Wells and
Equipment...................... $2,456,699 $ 31,294 $ (697,769) $1,790,224
Office and Other.................. 55,032 2,797 (15,968) 41,861
---------- ---------- ----------- ----------
$2,511,731 $ 34,091 $ (713,737) $1,832,085
---------- ---------- ----------- ----------
---------- ---------- ----------- ----------
S-2
69
SCHEDULE VI
MESA INC.
ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
AS OF DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
BALANCE, BALANCE,
BEGINNING CHARGED RETIREMENTS END OF
CLASSIFICATION OF PERIOD TO INCOME OR SALES PERIOD
- -------------------------------------------------- ---------- --------- ----------- --------
AS OF DECEMBER 31, 1993:
Oil and Gas Properties, Wells and Equipment..... $ 589,720 $ 96,774 $ (15,788) $670,706
Office and Other................................ 22,185 3,325 (761) 24,749
---------- --------- ----------- --------
$ 611,905 $ 100,099 $ (16,549) $695,455
---------- --------- ----------- --------
---------- --------- ----------- --------
AS OF DECEMBER 31, 1992:
Oil and Gas Properties, Wells and Equipment..... $ 481,218 $ 110,340 $ (1,838) $589,720
Office and Other................................ 20,591 3,593 (1,999) 22,185
---------- --------- ----------- --------
$ 501,809 $ 113,933 $ (3,837) $611,905
---------- --------- ----------- --------
---------- --------- ----------- --------
AS OF DECEMBER 31, 1991:
Oil and Gas Properties, Wells and Equipment..... $ 678,205 $ 112,860 $ (309,847) $481,218
Office and Other................................ 23,208 5,971 (8,588) 20,591
---------- --------- ----------- --------
$ 701,413 $ 118,831 $ (318,435) $501,809
---------- --------- ----------- --------
---------- --------- ----------- --------
S-3
70
SCHEDULE X
MESA INC.
SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1993:
Taxes --
Production.................................................................... $ 9,508
Ad Valorem and other.......................................................... 10,824
-------
$20,332
-------
-------
YEAR ENDED DECEMBER 31, 1992:
Taxes --
Production.................................................................... $ 9,380
Ad Valorem and other.......................................................... 9,251
-------
$18,631
-------
-------
YEAR ENDED DECEMBER 31, 1991:
Taxes --
Production.................................................................... $10,785
Ad Valorem and other.......................................................... 8,160
-------
$18,945
-------
-------
S-4