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
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
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):
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.
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:
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.
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
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.
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.
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.
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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.
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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
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
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.
DRILLING ACTIVITIES
The following table shows the results of Mesa's drilling activities for the last five years.
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.
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-
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
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.
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
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
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.


ITEM 2. PROPERTIES
Reference is made to Item 1 of this Form 10-K for a description of Mesa's properties.
ITEM 3.
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
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
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
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.
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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.
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.
ITEM 7.
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.
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.
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.
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* 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
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."
The table below presents Mesa's lease operating costs by area of operation (in thousands):
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):
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.
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.
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.
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):
- ---------------
(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.
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):
- ---------------
(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
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.
ITEM 8.

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 through.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.


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.
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.
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.
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.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Consolidated Financial Statements and Supplementary Data
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).
(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.
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.
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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
MESA INC.
CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA)
(See accompanying notes to consolidated financial statements.)
MESA INC.
CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
(See accompanying notes to consolidated financial statements.)
MESA INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
(See accompanying notes to consolidated financial statements.)
MESA INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (IN THOUSANDS)
(See accompanying notes to consolidated financial statements.)
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
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
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
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):
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.
MESA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) LONG-TERM DEBT
Long-term debt and current maturities are as follows (in thousands):
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.
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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):
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.
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.
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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):
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(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.
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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):
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):
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%,
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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.
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
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.
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:
The outstanding options at December 31, 1993 are detailed as follows:
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
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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):
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(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):
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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
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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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEARS ENDED:
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MESA INC.
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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEARS ENDED:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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):
(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
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.
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.
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):
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED)
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* 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.
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS FROM PROVED RESERVES (UNAUDITED)
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* 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.
MESA INC.
SUPPLEMENTAL FINANCIAL DATA
CHANGES IN STANDARDIZED MEASURE (UNAUDITED)
QUARTERLY RESULTS (UNAUDITED)
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(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.
(A)(2) CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
S-1
SCHEDULE V
MESA INC. PROPERTY, PLANT AND EQUIPMENT AS OF DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
S-2
SCHEDULE VI
MESA INC.
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT AS OF DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
S-3
SCHEDULE X
MESA INC.
SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE THREE YEARS ENDED DECEMBER 31, 1993 (IN THOUSANDS)
S-4