Item 1. Business =================
The Company -----------
MESA Inc. is one of the largest independent oil and gas companies in the United States and considers itself one of the most efficient operators of domestic natural gas producing properties and natural gas processing facilities. Mesa has been publicly traded since 1964 and is primarily in the business of exploration, development, production, and processing of domestic oil and gas.
As of December 31, 1994, Mesa owned approximately 1.8 trillion cubic feet of equivalent proved natural gas reserves ("Tcfe"). Over 70% of Mesa's total equivalent proved reserves are natural gas and the balance are principally natural gas liquids ("NGLs"), which are extracted from natural gas through processing plants. Substantially all of Mesa's proved reserves are proved developed reserves. Quantities stated as equivalent natural gas reserves are based on a factor of 6 thousand cubic feet ("Mcf") of natural gas per barrel ("Bbl") of liquids. See "-- Reserves."
Mesa's principal business strategies include (i) maximizing the value of its existing high-quality, long-life reserves through efficient operating and marketing practices, (ii) processing natural gas to extract value-added products such as natural gas liquids and helium, (iii) conducting selective exploratory and development activities, principally in existing areas of operations, (iv) making acquisitions of producing properties with exploration and development potential in areas where Mesa has operating experience and expertise, (v) generating value and cash flow from investments in natural gas and other energy futures contracts, and (vi) promoting the use of natural gas as a transportation fuel, including the construction and operation of natural gas fueling stations and the development and marketing of natural gas fuel equipment for the transportation market.
MESA Inc. (the "Company") is a holding company and conducts its operations through its subsidiaries. Unless the context otherwise requires, the term "Mesa" means the Company and its subsidiaries taken as a whole and includes the Company's predecessors, Mesa Limited Partnership (the "Partnership") and Mesa Petroleum Co. ("Original Mesa"). Mesa maintains its principal offices at 5205 North O Connor Boulevard, Suite 1400, Irving, Texas 75039-3746, where its telephone number is (214) 444-9001. At December 31, 1994, Mesa employed 399 employees.
Recent Events -------------
Mesa has a highly leveraged capital structure with long-term debt totaling approximately $1.2 billion at December 31, 1994. Cash flows from the production and sale of oil and gas at current prices are not expected to be sufficient during the next few years to service Mesa's obligations, including its long-term debt. Furthermore, Mesa's ability to develop and increase its reserves and production is limited by its leveraged capital structure.
Mesa has considered numerous alternatives for reducing its long-term debt and in late 1994 announced its intention to sell all or a portion of its interests in the Hugoton field of Kansas. During the first quarter of 1995, Mesa began an auction process intended to result in the sale of all its Hugoton interests. At December 31, 1994, Mesa's proved reserves in the Hugoton field totaled 1.2 Tcfe. During 1994, Mesa produced 73 billion cubic feet of equivalent natural gas ("Bcfe") from these properties. Proceeds from a sale would be used to retire long-term debt. Excluding the Hugoton properties, Mesa had proved reserves of 648 Bcfe at December 31, 1994, and produced 55 Bcfe during 1994. There can be no assurance that Mesa will sell its Hugoton properties. If Mesa does not sell these properties, it intends to seek other means to refinance or retire its debt.
Properties ----------
Approximately 96% of Mesa's proved reserves are concentrated in the Hugoton field of southwest Kansas and the West Panhandle field of Texas. The two fields are each part of a reservoir that extends from southwest Kansas, through the Oklahoma panhandle, and into the Texas panhandle. These fields, which produce gas from depths of 3,500 feet or less, are known for their stable long-life production profiles. Mesa's other properties are primarily in the Gulf of Mexico and the Rocky Mountains.
In recent years Mesa's capital budget has been directed principally toward the construction of NGL processing facilities and improvements in its compression and gathering systems. While Mesa expects to direct additional capital expenditures toward exploration in 1995 and in future years, Mesa does not expect that the amounts presently budgeted will be sufficient to replace annual production with new reserve additions.
Over the past several years Mesa has concentrated its efforts on fully developing its existing long-life reserve base and improving its marketing flexibility. In the Hugoton field, these efforts have included infill drilling (i.e., drilling an additional well on each 640-acre spacing unit), installing additional compression and gathering facilities, and the construction of a new natural gas processing plant. In the West Panhandle field, development activities have included well workovers and deepenings, adding compression facilities, and the expansion and upgrading of natural gas processing facilities. In addition, Mesa restructured its contractual arrangements in the West Panhandle field to more clearly define its right to production and to create greater marketing flexibility. Mesa has also negotiated new natural gas sales contracts over the past several years to provide market-based pricing on most of its production. Two significant gas sales contracts will expire in May 1995, thus giving Mesa a substantial amount of uncommitted deliverability available for sale after that date.
Mesa's strategies for replacing production with new reserve additions are based on a multi-step approach, including (i) development and exploratory drilling in the Gulf of Mexico based on evaluation of three- dimensional ("3-D") seismic data, (ii) developing additional reserves in certain deeper portions of the West Panhandle field reservoir, and (iii) acquisitions of producing properties with development and exploration potential, particularly in areas where Mesa presently or historically has operated. The extent to which Mesa pursues these activities is largely dependent on the success and extent of its capital-raising and deleveraging activities.
Mesa has maintained a large geological and geophysical database covering the Midcontinent and other areas where it has historically operated. As capital becomes available and conditions permit, Mesa intends to exploit its database and consider selective acquisitions of producing properties with development and exploration potential in the Texas panhandle, the Hugoton field, and other areas of the Midcontinent and Gulf Coast regions.
Hugoton Field -------------
The Hugoton field in southwest Kansas began producing in 1922, and is the largest producing gas field in the continental United States. Mesa's Hugoton properties, which represent approximately 13% of the proved reserves in the field, are concentrated in the center of the field on over 230,000 net acres, covering approximately 400 square miles. Mesa produces natural gas from over 1,300 wells (950 of which are operated by Mesa) on these properties. Mesa owns substantially all of the gathering and processing facilities which service its production from the Hugoton field and which allow Mesa to control the production stream from the wellbore to the various interconnects it has with major intrastate and interstate pipelines.
Mesa's Hugoton properties are capable of producing over 260 million cubic feet ("MMcf") of wet gas per day (i.e., gas production at the wellhead before processing and before reduction for royalties). Substantially all of Mesa's Hugoton production is processed through its Satanta natural gas processing plant (the "Satanta Plant"). After processing, Mesa has available to market over 175 MMcf of residue (processed) gas and 14 thousand barrels ("MBbls") of NGLs on a peak production day. Production in the Hugoton field is limited by allowables set by state regulators. Mesa attempts to shift as much of its production as is practicable into the heating season, when prices are generally higher. Mesa believes that its ability to aggregate significant volumes of natural gas and NGLs at central delivery points enhances its marketing opportunities and competitive position within the industry.
Mesa's Hugoton properties accounted for approximately 65% of its equivalent proved reserves and 66% of the present value of estimated future net cash flows before income taxes, determined as of December 31, 1994, in accordance with Securities and Exchange Commission (the "Commission") guidelines. The Hugoton properties accounted for approximately 53%, 48%, and 40% of Mesa's oil and gas revenues for the years ended December 31, 1994, 1993, and 1992, respectively. The percentage of revenues from the Hugoton field has been less than the percentage of equivalent proved reserves due primarily to the longer life of the Hugoton properties compared to Mesa's other properties and to lower production levels caused by allowable restrictions. See "Production--Hugoton Field."
West Panhandle Field --------------------
The West Panhandle properties are located in the northern panhandle region of Texas, and are geologically similar to Mesa's Hugoton properties. Natural gas from these properties is produced from 579 wells which Mesa operates on over 185,000 net acres. All of Mesa's West Panhandle production is processed through Mesa's Fain natural gas processing plant (the "Fain Plant").
Mesa's West Panhandle reserves are owned and produced pursuant to contracts with Colorado Interstate Gas Company ("CIG"), originally executed in 1928 by predecessors of both companies. A recent amendment to these contracts, the Production Allocation Agreement ("PAA"), allocates 77% of the production from the West Panhandle field properties to Mesa and 23% to CIG, effective as of January 1, 1991. Under the associated agreements, Mesa operates the wells and production equipment and CIG owns and operates the gathering system by which Mesa's production is transported to the Fain Plant. CIG also performs certain administrative functions. Each party reimburses the other for certain costs and expenses incurred for the joint account.
As of December 31, 1994, Mesa's West Panhandle properties represented approximately 31% of Mesa's equivalent proved reserves, and approximately 33% of the present value of estimated future net cash flows before income taxes, determined in accordance with Commission guidelines. Production from the West Panhandle properties accounted for approximately 36%, 40%, and 39% of Mesa's oil and gas revenues for the years ended December 31, 1994, 1993, and 1992, respectively. Although the West Panhandle properties are long- lived, the percentage of Mesa's revenues represented by West Panhandle production has been greater than the percentage of equivalent proved reserves represented by such properties. This is a result of higher gas prices received under a sales contract for approximately 40% of Mesa's West Panhandle residue gas production, as well as the higher yield of NGLs extracted from West Panhandle natural gas as compared to Hugoton natural gas.
The Fain Plant is capable of processing up to 120 MMcf of natural gas per day. West Panhandle field natural gas contains a high quantity of NGLs. As a result, processing this gas yields relatively greater liquid volumes than recoveries typically realized in other natural gas fields. For example, on a peak day, Mesa can extract over 11 MBbls of NGLs at its Fain Plant from an inlet gas volume of 120 MMcf.
In the last four years Mesa has deepened, redrilled, or reworked 350 wells in the West Panhandle field, adding reserves, and increasing deliverability. Mesa has also identified in excess of 100 drilling locations targeting reserves in deeper portions of the reservoirs not currently reached by existing wells. Mesa anticipates development of the reserves over the next two to three years, in anticipation of its contractual right to increase its share of West Panhandle production in 1997 (see -- "Production--West Panhandle Production").
Gulf Coast ----------
Mesa's Gulf Coast properties are located offshore Texas and Louisiana. Mesa has operated in the Gulf of Mexico since 1970 and has produced approximately 410 Bcfe (net to Mesa's interest). Mesa currently owns interests in 45 blocks in the Gulf of Mexico. As of December 31, 1994, these properties had an estimated 39 Bcfe of remaining proved reserves. In addition, Mesa has over 100,000 miles of two-dimensional ("2-D") seismic data and about 300 square miles of 3-D seismic data in the Gulf of Mexico. Mesa has an office in Lafayette, Louisiana, to oversee production from its Gulf Coast properties. Mesa's working interests in seven of its 45 blocks are subject to a net profits interest owned by the Mesa Offshore Trust.
Over the last four years, Mesa has evaluated a number of its offshore producing properties utilizing well information, 2-D seismic and production data, combined with new 3-D seismic surveys to identify further development and exploration potential. Mesa currently has nine 3-D seismic surveys under analysis. New well locations were identified on nine producing leases in 1994 and four exploratory blocks were acquired as a result of interpreting 3-D seismic data surveys. In 1994 Mesa drilled four successful wells in one producing field based on 3-D seismic data. Mesa intends to continue its evaluation and identification of additional prospects for drilling in 1995, depending on the success of its initial program and other factors. Because it has existing infrastructure and production facilities on these properties, Mesa expects that it will be able to bring its successful wells on-line more quickly and at lower development costs than have been typical for offshore production.
Other -----
Mesa's other producing properties are located in the Rocky Mountain area of the United States.
Mesa's non-oil and gas tangible properties include buildings, leasehold improvements, and office equipment, primarily in Amarillo, Dallas, and Fort Worth, Texas, and certain other assets. Non-oil and gas tangible properties comprise less than 2% of the net book value of Mesa's properties.
Reserves --------
The following table summarizes the estimated proved reserves and estimated future cash flows associated with Mesa's oil and gas properties as of December 31, 1994, estimated in accordance with Commission guidelines by Mesa s engineers (dollar amounts in thousands):
Proved reserves: Natural gas (MMcf)................................... 1,303,187 Natural gas liquids, oil and condensate (MBbls)...... 89,428
Future cash flows: Future cash inflows.................................. $3,513,282 Operating costs...................................... (876,450) Production and ad valorem taxes...................... (315,555) Development and abandonment costs.................... (95,441) Future income taxes.................................. (211,076) ---------- Future net cash flows........................... $2,014,760 ========== Present value of future net cash flows discounted at 10% ("Present Value") after income taxes ............. $ 934,182 ========== Present Value before income taxes......................... $ 988,325 ==========
The following table summarizes estimated proved reserves as of December 31, 1994, by major areas of operation:
Natural Natural Gas Gas NGLs Oil Equivalents --------- -------- ------- ----------- (MMcf) (MBbls) (MBbls) (MMcfe)
Hugoton......................... 950,684 40,108 -- 1,191,332 West Panhandle.................. 296,415 44,218 2,104 574,347 Other........................... 56,088 71 2,927 74,076 --------- ------ ----- --------- Total....................... 1,303,187 84,397 5,031 1,839,755 ========= ====== ===== =========
The proved reserve estimates set forth above were prepared by Mesa's engineers. In previous years the proved reserve estimates reported by Mesa for its Hugoton and West Panhandle properties (approximately 96% of total proved reserves) were prepared by an independent petroleum engineering firm. Mesa's internal estimates of proved reserves for the Hugoton and West Panhandle properties in such years were greater than the estimates prepared by the independent petroleum engineers. In the Hugoton field, the primary difference reflects increased reserves for properties on which Mesa has drilled 381 infill wells since 1987, resulting from Mesa's interpretation of pressure and cumulative production data. In the West Panhandle field, the reserve differences result from the interpretation of cumulative production data on producing wells and the estimates of proved undeveloped reserves. Mesa's proved reserve estimates as of December 31, 1994, for the Hugoton and West Panhandle fields are approximately 241 Bcfe greater than the reserves reported at December 31, 1993, adjusted for 1994 production, for the same properties. Mesa operates the producing wells and the natural gas processing plants on each of these properties and, based on its knowledge of the properties, believes that its proved reserve estimates are more reflective of future production than the estimates prepared by independent petroleum engineers in previous years.
Reserve engineering is not an exact science. Information relating to Mesa's proved oil and gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and gas reserves and of future net revenues necessarily depend upon a number of factors and assumptions, such as historical production performance, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover costs, all of which may in fact vary considerably from actual future results. The accuracy of any reserve estimate is a function of the quality of the available data, of engineering and geological interpretation and of subjective judgment. For these reasons, estimates of the economically recoverable quantities of oil and gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom prepared by different engineers or by the same engineers at different times may vary materially. Actual production, revenues, and expenditures with respect to Mesa's reserves will likely vary from estimates, and such variances may be material.
During 1994, Mesa filed Form EIA-23, which included reserve estimates as of December 31, 1993, with the Energy Information Administration of the Department of Energy (the "EIA"). Such reserve estimates did not vary from those estimates contained herein by more than five percent as described above.
The estimated quantities of proved oil and gas reserves, the standardized measure of future net cash flows from proved oil and gas reserves (the "Standardized Measure") and the changes in the Standardized Measure for each of the three years in the period ended December 31, 1994, are included under "Supplemental Financial Data" in the consolidated financial statements of the Company located elsewhere in this Form 10-K.
Production ----------
Mesa's Hugoton and West Panhandle fields are both mature reservoirs that are substantially developed and have long-life production profiles. Assuming the continuation of existing economic and operating conditions (including the Hugoton field regulatory changes discussed below), Mesa expects to be able to maintain annual productive capacity from its existing properties in these two fields through the end of this decade that approximates such properties' 1994 equivalent production.
Natural gas production is subject to numerous state and federal laws and Federal Energy Regulation Commission (the "FERC") regulations.
Certain factors affecting production in Mesa's various fields are discussed in greater detail below.
Hugoton Field -------------
The Kansas Corporation Commission (the "KCC") is the state regulatory agency that regulates oil and gas production in Kansas. One of the KCC's most important responsibilities is the determination of market demand (allowables) for the field and the allocation of allowables among the more than 6,200 wells in the field.
Twice each year, the KCC sets the fieldwide allowable production at a level estimated to be necessary to meet the Hugoton market demand for the summer and winter production periods. The fieldwide allowable is then allocated among individual wells determined by a series of calculations that are principally based on each well's pressure, deliverability, and acreage. The allowables assigned to individual wells are affected by the relative production, testing, and drilling practices of all producers in the field, as well as the relative pressure and deliverability performance of each well.
Generally, fieldwide allowables are influenced by overall gas market supply and demand in the United States as well as specific nominations for gas from the parties who produce or purchase gas from the field. Since 1987, fieldwide allowables have increased in each year except 1991. The total field allowable in 1994 was 613 Bcf of wellhead gas.
On February 2, 1994, the KCC issued an order, effective as of April 1, 1994, establishing new field rules which modified the formulas used to allocate allowables among wells in the field. The standard pressure used in each well's calculated deliverability was reduced by 35%, greatly benefitting Mesa's high deliverability wells. Also, the new rules assign a 30% greater allowable to 640-acre units with infill wells than to similar units without infill wells. Substantially all of Mesa's Hugoton infill wells have been drilled, which resulted in an increase to Mesa in assignable allowables for 1994. The new field rules also allow Hugoton producers to make up pre-1994 cancelled underages over a 10-year period. Mesa's share of the allowables from the field increased from approximately 10% in 1993 to 14% in 1994 as a result of the new field rules.
Mesa's net Hugoton field production increased to approximately 73 Bcfe in 1994 compared with 57 Bcfe in 1993 as a result of the new Hugoton field rules, the increased yield of NGLs from the Satanta Plant, and certain other factors. Assuming continuation of existing economic, operating, and regulatory conditions, Mesa expects its existing Hugoton properties to be able to produce an average of 74 Bcfe per year through the year 2000.
Excluding reserve acquisitions, Mesa has invested over $125 million in capital expenditures in its Hugoton properties since 1986 to drill 381 infill wells, to construct the Satanta Plant and related facilities, and to upgrade gathering and compression facilities, production equipment and pipeline interconnects in order to increase production capacity and marketing flexibility. Mesa expects future capital expenditures to be substantially lower.
West Panhandle Field --------------------
Mesa's production of wet gas from the West Panhandle field is governed by the PAA and other contracts with CIG. Mesa's entitled wet gas production was 35 Bcf for 1993 and 32 Bcf for 1994. Mesa will be entitled to 32 Bcf of wet production per year for 1995 and 1996. After deductions for processing and royalties, Mesa expects that 32 Bcf of wet gas production will result in annual net production volumes of approximately 21 Bcf of residue gas and 3 million barrels ("MMBbls") of NGLs. Beginning in 1997 Mesa will have the right to market and sell as much gas as it can produce, subject to specific CIG seasonal and daily entitlements as provided for under the contracts. Assuming continuation of existing economic and operating conditions, Mesa expects its existing West Panhandle properties will be able to produce an average of 37 Bcf of wet gas per year for sale in the years 1997 through 2000.
The PAA contains provisions which allocate 77% of ultimate production after January 1, 1991, to Mesa and 23% to CIG. As a result, Mesa records 77% of total annual West Panhandle production as sales, regardless of whether Mesa's actual deliveries are greater or less than the 77% share. The difference between Mesa's 77% entitlement and the amount of production actually sold by Mesa to its customers is recorded monthly as production revenue with corresponding accruals for operating costs, production taxes, depreciation, depletion and amortization, and gas balancing receivables. At December 31, 1994, Mesa had produced less than its 77% entitlement since January 1, 1991, and a long-term gas balancing receivable of $39.9 million was recorded in Mesa's balance sheet in other assets. In future years, as Mesa sells to customers more than its 77% entitlement share of field production, this receivable will be realized.
Natural Gas Processing ----------------------
Mesa processes its natural gas production for the extraction of NGLs and helium to enhance the market value of the gas stream. Mesa has recently made substantial capital investments to enhance its natural gas processing and helium extraction capabilities in the Hugoton and West Panhandle fields. Mesa owns and operates its own processing facilities so that it can (i) capture the processing margin for itself, as third-party processing agreements generally available in the industry result in retention of a significant portion of the processing margin by the contract processor, and (ii) control the quality of the residue gas stream, permitting it to market gas directly to pipelines for delivery to end users. In addition, Mesa believes that the ability to control its production stream from the wellhead through its processing facilities to disposition at central delivery points enhances its marketing opportunities and competitive position in the industry.
Through its natural gas processing plants, Mesa extracts raw NGLs and crude helium from the wet natural gas stream. The NGLs are then transported and fractionated into their constituent hydrocarbons such as ethane, propane, normal butane, isobutane, and natural gasolines. The NGLs and helium are then sold pursuant to contracts providing for market-based prices.
Satanta Natural Gas Processing Plant ------------------------------------
Historically, approximately one-half of Mesa's Hugoton production was processed through Mesa's Ulysses natural gas processing plant for the extraction of NGLs. In the third quarter of 1993 Mesa started processing at the Satanta Plant. The Satanta Plant has the capacity to process 250 MMcf of natural gas per day, and enables Mesa to extract natural gas liquids from substantially all of the gas produced from its Hugoton field properties. The Satanta Plant also has the ability to extract helium from the gas stream. In 1994 the Satanta Plant averaged 143 MMcf per day of inlet gas (net to Mesa's interests) and produced a daily average of 9.4 MBbls of NGLs, 473 Mcf of crude helium, and 107 MMcf of residue natural gas.
Fain Natural Gas Processing Plant ---------------------------------
Wet gas produced from the West Panhandle field contains a high quantity of NGLs, yielding relatively greater NGL volumes than realized from most other natural gas fields. The Fain Plant has inlet capacity of 120 MMcf per day. In 1994 the Fain Plant averaged 75 MMcf per day of inlet gas (net to Mesa's interests), and produced a daily average of 8.4 MBbls of NGLs, 102 Mcf of crude helium, and 65 MMcf of residue natural gas.
Sales and Marketing -------------------
Following the processing of wet gas, Mesa sells the dry (or residue) natural gas, helium, condensate, and NGLs pursuant to various short- and long-term sales contracts. Substantially all of Mesa's gas and NGL sales are made at market prices, with the exception of certain West Panhandle field volumes. Due to a number of market forces, including the seasonal demand for natural gas, both sales volumes from Mesa's properties and sales prices received vary on a seasonal basis. Sales volumes and price realizations for natural gas are generally higher during the first and fourth quarters of each calendar year.
The following tables show Mesa's natural gas, natural gas liquids, and oil and condensate production and prices by area for the past three years:
Production 1994 1993 1992 ---------- ------ ------ ------ Natural gas (MMcf) Hugoton.................................... 51,986 47,476 48,592 West Panhandle............................. 22,983 23,786 26,380 Other...................................... 7,370 8,558 14,555 ------ ------ ------ Total................................. 82,339 79,820 89,527 ====== ====== ======
Natural gas liquids (MBbls) Hugoton.................................... 3,430 1,481 898 West Panhandle............................. 3,423 3,480 3,794 Other...................................... 58 89 148 ------ ------ ------ Total................................. 6,911 5,050 4,840 ====== ====== ======
Oil and condensate (MBbls) Hugoton.................................... -- 104 249 West Panhandle............................. 164 153 -- Other...................................... 382 481 735 ------ ------ ------ Total................................. 546 738 984 ====== ====== ======
Prices ------ Weighted average sales price: Natural gas (per Mcf) Hugoton............................... $ 1.57 $ 1.78 $ 1.56 West Panhandle........................ 1.80 1.72 1.80 Other................................. 1.81 2.04 1.74 ------ ------ ------ Average.......................... $ 1.67 $ 1.79 $ 1.72 ====== ====== ====== Natural gas liquids (per Bbl) Hugoton............................... $10.03 $12.35 $13.98 West Panhandle........................ 11.06 12.04 11.92 Other................................. 11.40 12.55 12.50 ------ ------ ------ Average.......................... $10.55 $12.14 $12.32 ====== ====== ====== Oil and condensate (per Bbl) Hugoton............................... $ -- $18.21 $18.80 West Panhandle........................ 13.38 15.04 -- Other................................. 15.09 16.79 18.88 ------ ------ ------ Average.......................... $14.58 $16.63 $18.86 ====== ====== ======
The table below presents Mesa's total production costs (lease operating expenses and production and other taxes) by area of operation for each of the years ended December 31 (in thousands, except per thousand cubic feet of natural gas equivalent ["Mcfe"] data):
1994 1993 1992 ---------------- ---------------- ---------------- Total Per Mcfe Total Per Mcfe Total Per Mcfe ------- -------- ------- -------- ------- --------
Hugoton......... $30,054 $ .41 $25,406 $ .45 $22,353 $ .40 West Panhandle.. 31,446 .71 34,478 .76 27,794 .57 Other........... 12,461 1.24 12,267 1.02 12,343 .62 ------- ------- ------- Total/ Average.. $73,961 $ .58 $72,151 $ .63 $62,490 $ .50 ======= ======= =======
Hugoton Sales Contracts -----------------------
A substantial portion of Mesa's Hugoton field production is subject to two gas purchase contracts with Western Resources, Inc. ("WRI"). The WRI contracts expire in May 1995. Effective February 1, 1994, WRI assigned a portion of one contract to Missouri Gas Energy ("MGE"). Under the contracts, WRI and MGE had the right to purchase 37.5 Bcf in 1994 and may purchase an aggregate of 19.9 Bcf during the first five months of 1995. These volumes are subject to minimum seasonal purchase volumes. WRI and MGE pay market prices for volumes purchased as determined monthly based on a price index published by a third party. In 1994 WRI and MGE together purchased 29.1 Bcf of gas from Mesa at an average price of $1.56 per Mcf under these contracts.
Mesa's efforts to maximize its annual production and to direct natural gas sales to the most favorable markets available are consistent with regulatory and contractual requirements. Any Hugoton production not taken under the applicable contracts by WRI and MGE is released for sale to other parties. Mesa markets such production to marketers, pipelines, local distribution companies, and end-users, generally under short-term contracts at market prices.
West Panhandle Gas Sales Contracts ----------------------------------
Most of Mesa's West Panhandle field residue natural gas is sold pursuant to gas purchase contracts with two major customers in the Texas panhandle area.
Approximately 10 Bcf per year of residue natural gas is sold to a gas utility that serves residential, commercial, and industrial customers in Amarillo, Texas, under the terms of a long-term agreement dated January 2, 1993, which supercedes the original contract that was in effect since 1949. The agreement contains a pricing formula for the five-year period from 1993 through 1997. Beginning in 1993, 70% of the volumes sold to the gas utility under the contract were sold at fixed prices of $2.71 in 1993 and $2.85 in 1994. Such prices escalate at 5% per annum in 1995 and then at 7-1/2% per annum in 1996 and 1997. The other 30% of volumes sold under this contract are priced at a regional market index based on spot prices plus $.10 per Mcf. Prices for 1998 and beyond will be determined by renegotiation. Mesa provides the gas utility significant volume flexibility, including a right to the residue gas volumes required to meet the seasonal needs of its residential and commercial customers. The average price received by Mesa for natural gas sales to the gas utility in 1994 was $2.55 per Mcf.
Mesa's principal industrial customer for West Panhandle field gas is an intrastate pipeline company which serves various markets, including an electric-power generation facility near Amarillo. In 1990 Mesa entered into a five-year contract with the pipeline company to supply gas to the power generation facility. The contract provides for minimum annual volumes of 8.4 Bcf in 1994 and 8.4 Bcf in 1995 at fixed prices per million British Thermal Units ("MMBtu") of $1.71 and $1.79 for the respective years. Mesa has periodically made sales to the pipeline company in excess of the minimum volumes specified in the contract at market prices. In 1994 Mesa sold approximately 10.5 Bcf of residue natural gas to the pipeline for an average price of $1.56 per Mcf.
Other industrial customers purchase natural gas from Mesa under short- to intermediate-term contracts. These sales totaled approximately 3.6 Bcf in 1994. Mesa intends to continue to seek new customers for additional sales of West Panhandle field natural gas production.
Prior to 1993, Mesa's right to market natural gas produced from the West Panhandle field was limited to Amarillo, Texas, and its environs. An amendment to the PAA in 1993 removed this restriction, and Mesa now has the right to market its production elsewhere. Through 1995, a substantial portion of Mesa's West Panhandle field production is under contract to customers in Amarillo as described above. Mesa expects to continue to focus its marketing efforts in the Amarillo area. Mesa believes that the right to market production outside the Amarillo area will ensure that Mesa receives competitive terms for its West Panhandle field production.
NGL and Helium Sales --------------------
NGL production from both the Satanta and Fain Plants are sold by component pursuant to a seven-year contractual arrangement with Mapco Oil and Gas Company, a major transporter and marketer of NGLs, at the greater of Midcontinent or Gulf Coast prices at the time of sale. Helium is sold to an industrial gas company under a fifteen-year agreement that provides for annual price adjustments.
Major Customers ---------------
See Note 11 to the consolidated financial statements of the Company located elsewhere in this Form 10-K for information on sales to major customers.
Drilling Activities -------------------
The following table shows the results of Mesa's drilling activities for the last five years:
1994 1993 1992 1991 1990 ----------- ----------- ----------- ----------- ----------- Gross Net Gross Net Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- Exploratory Wells: Productive.... -- -- -- -- 5 4.1 6 4.7 -- -- Dry........... -- -- 1 1.0 1 .4 1 .2 5 3.1 Development Wells: Productive.... 31 24.5 43 29.1 22 16.5 26 10.9 146 120.8 Dry........... 1 .8 -- -- -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- Total....... 32 25.3 44 30.1 28 21.0 33 15.8 151 123.9 ===== ===== ===== ===== ===== ===== ===== ===== ===== =====
At December 31, 1994, the Company was participating in the drilling of one gross (.77 net) well in the West Panhandle field.
Producing Acreage and Wells, Undeveloped Acreage ------------------------------------------------
Mesa's ownership of oil and gas acreage held by production, producing wells and undeveloped oil and gas acreage as of December 31, 1994, is set forth in the table below.
Producing Producing Undeveloped Acreage Wells Acreage ---------------- -------------- -------------- Gross Net Gross Net Gross Net ------- ------- ----- ------- ------ ------ Onshore U.S.: Kansas................ 258,979 231,360 1,390 991.4 5,280 5,280 Texas................. 241,354 185,655 598 448.5 2,030 1,574 Wyoming............... 11,715 4,603 2 -- 16,503 10,941 North Dakota.......... 4,661 3,467 23 6.0 3,932 2,572 Other................. 2,826 2,139 13 1.2 24,007 14,217 ------- ------- ----- ------- ------ ------ Total Onshore.... 519,535 427,224 2,026 1,447.1 51,752 34,584 ------- ------- ----- ------- ------ ------
Offshore U.S.: Louisiana............. 87,025 45,710 189 41.6 16,831 15,894 Texas................. 73,808 16,544 58 9.8 17,280 17,280 ------- ------- ----- ------- ------ ------ Total Offshore... 160,833 62,254 247 51.4 34,111 33,174 ------- ------- ----- ------- ------ ------ Grand Total................ 680,368 489,478 2,273 1,498.5 85,863 67,758 ======= ======= ===== ======= ====== ======
Mesa has interests in 2,085 gross (1,471.2 net) producing gas wells and 188 gross (27.3 net) producing oil wells in the United States. Mesa also owns approximately 86,100 net acres of producing minerals and 40,652 net acres of nonproducing minerals in the United States.
The NGV Business ----------------
Mesa believes that the transportation market offers opportunities to realize premium prices for natural gas. In recent years Mesa has engaged in developing its natural gas vehicle ("NGV") business and is a leader in the development of natural gas conversion equipment for automobiles and natural gas fueling stations for fleet vehicles. Mesa believes that the NGV market will develop and expand in the next decade, particularly in light of (i) the National Energy Policy Act of 1992, (ii) the amendments to the 1990 Federal Clean Air Act which require the use of alternative fuels by certain fleets, (iii) the requirements of numerous state and municipal environmental regulations, (iv) generally increased awareness of the adverse environmental and pollution effects of crude oil-based motor fuels, and (v) the development of more efficient equipment to convert gasoline- and diesel- burning vehicles to operate on natural gas. Mesa's present strategies are (i) the development, manufacture, and sale of engine-specific conversion equipment which meets the most stringent emissions standards, and (ii) pursuing conversion equipment sales, fleet conversions, fueling station installations, and the administration of fueling and conversion programs.
Conversion Equipment --------------------
Since 1991 Mesa has invested approximately $17 million in its indirect, wholly owned subsidiary, MESA Environmental Ventures Co. ("Mesa Environmental"), to fund its acquisitions, capital investments, and overhead. Mesa Environmental has developed a natural gas vehicle conversion system, the Gas Engine Management ("GEM") system, which Mesa believes is the cleanest and most advanced conversion product in the industry. Mesa Environmental is currently marketing its GEM system to fleet operators in the United States. Mesa Environmental is a start-up business in a newly developing industry, and the ultimate capital investment required to ensure its viability is uncertain. In addition, Mesa cannot predict when, or if, Mesa Environmental's operations will begin to earn a profit.
Fueling Business ----------------
In 1994 Mesa entered into a fueling arrangement with a large operator of airport shared-ride fleet vehicles. Mesa agreed to finance the acquisition by the fleet operator of certain natural gas-fueled vans and conversion equipment, and the fleet operator agreed to purchase natural gas at Mesa's fueling facilities. This financing/fueling arrangement is designed to be a model for similar agreements with fleet operators at select other locations in the U.S. In December 1994 Mesa opened a natural gas fueling station near the Phoenix, Arizona, airport and expects to open two stations in Los Angeles during 1995.
Organizational Structure ------------------------
In order to simplify its organizational and capital structure, Mesa effected a series of mergers in early 1994 which resulted in the conversion of each of Mesa's subsidiary partnerships, other than Hugoton Capital Limited Partnership ("HCLP"), into corporate form. Pursuant to these mergers, Mesa Operating Limited Partnership was merged into Mesa Operating Co. ("MOC"), Mesa Midcontinent Limited Partnership, and Mesa Holding Limited Partnership were merged into Mesa Holding Co. ("MHC"), and Mesa Environmental Ventures Limited Partnership was merged into Mesa Environmental. Pursuant to certain of these mergers, all of the general partner interests in Mesa's subsidiary partnerships held directly or indirectly by Boone Pickens were converted into approximately 1.7 million shares of common stock of Mesa, as contemplated by a conversion agreement dated December 31, 1991, between Mesa and Mr. Pickens. As a result, all of Mesa's subsidiaries are now wholly owned by Mesa. Unless the context otherwise requires, the terms "MOC," "MHC," and "Mesa Environmental" include their respective predecessors. Mesa's significant subsidiaries are described below.
MOC ---
MOC owns Mesa's properties in the West Panhandle field of Texas and Mesa's interests in the Gulf of Mexico and the Rocky Mountain area. MOC also owns an approximate 99% limited partnership interest in HCLP. In addition, MOC owns helium attributable to its West Panhandle field properties, as well as helium and certain NGLs produced from HCLP's Hugoton field properties.
MOC is Mesa's principal operating subsidiary. Most of Mesa's employees are employed by MOC, and MOC is generally responsible for all of Mesa's operations, administration, and marketing, including the operations of HCLP.
HCLP ----
Substantially all of Mesa's Hugoton field property interests (including gathering systems, compression and gas processing facilities, but excluding certain NGL and helium reserves) are owned by HCLP. HCLP also owns the Satanta Plant, which was constructed by MOC. MOC operates the plant under a long-term lease.
HCLP was formed in 1991 to own substantially all of Mesa's Hugoton field properties and to issue certain long-term notes secured by those properties (the "HCLP Secured Notes"). The indenture and mortgage for the HCLP Secured Notes contain various covenants which, among other things, limit HCLP's ability to sell or acquire oil and gas property interests, incur additional indebtedness, make unscheduled capital expenditures, make distributions of property or funds subject to the mortgage, enter into certain types of long-term contracts, or forward sales of production. The agreements also require HCLP to remain in partnership form; its general partner, Hugoton Management Co. ("HMC"), is a wholly owned subsidiary of the Company. The assets of HCLP, which is required to maintain separate existence from Mesa, are generally not available to pay creditors of Mesa or its subsidiaries other than HCLP. The HCLP agreements require proceeds from production to be applied towards payment of HCLP's operating, administrative, and capital costs, and to service HCLP's debt. To the extent cash flows exceed these requirements, such "excess cash" is generally available for distribution to Mesa subsidiaries that own an equity interest in HCLP.
MHC ---
MHC principally conducts various investment activities. At December 31, 1994, MHC held approximately $71 million of cash and securities, an approximate 1% limited partnership interest in HCLP, and all of the equity of Mesa Environmental.
History of Mesa ---------------
In 1964 Original Mesa was formed as a public corporation engaged in the business of exploring for and producing oil and natural gas. Original Mesa's reserves and revenues grew significantly throughout the 1960s, 1970s, and early 1980s as a result of successful exploration, development and acquisitions. Original Mesa conducted operations in the United States, and at various times, Canada, the North Sea, and Australia. Original Mesa was reorganized as the Partnership, a publicly traded limited partnership, in 1985 and the Partnership was converted to corporate form as MESA Inc. in 1991.
Mesa's two most recent significant acquisitions, Pioneer Corporation in 1986 (which included Mesa's West Panhandle field) and Tenneco Inc.'s midcontinent division in 1988 (which included approximately one-fourth of Mesa's current Hugoton holdings), increased reserves from 1.4 Tcfe at year- end 1985 to over 2.8 Tcfe at year-end 1988. Mesa incurred significant debt to make the reserve acquisitions. Mesa also made cash distributions to Partnership unitholders of over $1.1 billion from 1986 through 1990. The increased debt associated with the acquisitions, the distributions, and declining gas prices through the late 1980s and early 1990s, significantly impaired Mesa's financial strength and flexibility. As a result, in 1991 Mesa began to sell assets and refinance and restructure its debt. From 1989 through 1993, Mesa sold nearly 600 Bcfe of proved producing reserves for an aggregate of over $633 million. Mesa used the proceeds principally to reduce debt. Mesa refinanced $550 million of bank debt in 1991 with the formation of HCLP and the issuance of the HCLP Secured Notes. In 1993 Mesa restructured substantially all of its $600 million of outstanding subordinated debt in a debt exchange transaction, which had the effect of deferring over $150 million of cash interest requirements until after 1995. In the second quarter of 1994 Mesa completed a public offering of approximately 16.3 million shares of common stock at a public offering price of $6.00 per share (the "Equity Offering"). The Equity Offering resulted in net proceeds to Mesa of approximately $93 million which were used to repay debt.
Mesa is currently pursuing a sale of its interests in the Hugoton field and intends to use the proceeds to retire debt. See "Recent Events."
Competition -----------
The oil and gas business is highly competitive in the search for, acquisition of, and sale of, oil and gas. Mesa's competitors in these endeavors include the major oil and gas companies, independent oil and gas concerns, and individual producers and operators, as well as major pipeline companies, many of which have financial resources greatly in excess of those of Mesa. Mesa believes that its competitive position is affected by, among other things, price, contract terms, and quality of service.
Mesa is one of the largest owners of natural gas reserves in the United States. Mesa's major gas sales contracts (see "-- Sales and Marketing") allow production not sold to the contract purchaser to be sold to other purchasers in the spot market. Production from Mesa's properties has access to a substantial portion of the major metropolitan markets in the United States through numerous pipelines and other purchasers. Mesa is not dependent upon any single purchaser or small group of purchasers.
Mesa believes that its competitive position is enhanced by its substantial long-life reserve holdings and related deliverability, its flexibility to sell such reserves in a diverse number of markets, and its ability to produce its reserves at a low cost.
Operating Hazards and Uninsured Risks -------------------------------------
Mesa's oil and gas activities are subject to all of the risks normally incident to exploration for and production of oil and gas, including blowouts, cratering, and fires, each of which could result in damage to life and property. Offshore operations are subject to a variety of operating risks, such as hurricanes and other adverse weather conditions, and lack of access to existing pipelines or other means of transporting production. Furthermore, offshore oil and gas operations are subject to extensive governmental regulations, including certain regulations that may, in certain circumstances, impose absolute liability for pollution damages, and to interruption or termination by governmental authorities based on environmental or other considerations. In accordance with customary industry practices, Mesa carries insurance against some, but not all, of these risks. Losses and liabilities resulting from such events would reduce revenues and increase costs to Mesa to the extent not covered by insurance.
Regulation and Prices ---------------------
Mesa's operations are affected from time to time in varying degrees by political developments and federal, state, and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by price controls, taxes, conservation, safety, environmental, and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations.
Natural Gas Regulations -----------------------
Historically, interstate pipeline companies generally acted as wholesale merchants by purchasing natural gas from producers and reselling the gas to local distribution companies and large end-users. Commencing in late 1985, the FERC issued a series of orders that have had a major impact on natural gas pipeline operations, services, and rates, and thus have significantly altered the marketing and price of natural gas. The FERC's key rulemaking action, Order 636 ("Order 636"), issued in April 1992, requires each pipeline company, among other things, to "unbundle" its traditional wholesale services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and stand-by sales and gas balancing services), and to adopt a new rate- making methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate makes gas sales as a merchant in the future, it does so in direct competition with all other sellers pursuant to private contracts; however, pipeline companies and their affiliates were not required to remain "merchants" of gas, and several of the interstate pipeline companies have become "transporters only." In subsequent orders, the FERC largely affirmed the major features of Order 636 and denied a stay of the implementation of the new rules pending judicial review. In addition, and following the conclusion of individual restructuring proceedings for each interstate pipeline pursuant to Order 636, the FERC has approved, with modifications, all of the restructuring plans, and has generally accepted rate filings implementing Order 636 on every interstate pipeline as of the end of 1994. Order 636, as well as the FERC orders approving the individual pipeline rate filings implementing Order 636, are the subject of numerous appeals to the United States Courts of Appeals. Mesa cannot predict whether the latest orders will be affirmed on appeal or what the effects will be on its business.
State and Other Regulation --------------------------
All of the jurisdictions in which Mesa owns producing oil and gas properties have statutory provisions regulating the production and sale of crude oil and natural gas. The regulations often require permits for the drilling of wells, but extend also to the spacing of wells, the prevention of waste of oil and gas resources, the rate of production, prevention and clean-up of pollution, and other matters. In Texas, the Railroad Commission regulates the amount of oil and gas produced within the state by assigning to each well or proration unit an allowable rate of production. Certain other jurisdictions, including Kansas, impose similar restrictions. See "-- Production" for a discussion of recent changes to Mesa's allowables in the Hugoton field.
Certain producing states, including Texas, Louisiana, Oklahoma, and Kansas, have in recent years adopted or considered adopting measures that alter the methods previously used to prorate gas production from wells located in these states. For example, the recently modified Texas rules provide for reliance on information filed monthly by well operators, in addition to historical production data for the well during comparable past periods, to arrive at an allowable. This is in contrast to historic reliance on forecasts of upcoming takes filed monthly by purchasers of natural gas in formulating allowables, a procedure which resulted in substantial excess allowables over volumes actually produced. Mesa cannot predict what ultimate effect any of these recently adopted prorationing regulations will have on its production of gas, or whether other states will adopt similar or other gas prorationing procedures.
Mesa owns, directly or indirectly, certain natural gas facilities that it believes meet the traditional tests the FERC has used to establish a company's status as a gatherer not subject to FERC jurisdiction under the Natural Gas Act of 1938 (the "NGA"). Moreover, recent orders of the FERC have been more liberal in their reliance upon or use of the traditional tests, such that in many instances, what was once classified as "transmission" may now be "gathering." Mesa transports its own gas through these facilities. Mesa also has gas that is transported through gathering facilities owned by others, including interstate pipelines. On May 27, 1994, the FERC issued orders in the context of the "spin-off" or "spin-down" of interstate pipeline-owned gathering facilities. A "spin-off" is a FERC- approved sale of such facilities to a non-affiliate. A "spin-down" is the transfer by the interstate pipeline of its gathering facilities to an affiliate. A number of spin-offs and spin-downs have been approved by the FERC and implemented. The FERC held that it retains jurisdiction over gathering provided by interstate pipelines, but that it generally does not have jurisdiction over pipeline gathering affiliates, except in the event of affiliate abuse (such as actions by the affiliate undermining open and nondiscriminatory access to the interstate pipeline). These orders require nondiscriminatory access for all sources of supply, prohibit the tying of pipeline transportation service to any service provided by the pipeline's gathering affiliate, and require the new gathering company to submit a "default" contract if a satisfactory contract cannot be mutually agreed upon with existing customers. Several petitions for rehearing were filed. On November 30, 1994, the FERC issued a series of rehearing orders largely affirming the May 27, 1994, orders. The FERC clarified that "default" contracts are intended to serve only as a transition mechanism to prevent arbitrary termination of gathering service to existing customers. Also, the FERC now requires that an interstate pipeline must not only seek authority under Section 7(b) of the NGA to abandon certificated facilities, but also must file for authority under Section 4 of the NGA to terminate service from both certificated and uncertificated facilities. On December 31, 1994, an appeal was filed with the U.S. Court of Appeals for the D.C. Circuit to overturn three of the FERC's November 30, 1994, orders. Mesa cannot predict what the ultimate effect of the FERC's orders pertaining to gathering will have on its production and marketing, or whether the Appellate Court will affirm the FERC's orders on these matters.
State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering has received greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order 636 continues. For example, Oklahoma enacted a prohibition against discriminatory gathering rates, and certain Texas regulatory officials have expressed interest in evaluating similar rules in Texas.
Federal Royalty Matters -----------------------
By a letter dated May 3, 1993, directed to thousands of producers holding interests in federal leases, the United States Department of the Interior (the "DOI") announced its interpretation of existing federal leases to require the payment of royalties on past natural gas contract settlements which were entered into in the 1980s and 1990s to resolve, among other things, take-or-pay and minimum take claims by producers against pipelines and other buyers. The DOI's letter set forth various theories of liability, all founded on the DOI's interpretation of the term "gross proceeds" as used in federal leases and pertinent federal regulations. In an effort to ascertain the amount of such potential royalties, the DOI sent a letter to producers on June 18, 1993, requiring producers to provide all data on all natural gas contract settlements, regardless of whether gas produced from federal leases was involved in the settlement. Mesa received a copy of this information demand letter. In response to the DOI's action, in July 1993 various industry associations and others filed suit in the United States District Court for the Northern District of West Virginia seeking an injunction to prevent the collection of royalties on natural gas contract settlement amounts under the DOI's theories. The lawsuit has been transferred to the United States District Court in Washington, D.C. While the Washington litigation is pending, on February 13, 1995, the DOI's claim in a bankruptcy proceeding against a producer based upon an interstate pipeline's earlier buy-out of the producer's gas sale contract was rejected by the Federal Bankruptcy Court in Lexington, Kentucky. While the facts of the court's decision do not involve all of the DOI's theories, the court found on those at issue that DOI's theories were without legal merit, and the court's reasoning suggests that the DOI's other claims are similarly deficient. Because the Washington litigation remains pending and the Kentucky decision may be appealed, and because of the complex nature of the calculations necessary to determine potential additional royalty liability under the DOI's theories, it is impossible to predict what, if any, additional or different royalty obligation the DOI may assert or ultimately be entitled to recover, if anything, with respect to any of Mesa's prior natural gas contract settlements.
Environmental Matters ---------------------
Mesa's operations are subject to numerous federal, state, and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment, including the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Federal Superfund Law." Such laws and regulations, among other things, impose absolute liability upon the lessee under a lease for the cost of clean-up of pollution resulting from a lessee's operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Mesa maintains insurance against costs of clean-up operations, but it is not fully insured against all such risks. A serious incident of pollution may, as it has in the past, also result in the DOI requiring lessees under federal leases to suspend or cease operation in the affected area. In addition, the recent trend toward stricter standards in environmental legislation and regulation may continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as "hazardous wastes" which would make the reclassified exploration and production wastes subject to much more stringent handling, disposal, and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on Mesa's operating costs, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on Mesa.
The Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose a variety of regulations on "responsible parties" (which include owners and operators of offshore facilities) related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. In addition, OPA imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. On August 25, 1993, the Minerals Management Service (the "MMS") published an advance notice of its intention to adopt a rule under OPA that would require owners and operators of offshore oil and gas facilities to establish $150 million in financial responsibility. Under the proposed rule, financial responsibility could be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. There is substantial uncertainty as to whether insurance companies or underwriters will be willing to provide coverage under OPA because the statute provides for direct lawsuits against insurers who provide financial responsibility coverage, and most insurers have strongly protested this requirement. The financial tests or other criteria that will be used to judge self-insurance are also uncertain. Mesa cannot predict the final form of the financial responsibility rule that will be adopted by the MMS, but such rule has the potential to result in the imposition of substantial additional annual costs on Mesa or otherwise have material adverse effects on Mesa's operations in the Gulf of Mexico.
In 1993 a number of companies in New Mexico, including Mesa, were named in a preliminary information request from the Environmental Protection Agency (the "EPA") as persons who may be potentially responsible for response costs incurred in connection with the Lee Acres Landfill site. Although Mesa did not directly dispose of any materials at the site, it may have contracted to transport materials from its operations with certain trucking companies also named in the information request. To the extent any materials produced by Mesa may have been transported to the site, Mesa believes that such materials were rainwater and/or water produced from natural gas wells, which Mesa believes are exempt or excluded from the definitions of "hazardous waste" or "hazardous substance" under applicable Federal environmental laws, although the EPA may assert a contrary position. Since submitting its response to the information request in April 1994, Mesa has not received any additional inquiries or information from the EPA concerning the site, including whether Mesa is, in fact, asserted to be a responsible party for the site or what potential liability, if any, Mesa may face in connection with this matter.
Mesa is not involved in any other administrative or judicial proceedings arising under federal, state, or local environmental protection laws and regulations which would have a material adverse effect on Mesa's financial position or results of operations.
Item 2.
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 ==========================
Masterson Lawsuit -----------------
In 1986 Mesa, through MOC, acquired rights in certain properties located in the West Panhandle field of Texas when it acquired the assets of Pioneer Corporation. In particular, Mesa acquired an interest in gas production from an oil and gas lease (the "Gas Lease") dated April 30, 1955, between R. B. Masterson, et al., as lessor, and CIG, as lessee.
In February 1992 the current lessors of the Gas Lease sued CIG in Federal District Court in Amarillo, Texas, claiming that CIG had underpaid royalties due under the Gas Lease. The plaintiffs alleged that the underpayment was the result of CIG's using an improper gas sales price upon which to calculate royalties, and that the proper price should have been determined pursuant to a "favored nations" clause in a July 1, 1967, amendment to the Gas Lease. The complaint did not specify the damages sought and appeared to relate only to royalties for periods after October 1, 1989. The plaintiffs also sought a declaration by the court as to the proper price to be used for calculating future royalties. In August 1992 CIG filed a third party complaint against Mesa for any such royalty underpayments which may be allocable to Mesa's interest in the Gas Lease.
On December 22, 1992, the plaintiffs filed a Second Amended Complaint, including both CIG and Mesa as defendants, again alleging that the "favored nations" clause resulted in underpayments of royalties, but for the first time alleging that the underpayments amounted to approximately $250 million (including interest) and covered the period July 1, 1967, to present. Mesa was subsequently dismissed by the plaintiffs for procedural reasons, but remains in the case as a defendant in CIG's third party complaint.
The plaintiffs later filed court papers alleging royalty underpayments of over $500 million (including interest at 10%) covering the period from July 1, 1967, to the present. In addition, the plaintiffs seek exemplary damages. Management believes that Mesa has several defenses to plaintiffs' claims, including: (i) that the royalties for all periods were properly computed and paid; (ii) that plaintiffs' claims with respect to all periods prior to October 1, 1989, (which account for approximately $400 million of the claims) were explicitly released by a 1988 settlement agreement among plaintiffs, CIG and Mesa and are further barred by the statute of limitations; and (iv) from October 1, 1989, to the present, the "favored nations" provision was suspended because the plaintiffs had agreed to be paid certain other royalty rates in lieu of the "favored nations" rate.
In March 1995 the court ruled (1) that all claims for royalty underpayments for the periods prior to October 1, 1989, were released by the plaintiffs in the 1988 settlement agreement, (2) that plaintiffs are not entitled to exemplary damages, and (3) that the "favored nations" clause in the 1967 Gas Lease Amendment has not been eliminated or suspended by the "in lieu of" provision to the 1988 royalty agreements. The court has also made certain other rulings adverse to the defendants covering certain other defenses. The Company and CIG have filed stipulations with the court whereby the Company would be liable for between 50% and 60%, depending upon the time period covered, of any adverse judgment against CIG for post- February 1988 underpayment of royalties. The court's rulings have eliminated approximately $400 million of the plaintiff's original $500 million of claims but have also reduced a number of CIG's and the Company's defenses.
The trial began March 22, 1995.
Preference Unitholders ----------------------
Mesa and Mr. Pickens are defendants in lawsuits filed in early 1992 related to the conversion of the Partnership into MESA Inc., styled Odmark, et al. v. Mesa Limited Partnership, et al., Gerardo, et al. v. Mesa Limited Partnership, et al., and McBride Trust, et al. v. Mesa Limited Partnership, et al., pending in the U.S. District Court for the Northern District of Texas--Dallas Division. The first two lawsuits were consolidated and certified as a class action and the third is an individual action by or on behalf of former holders of preference units of the Partnership. All three allege substantially the same claims under the federal securities laws and common law. Plaintiffs allege, among other things, that (i) the proxy materials delivered to unitholders in connection with the conversion of the Partnership into MESA Inc. (the "Corporate Conversion") contained material misstatements and omissions, (ii) the general partners of the Partnership breached fiduciary duties to the preference unitholders in structuring the transaction and allocating the common stock of Mesa, and (iii) the Corporate Conversion was implemented in breach of the partnership agreement of the Partnership because the defendant allegedly did not obtain the requisite opinion of independent counsel regarding the tax effects of the transaction. Mesa and the other defendants have denied the allegations and believe they are without merit. Plaintiffs seek a declaration declaring the Corporate Conversion void and rescinding it, an order requiring payment to the former preference unitholders of $164 million in respect of the preferential distribution rights of their units, unspecified compensatory and punitive damages and other relief. Mesa and the other defendants have denied the plaintiffs' allegations.
On August 12, 1994, the court entered an order denying plaintiff's motion for a summary judgment and granted Mesa's motion for a summary judgment. A final judgment was entered dismissing the case. A notice of appeal was filed August 19, 1994, by plaintiffs. Oral arguments in the case have been scheduled before the Fifth Circuit Court of Appeals in May 1995.
Other -----
See "Item 1. Business-Environmental Matters" for a discussion of legal proceedings relating to environmental matters that are pending or known to be contemplated by governmental authorities to which Mesa or a subsidiary is a party.
Mesa is also a defendant in various other lawsuits and legal proceedings and, as the successor entity to the Partnership and Original Mesa, has assumed certain other obligations from those entities. Mesa does not expect the resolution of any of these other matters to have a material adverse effect on its results of operations or financial position.
Item 4.
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:
Common Stock -------------- High Low ------ ------ 1994: First Quarter........................................ $8-1/2 $5-5/8 Second Quarter....................................... 7 5-3/8 Third Quarter........................................ 5-7/8 5-1/8 Fourth Quarter....................................... 5-1/2 3-5/8
1993: First Quarter........................................ $6-1/4 $4 Second Quarter....................................... 7 3-1/2 Third Quarter........................................ 8-1/8 6 Fourth Quarter....................................... 7-7/8 4-7/8
---------- * Mesa's common stock trades on the New York Stock Exchange under the symbol MXP. At December 31, 1994, there were 64,050,009 common shares outstanding.
* Mesa has not paid any dividends with respect to its common stock and does not expect to pay dividends in the future unless and until there is a material and sustained increase in natural gas prices and adequate provision has been made for further reduction of debt. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 4 to the consolidated financial statements of the Company included elsewhere in this Form 10-K for a discussion of restrictions on the payment of dividends.
At March 22, 1994, there were 20,284 record holders of Mesa's common shares.
Item 6.
Item 6. Selected Financial Data ================================
The following table sets forth selected financial information of Mesa as of the dates or for the periods indicated. This table should be read in conjunction with the consolidated financial statements of the Company and related notes thereto included elsewhere in this Form 10-K.
As of or for the Years Ended December 31 ---------------------------------------------------------- 1994 1993 1992 1991 1990 ---------- ---------- ---------- ---------- ---------- (in thousands, except per share data)
Revenues........ $ 228,737 $ 222,204 $ 237,112 $ 249,546 $ 329,597 ========== ========== ========== ========== ========== Operating income $ 28,683 $ 22,012 $ 26,221 $ 34,128 $ 43,389 ========== ========== ========== ========== ========== Net loss........ $ (83,353) $(102,448) $ (89,232) $ (79,163) $ (200,276) ========== ========== ========== ========== ========== Net loss per common share... $ (1.42) $ (2.61) $ (2.31) $ (2.05) $ (5.19) ========== ========== ========== ========== ========== Dividends per share.......... $ -- $ -- $ -- $ -- $ .85 ========== ========== ========== ========== ========== Total assets.... $1,483,959 $1,533,382 $1,676,523 $1,832,816 $2,168,002 ========== ========== ========== ========== ========== Long-term debt, including current maturities..... $1,223,293 $1,241,294 $1,286,155 $1,310,705 $1,521,740 ========== ========== ========== ========== ==========
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ========================================================================
Results of Operations ---------------------
The following table presents a summary of the results of operations of Mesa for the years indicated:
Years Ended December 31 ------------------------------- 1994 1993 1992 --------- --------- --------- (in thousands)
Revenues.............................. $ 228,737 $ 222,204 $ 237,112 Operating and administrative costs.... (107,767) (100,093) (96,958) Depreciation, depletion and amortization........................ (92,287) (100,099) (113,933) --------- --------- --------- Operating income...................... 28,683 22,012 26,221 Interest expense, net of interest income..................... (131,300) (131,298) (129,888) Other................................. 19,264 6,838 14,435 --------- --------- --------- Net loss.............................. $ (83,353) $(102,448) $ (89,232) ========= ========= =========
Revenues --------
The table below presents, for the years indicated, the revenues, production and average prices received from sales of natural gas, natural gas liquids and oil and condensate.
Years Ended December 31 ---------------------------- 1994 1993 1992 -------- -------- -------- Revenues (in thousands): Natural gas......................... $139,580 $141,798 $157,672 Natural gas liquids................. 72,771 61,427 59,669 Oil and condensate.................. 7,877 12,428 18,701 -------- -------- -------- Total.......................... $220,228 $215,653 $236,042 ======== ======== ======== Natural Gas Production (MMcf): Hugoton............................. 51,986 47,476 48,592 West Panhandle...................... 22,983 23,786 26,380 Other............................... 7,370 8,558 14,555 -------- -------- -------- Total.......................... 82,339 79,820 89,527 ======== ======== ======== Natural Gas Liquids Production (MBbls): Hugoton............................. 3,430 1,481 898 West Panhandle...................... 3,423 3,480 3,794 Other............................... 58 89 148 -------- -------- -------- Total.......................... 6,911 5,050 4,840 ======== ======== ======== Oil and Condensate Production (MBbls): Hugoton............................. -- 104 249 West Panhandle...................... 164 153 -- Other............................... 382 481 735 -------- -------- -------- Total.......................... 546 738 984 ======== ======== ======== Average Prices: Natural gas (per Mcf)............... $ 1.67 $ 1.79 $ 1.72 Natural gas liquids (per Bbl)....... $ 10.55 $ 12.14 $ 12.32 Oil and condensate (per Bbl)........ $ 14.58 $ 16.63 $ 18.86
The increase in total revenues from sales of natural gas, natural gas liquids and oil and condensate from 1993 to 1994 is primarily due to increased natural gas and natural gas liquids production in 1994, partially offset by the decrease in prices from 1993 to 1994. Total revenues decreased from 1992 to 1993 primarily due to lower natural gas production in 1993.
Natural gas revenues decreased from 1992 to 1993 and from 1993 to 1994. Total natural gas production increased by 3% from 1993 to 1994 substantially due to higher allowables in the Hugoton field partially offset by slightly lower West Panhandle and Gulf Coast production. Average natural gas prices in 1994 were 7% lower than 1993 average prices due to lower market prices. (See "Natural Gas Prices" below.) Natural gas production in 1993 decreased due primarily to lower West Panhandle and Gulf Coast production.
Natural gas liquids production increased by approximately 43% from 1992 to 1994 as a result of increases in Hugoton field liquids production. In the third quarter of 1993 the Satanta Plant in the Hugoton field was completed. The plant, which is capable of processing up to 250 MMcf of natural gas per day, replaced Mesa s older Ulysses plant which could process up to 160 MMcf per day.
West Panhandle production is governed by the terms of a contract with CIG. (See discussion below under "Production Allocation Agreement.")
Mesa s production from the Hugoton field is affected by the allowables set for the entire field and by the portion of allowables allocated to Mesa s wells. See "Production -- Hugoton Field" in the business section of this Form 10-K.
Natural Gas Prices ------------------
Substantially all of Mesa s natural gas production is sold under short- or long-term sales contracts. Approximately 80% of Mesa s annual natural gas sales, whether or not such sales are governed by a contract, are at market prices. The following table shows Mesa s natural gas production sold under fixed price contracts and production sold at market prices:
Years Ended December 31 -------------------------- 1994 1993 1992 ------ ------ ------ Natural Gas Production (MMcf): Sold under fixed price contracts.......... 13,935 19,467 19,051 Sold at market prices..................... 68,404 60,353 70,476 ------ ------ ------ Total production..................... 82,339 79,820 89,527 ====== ====== ======
Percent sold at market prices............. 83% 76% 79% ====== ====== ======
In addition to its fixed price contracts, Mesa will, when circumstances warrant, hedge the price received for its market-sensitive production through natural gas futures contracts traded on the New York Mercantile Exchange. The following table shows the effects of Mesa s fixed price contracts and hedging activities on its natural gas prices:
Years Ended December 31 -------------------------- 1994 1993 1992 ------ ------ ------ Average Natural Gas Prices (per Mcf): Fixed price contracts..................... $ 2.16 $ 1.94 $ 2.06
Market prices received.................... 1.55 1.75 1.55 Hedge gains (losses)...................... .01 (.01) .08 ------ ------ ------ Total market prices.................. 1.56 1.74 1.63 ------ ------ ------ Total average prices...................... $ 1.67 $ 1.79 $ 1.72 ====== ====== ======
Gains and losses from hedging activities are included in natural gas revenues when the hedged production occurs. Mesa recognized gains from hedging activities of $895,000 in 1994, losses of $324,000 in 1993, and gains of $5.6 million in 1992. Mesa has hedged a significant portion of its market-sensitive production for the first three quarters of 1995. As of February 21, 1995, Mesa had closed its hedge positions which were open as of December 31, 1994, and realized gains of approximately $12 million which will be recognized as natural gas revenues as the hedged production occurs. In 1995 Mesa has entered into additional hedge positions related to 1995 production. The results of such positions may increase or decrease Mesa s natural gas revenues.
Costs and Expenses ------------------
Mesa's aggregate costs and expenses declined marginally from 1993 to 1994. Lease operating expenses increased by 2% as a result of higher operating costs associated with Mesa's Satanta Plant in the Hugoton field and higher Hugoton field production. Lease operating expenses, however, have decreased on a unit of production basis due to increased production. Exploration charges in 1994 are greater than such charges in 1993, reflecting Mesa s increased exploration activities in the Gulf of Mexico. The increased 1994 costs result primarily from the purchase of 3-D seismic data. General and administrative expenses were higher in 1994 than in 1993 primarily due to litigation expenses associated with Mesa's defense of a royalty lawsuit in the West Panhandle field (see Note 9 to the consolidated financial statements of the Company located elsewhere in this Form 10-K). Depreciation, depletion and amortization ("DD&A") expense was lower in 1994 compared to 1993. DD&A expense, which is calculated on a unit-of-production basis, reflects the 1994 reserve increases in the Hugoton and West Panhandle fields and reserve discoveries in the Gulf Coast. (See "Supplemental Financial Data" to the consolidated financial statements of the Company located elsewhere in this Form 10-K.)
Mesa's aggregate costs and expenses declined by approximately 5% from 1992 to 1993 primarily due to decreases in exploration and DD&A expenses partially offset by an increase in lease operating expenses. Lease operating expenses were greater in 1993 than in 1992 due to increased production costs in the West Panhandle field. The increase was primarily a result of increased gathering-related fees paid to CIG as operator of the gathering system in the West Panhandle field. Exploration charges were substantially lower in 1993 than in 1992. The 1992 expense included exploratory dry holes in the Gulf Coast area. DD&A expense was lower in 1993 than in 1992 due primarily to lower production in 1993.
Other Income (Expense) ----------------------
Interest expense in 1994 was not materially different from 1993 and 1992 as average aggregate debt outstanding did not materially change.
Interest income increased from $10.7 million in 1993 to $13.5 million in 1994 as a result of higher average cash balances and higher average interest rates earned on these cash balances in 1994.
Results of operations for the years 1994, 1993, and 1992 include certain items which are either non-recurring or are not directly associated with Mesa's oil and gas producing operations. The following table sets forth the amounts of such items (in thousands):
Years Ended December 31 ------------------------- 1994 1993 1992 ------- ------- ------- Gains from futures and securities investments............................... $ 6,698 $ 3,954 $ 7,808 Gains from collections from Bicoastal Corporation............................... 16,577 18,450 -- Gains on dispositions of oil and gas properties........................ -- 9,600 12,250 Litigation settlement....................... -- (42,750) -- Gain from adjustment of contingency reserve. -- 24,000 -- Expense of debt exchange transaction........ -- (9,651) -- Expense of Corporate Conversion............. -- -- (2,144) Other....................................... (4,011) 3,235 (3,479) ------- ------- ------- $19,264 $ 6,838 $14,435 ======= ======= =======
The gains from futures and securities investments relate to Mesa's investments in marketable securities and futures contracts that are not accounted for as hedges of future production. The gains from collection of interest from Bicoastal Corporation relates to a note receivable from such company, which was in bankruptcy. Mesa's claims in the bankruptcy exceeded its recorded receivable. As of year-end 1994, Mesa had collected the full amount of its allowed claim plus a portion of the interest due on such claims. The gains on dispositions of oil and gas properties relate primarily to 1993 sales of oil producing properties in the deep Hugoton and Rocky Mountain areas and the 1992 sale of Mesa s interests in Canada for approximately $26 million and $12 million, respectively.
The litigation settlement charge relates to Mesa's early 1994 settlement of a lawsuit with Unocal Corporation ("Unocal"). The litigation related to a 1985 investment in Unocal by Original Mesa and certain other defendants. The plaintiffs had sought to recover alleged "short-swing profits" plus interest totaling over $150 million pursuant to Section 16(b) of the Securities Exchange Act of 1934. In early 1994 Mesa and the other defendants reached a settlement with the plaintiffs and agreed to pay $47.5 million to Unocal, of which Mesa's share was $42.8 million. Mesa issued additional 12-3/4% secured discount notes due June 30, 1998 with a face amount of $48.2 million and used the proceeds to pay its share of the settlement.
In the fourth quarter of 1993 Mesa completed a settlement with the Internal Revenue Service (the "IRS") resolving all tax issues relating to the 1984 through 1987 tax returns of Original Mesa. Mesa had previously established contingency reserves for the IRS claims and certain other contingent liabilities in excess of the actual and estimated liabilities. As a result of the settlement with the IRS and the resolution and revaluation of certain other contingent liabilities, Mesa recorded a net gain of $24 million in the fourth quarter of 1993.
The debt exchange expense relates to costs associated with Mesa's $600 million debt exchange transaction completed in 1993. The Corporate Conversion expense relates to costs associated with the year-end 1991 conversion of the Partnership to MESA Inc.
Production Allocation Agreement -------------------------------
Effective January 1, 1991, Mesa entered into the PAA with CIG which allocates 77% of reserves and production from the West Panhandle field to Mesa and 23% to CIG. During 1994, 1993, and 1992, Mesa produced and sold 69%, 74% and 61%, respectively, of total production from the field; the balance of field production was sold by CIG. Mesa records its 77% ownership interest in natural gas production as revenue. The difference between the net value of production sold by Mesa and the net value of its 77% entitlement is accrued as a gas balancing receivable. The revenues and costs associated with such accrued production are included in results of operations.
The following table presents the incremental effect on production and results of operations from entitlement production recorded in excess of actual sales as a result of the PAA (dollars in thousands):
Years Ended December 31 --------------------------- 1994 1993 1992 ------- ------- -------
Revenues accrued.......................... $ 8,662 $ 5,145 $23,270 Costs and expenses accrued................ (3,075) (1,059) (6,073) Depreciation, depletion and amortization.. (3,713) (1,244) (10,764) ------- ------- ------- Total................................ $ 1,874 $ 2,842 $ 6,433 ======= ======= ======= Production Accrued: Natural gas (MMcf)................... 2,386 740 6,772 Natural gas liquids (MBbls).......... 355 106 972
At December 31, 1994, the long-term gas balancing receivable from CIG, net of accrued costs, relating to the PAA was $39.9 million, which is included in other assets in the consolidated balance sheet. The provisions of the PAA allow for periodic and ultimate cash balancing to occur. The PAA also provides that CIG may not take in excess of its 23% share of ultimate production.
Mesa entered into an amendment to the PAA in 1993 which allows Mesa, for the first time, to market its residue gas production outside of Amarillo, Texas, but which also limits Mesa's production to 35 Bcf of unprocessed gas in 1993 and 32 Bcf annually in 1994 through 1996. Mesa produced 31 Bcf and 35 Bcf in 1994 and 1993, respectively.
Capital Resources and Liquidity -------------------------------
Mesa is primarily in the business of exploring for, developing, producing, and processing oil and natural gas. At December 31, 1994, Mesa owned over 1.8 Tcfe of proved equivalent natural gas reserves. Mesa is also highly leveraged with over $1.2 billion of long-term debt, including current maturities. HCLP, an indirect subsidiary of Mesa, is the obligor on approximately 44% of Mesa's consolidated long-term debt. The HCLP debt is secured by Mesa s Hugoton field properties, which represent approximately 65% of Mesa s oil and gas reserves. The assets and cash flows of HCLP that are subject to the mortgage securing the HCLP debt are dedicated to service HCLP s debt and are not available to pay creditors of Mesa or its subsidiaries other than HCLP. However, any "excess cash," as defined in the HCLP debt agreements, may be distributed by HCLP to its equity owners, MOC, MHC and HMC, which are direct subsidiaries of Mesa, to be used for general corporate purposes. MOC owns all of Mesa s interest in the West Panhandle field of Texas and the Gulf Coast and the Rocky Mountain areas. At December 31, 1994, MOC owned an approximate 99% limited partnership interest in HCLP. The Company and MOC are liable for all of the Company's consolidated long- term debt other than the HCLP debt. MHC owns cash and securities, an approximate 1% limited partnership interest in HCLP and 100% of Mesa Environmental, a company established to compete in the natural gas vehicle market. HMC owns the general partner interest in HCLP.
Approximately 88% of Mesa's non-HCLP debt does not require cash interest payments until December 31, 1995. Beginning on this date, and until the debt is repaid, Mesa is required to make semiannual interest payments in cash at a 12-3/4% annual rate. If Mesa had been required to make cash interest payments on this debt in 1994, the interest payments would have totaled $70.6 million. These additional interest payments would have exceeded Mesa's 1994 consolidated cash flows from operating activities, which totaled $48.6 million. Mesa also has significant principal payments due in 1996 and 1998.
Following is a discussion of Mesa's debt, resources and alternatives:
Long-term Debt --------------
The following table provides additional information as to Mesa's long- term debt at December 31, 1994, (in thousands):
Obligors ----------------- Company and MOC HCLP Total -------- -------- ---------- Debt: HCLP Secured Notes(a)............... $ -- $520,180 $ 520,180 Credit Agreement(b)................. 71,131 -- 71,131 12-3/4% secured discount notes(c)(e) 581,942 -- 581,942 12-3/4% unsecured discount notes(d)(e)....................... 37,345 -- 37,345 Other............................... 12,695 -- 12,695 -------- -------- ---------- 703,113 520,180 1,223,293 Current maturities....................... (15,305) (15,232) (30,537) -------- -------- ---------- Long-term debt........................... $687,808 $504,948 $1,192,756 ======== ======== ==========
---------- (a) These notes are secured by the Hugoton field properties and are due in semiannual installments through August 2012, but may be repaid earlier depending on the rate of production from the properties.
(b) The bank credit facility (the "Credit Agreement") is secured by a first lien on MOC's West Panhandle properties, Mesa's equity interest in MOC and a 76% limited partnership interest in HCLP and is due in various installments through June 1997. At December 31, 1994, the Credit Agreement also supported letters of credit totaling $11.4 million.
(c) These notes are due in June 1998 and are secured by second liens on MOC's West Panhandle properties and a 76% limited partnership interest in HCLP.
(d) These notes are unsecured and are due in June 1996.
(e) These secured and unsecured discount notes (together, the "Discount Notes") do not require cash interest payments until December 31, 1995, but the accreted value of such Discount Notes increases at 12-3/4% per annum through June 30, 1995.
The following tables summarize Mesa's 1994 actual and 1995 through 1998 forecast cash requirements, assuming no changes in capital structure, for interest, debt principal and capital expenditures (in thousands):
Actual Forecast -------- ----------------------------------- 1994 1995 1996 1997 1998 -------- -------- -------- -------- -------- HCLP: Interest payments, net(a)............... $ 46,815 $ 46,000 $ 45,900 $ 41,200 $ 37,800 Principal repayments... 21,420 15,200 32,300 35,800 37,000 Capital expenditures(b) 6,957 11,100 5,000 1,000 -- -------- -------- -------- -------- -------- $ 75,192 $ 72,300 $ 83,200 $ 78,000 $ 74,800 ======== ======== ======== ======== ======== Other Mesa subsidiaries: Interest payments, net(a)............... $ 1,945 $ 47,500 $ 92,300 $ 96,900 $ 99,400 Principal repayments(c) 153,687 15,300 62,200 38,600 617,400 Capital expenditures(b)(d)... 25,633 25,500 9,700 15,500 2,400 -------- -------- -------- -------- -------- $181,265 $ 88,300 $164,200 $151,000 $719,200 ======== ======== ======== ======== ======== ---------- (a) Cash interest payments, net of interest income. MOC is required to begin making semiannual cash interest payments on the Discount Notes on December 31, 1995.
(b) Forecast capital expenditures represent Mesa's best estimate of drilling and facilities expenditures required to attain projected levels of production from its existing properties during the forecast period and to fund its current exploration and development program. Capital expenditures include $10.7 million of committed capital expenditures for 1995, which is included in the amount set forth in the table. Mesa may incur capital expenditures in addition to those reflected in the table.
(c) Includes approximately $93 million of principal repayments made in 1994 with proceeds from a $93 million equity offering completed in the second quarter of 1994. Such principal was scheduled to mature in 1996.
(d) Over the next two years, Mesa may spend an estimated $11 million in exploratory capital contingent upon evaluation and identifi- cation of additional prospects for drilling. These amounts are not included in the above table.
The Credit Agreement contains restrictive covenants which require Mesa to maintain a tangible adjusted equity, as defined, of at least $50 million and available cash, as defined, of $32.5 million. At December 31, 1994, tangible adjusted equity was $125 million and available cash was $105 million.
The indentures governing the Discount Notes restrict, among other things, Mesa's ability to incur additional indebtedness, pay dividends, acquire stock or make investments, loans and advances. The Credit Agreement also restricts, among other things, Mesa's ability to incur additional indebtedness, create liens, pay dividends, acquire stock or make investments, loans and advances.
Company Resources -----------------
The following table sets forth certain of Mesa s near-term resources as of or for the year ended December 31, 1994, (in thousands):
Other Subsidiaries MOC HCLP Combined Total -------- -------- ------------ --------
Cash and securities(a)......... $ 40,815 $ 49,638 $ 72,081 $162,534 Working capital................ 21,958 19,097 74,600 115,655 Restricted cash(b)............. -- 61,299 -- 61,299
Cash flows from operating activities: Oil and gas sales, net of production and administrative costs.... $ 37,768 $ 89,952 $ -- $127,720 Litigation settlement(c).. (42,750) -- -- (42,750) Interest payments, net(d). (4,992) (46,815) 3,047 (48,760) Other..................... (6,028) (2,689) 21,104 12,387 -------- -------- -------- -------- $(16,002) $ 40,448 $ 24,151 $ 48,597 ======== ======== ======== ======== ---------- (a) Included in working capital.
(b) Non-current asset in balance sheet.
(c) In March 1994 Mesa issued additional 12-3/4% secured discount notes and used the proceeds of $42.8 million to settle the Unocal litigation. See "Other Income (Expense)."
(d) Cash interest payments, net of interest income.
Mesa's cash flows from operating activities are substantially dependent on the amount of oil and gas produced and the price received for such production. Production and prices received from Mesa's properties, together with available cash and securities balances, are expected, under Mesa's current operating plan, to generate sufficient cash flow to meet Mesa's required principal, interest and capital obligations through December 31, 1995.
Mesa s current financial forecasts indicate that Mesa will be unable to fund its principal and interest obligations on MOC debt in 1996 with cash flows from operating activities and available cash and securities balances. To address this situation and to position Mesa for expansion through exploration and development, in December 1994 Mesa announced its intent to sell all or a portion of its interests in the Hugoton field, and in the first quarter of 1995 began an auction process to sell such properties. (See "Hugoton Properties Sale" below.) Proceeds from such a sale would be used to retire long-term debt. If Mesa does not sell its Hugoton properties, it would attempt to strengthen its financial condition by other means, including the sale of additional equity or refinancing of its long- term debt. There can be no assurance that Mesa will sell its Hugoton properties or that, in the absence of such a sale, Mesa will be able to issue equity or refinance its debt.
Hugoton Properties Sale -----------------------
In the first quarter of 1995 Mesa began an auction process to sell its interests in the Hugoton field, including the Satanta Plant, by approaching a select group of prospective buyers which have the financial means to complete a purchase of Mesa s entire interest. Mesa hopes to complete a sale by mid-1995.
Mesa intends to use proceeds from a sale to retire debt. Any sales proceeds must first be applied against the outstanding balances related to the HCLP Secured Notes, which are secured by the Hugoton properties. Such balances include note principal, accrued interest and any premiums due, including premiums for early retirement of the notes. As of December 31, 1994, such premiums for early retirement of the notes would have totaled approximately $42 million. The actual premiums due in the event of a redemption of the HCLP Secured Notes will depend upon the prevailing interest rates at the date of redemption. The restricted cash held at HCLP would be available to repay obligations under the HCLP Secured Notes. Sales proceeds remaining after satisfying the HCLP Secured Note obligations would be applied to the amounts outstanding under the Credit Agreement, including outstanding letters of credit, and the Discount Notes. Mesa expects to record a gain from the sale.
Excluding the Hugoton properties, Mesa had approximately 648 Bcfe of proved reserves at December 31, 1994, and had approximately 55 Bcfe of oil and gas production in 1994. Excluding Hugoton, Mesa generated approximately $40 million of cash flows from sales of oil and gas production, net of operating and administrative expenses, in 1994.
Masterson Lawsuit -----------------
Mesa and CIG are defendants in a lawsuit brought by the lessors of a portion of Mesa s interests in the West Panhandle field. In the lawsuit, the plaintiffs allege that CIG and Mesa have underpaid royalties by approximately $500 million since 1967 as a result of CIG's use of an improper gas sales price upon which to calculate royalties and that the proper price should have been determined pursuant to a "favored nations" clause included in a 1967 Gas Lease Amendment. In March 1995 the court made several rulings which eliminated approximately $400 million of the plaintiffs' claims, but which also reduced a number of CIG's and Mesa's defenses. Mesa and CIG have stipulated to the court that Mesa would be liable for between 50% and 60% of any adverse judgment against CIG for post- February 1988 underpayment of royalties. The trial began March 22, 1995. Additional information regarding the lawsuit is contained in Note 9 to the consolidated financial statements of the Company located elsewhere in this Form 10-K.
Mesa does not expect the ultimate resolution of this lawsuit to have a material adverse effect on its financial position or results of operations. However, no determination can be made at this time as to the ultimate outcome and a significant final judgment for the plaintiffs could have such a material adverse effect. Mesa and CIG would expect to appeal any adverse decision reached by the U.S. District Court and would expect to argue on appeal many of the defenses which were ruled against by the court. In the event of an adverse decision at the U.S. District Court, Mesa would be required to post a bond to appeal. Mesa believes that it has sufficient resources to post such a bond and to pursue an appeal. Mesa's financial flexibility could be adversely affected in 1996 because of the bonding requirements.
Other -----
Mesa recognizes its ownership interest in natural gas production as revenue. Actual production quantities sold may be different from Mesa's ownership share of production in a given period. Mesa records these differences as gas balancing receivables or as deferred revenue. Net gas balancing underproduction represented approximately 5% of total equivalent production in 1994 compared with 3% during the same period in 1993. The gas balancing receivable or deferred revenue component of natural gas and natural gas liquids revenues in future periods is dependent on future rates of production, field allowables and the amount of production taken by Mesa or by its joint interest partners.
Mesa invests from time to time in marketable equity and other securities, as well as in commodity futures contracts primarily related to crude oil and natural gas. Mesa also enters into natural gas futures contracts as a hedge against natural gas price fluctuations.
Management does not anticipate that inflation will have a significant effect on Mesa's operations.
Item 8.
Item 8. Consolidated Financial Statements and Supplementary Data =================================================================
The consolidated financial statements of the Company, and notes thereto, together with the report of Arthur Andersen LLP, Mesa's independent public accountants, dated March 22, 1995, and supplementary data are included in this Form 10-K under Item 14 on pages 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 the Registrant appears in Mesa's Proxy Statement for the 1995 Annual Meeting of Stockholders which is to be filed with the Commission (the "Proxy Statement"), and such information is incorporated by reference herein.
Item 11.
Item 11. Executive Compensation ================================
The presentation of Executive Compensation of the Registrant appears in the Proxy Statement and such information (other than information that is not required to be set forth in this Form 10-K) is incorporated by reference herein.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management ========================================================================
The presentation of Security Ownership of Certain Beneficial Owners and Management of the Registrant appears in the Proxy Statement and such information is incorporated by reference herein.
Item 13.
Item 13. Certain Relationships and Related Transactions ========================================================
The information in Item 11 above, "Executive Compensation," and in the Proxy Statement under "Election of Directors," is incorporated by reference herein.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ==========================================================================
(a)(1) Consolidated Financial Statements and Supplementary Data ----------------------------------------------------------------
Page in Form 10-K -----------------
Report of Independent Public Accountants........... Consolidated Statements of Operations.............. Consolidated Balance Sheets........................ Consolidated Statements of Cash Flows.............. Consolidated Statements of Changes in Stockholders' Equity.......................... Notes to Consolidated Financial Statements......... Supplemental Financial Data........................
(a)(2) Consolidated Financial Statement Schedules --------------------------------------------------
The consolidated financial statement schedules have been omitted because they are not required, are not applicable or the information required has been included elsewhere herein.
(a)(3) Exhibits ----------------
(Asterisk indicates exhibits are incorporated by reference herein).
*3.1 - Amended and Restated Articles of Incorporation of MESA Inc. dated December 31, 1991 (Exhibit 3[a] to the Company's Form 10-K dated December 31, 1991).
*3.2 - Amended and Restated Bylaws of MESA Inc. (Exhibit 3[c] to the Company's Registration Statement on Form S-4, Registration No. 33-42102).
*4.1 - Indenture dated as of May 1, 1993, among MESA Inc., Mesa Operating Limited Partnership, Mesa Capital Corporation and Harris Trust and Savings Bank, as Trustee, relating to the secured discount notes and including (a) a form of Secured Notes, (b) a form of Deed of Trust, Assignment of Production, Security Agreement and Financing Statement, dated as of May 1, 1993, between Mesa Operating Limited Partnership and Harris Trust and Savings Bank, as trustee, securing the Secured Notes, and (c) a form of Security Agreement, Pledge and Financing Statement dated as of May 1, 1993, between Mesa Operating Limited Partnership and Harris Trust and Savings Bank, as trustee, securing the Secured Notes (Exhibit 4[f] to the Company's Form 10-Q/A dated June 30, 1993).
*4.2 - First Supplemental Indenture dated as of January 5, 1994, among MESA Inc., Mesa Operating Co., Mesa Capital Corporation and Harris Trust and Savings Bank, as Trustee (Exhibit 4.2 to the Company's Registration Statement on Form S-1, Registration No. 33-51909).
*4.3 - First Supplement to Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of March 2, 1994, between Mesa Operating Co. as Mortgagor and Debtor, and Harris Trust and Savings Bank, as mortgagee and Secured Party (Exhibit 4.8 to the Company's Form 10-Q dated March 31, 1994).
*4.4 - First Supplement to Security Agreement, Pledge and Financing Statement dated as of March 2, 1994, by Mesa Operating Co. in favor of Harris Trust and Savings Bank, as Trustee for the pro rata benefit of the Noteholders under the Indenture (Exhibit 4.9 to the Company's Form 10-Q dated March 31, 1994).
*4.5 - Indenture dated as of May 1, 1993, among MESA Inc., Mesa Operating Limited Partnership, Mesa Capital Corporation and American Stock Transfer & Trust Company, as Trustee, relating to the unsecured discount notes (Exhibit 4[g] to the Company's Form 10-Q/A dated June 30, 1993).
*4.6 - First Supplemental Indenture dated as of January 5, 1994, among MESA Inc., Mesa Operating Co., Mesa Capital Corporation and American Stock Transfer & Trust Company, as Trustee (Exhibit 4.4 to the Company's Registration Statement on Form S-1, Registration No. 33-51909).
4.7 - Third Amended and Restated Credit Agreement dated as of November 29, 1994, among the Company, Mesa Operating Co., and the Banks named in this Credit Agreement and Societe Generale, Southwest Agency, as Agent.
*4.8 - Indenture dated May 1, 1989, among Mesa Capital Corporation, Mesa Limited Partnership, Mesa Operating Limited Partnership, and Texas Commerce Bank National Association, as Trustee (Exhibit 4[c] to the Partnership's Form 10-Q dated March 31, 1989).
*4.9 - First Supplemental Indenture dated as of December 31, 1991, among Mesa Capital Corporation, MESA Inc., Mesa Operating Limited Partnership, as Issuers, and Texas Commerce Bank National Association, as Trustee (Exhibit 4[e] to the Company's Form 10-K dated December 31, 1991).
*4.10 - Second Supplemental Indenture dated as of April 30, 1992, among Mesa Capital Corporation, MESA Inc., Mesa Operating Limited Partnership and Texas Commerce Bank National Association, as Trustee (Exhibit 4[k] to the Company's Form 10-Q dated June 30, 1992).
*4.11 - Third Supplemental Indenture dated as of August 26, 1993, among Mesa Capital Corporation, MESA Inc., Mesa Operating Limited Partnership and Texas Commerce Bank National Association, as Trustee (Exhibit 4[l] to the Company's Form 10-Q/A dated June 30, 1993).
*4.12 - Fourth Supplemental Indenture dated as of January 5, 1994, among MESA Inc., Mesa Operating Co., Mesa Capital Corporation and Texas Commerce Bank National Association, as Trustee (Exhibit 4.16 to the Company's Registration Statement on Form S-1, Registration No. 33-51909).
*4.13 - Indenture dated as of May 30, 1991, among Hugoton Capital Limited Partnership, Hugoton Capital Corporation and Bankers Trust Company (Exhibit 4[e] to the Partnership's Form 10-Q dated June 30, 1991).
*4.14 - First Supplemental Indenture dated September 1, 1991, among Hugoton Capital Limited Partnership, Hugoton Capital Corporation and Bankers Trust Company, as Trustee (Exhibit 4[h] to the Company's Registration Statement on Form S-4, Registration No. 33-42102).
*4.15 - Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement dated June 12, 1991, from Hugoton Capital Limited Partnership to Bankers Trust Company, as Collateral Agent (Exhibit 4[f] to the Partnership's Form 10-Q dated June 30, 1991).
*4.16 - Second Amended and Restated Credit Agreement dated as of May 1, 1993, among the Company, Mesa Operating Limited Partnership, the Banks, and Societe Generale, Southwest Agency, as Agent (Exhibit 4.17 to the Company's Registration Statement on Form S-4, Registration No. 33-53706).
*4.17 - Assignment and Assumption Agreement dated as of January 5, 1994, among Mesa Inc., Mesa Operating Co., Mesa Operating Limited Partnership, Pickens Operating Co., the Banks party to the Credit Agreement and the Agent with respect to the Credit Agreement (Exhibit 4.21 to the Company's Registration Statement on Form S-4, Registration No. 33-53706).
*4.18 - Intercreditor Agreement dated as of August 26, 1993, among Societe Generale, Southwest Agency, as agent for the Banks under the Company's Credit Agreement, Harris Trust and Savings Bank, as trustee with respect to the Secured Notes, and American Stock Transfer & Trust Company, as trustee with respect to the Unsecured Notes and the Convertible Notes (Exhibit 4.18 to the Company's Registration Statement on Form S-4, Registration No. 33-53706).
*4.19 - Amended and Restated Pledge Agreement dated as of March 2, 1994, by Mesa Operating Co., in favor of Societe Generale, Southwest Agency, as Agent for the pro rata benefit of the banks parties to the Credit Agreement (Exhibit 4.31 to the Company's Form 10-Q dated March 31, 1994).
The Registrant agrees to furnish to the Commission upon request any instruments defining the right of holders of long-term debt with respect to which the total amount outstanding does not exceed 10% of the total assets of the Registrant and its subsidiaries on a consolidated basis.
*10.1 - Form of First Amendment to Deferred Compensation Agreement and Life Insurance Agreement between Mesa Petroleum Co. and certain officers and key employees (Exhibit 10[i] to the Company's Form 10-K dated December 31, 1980).
*10.2 - Hugoton (MTR) Gas Purchase Contract between The Kansas Power and Light Company, buyer, and Mesa Operating Limited Partnership, seller, dated effective January 1, 1990 (Exhibit 19[a] to the Partnership's Form 10-Q dated June 30, 1989).
*10.3 - Supplemental Gas Purchase Contract between The Kansas Power and Light Company, buyer, and Mesa Operating Limited Partnership, seller, dated effective January 1, 1990 (Exhibit 19[b] to the Partnership's Form 10-Q dated June 30, 1989).
*10.4 - Contract dated January 3, 1928, between Colorado Interstate Gas Company and Amarillo Oil Company (the B Contract) (Exhibit 10.1 to Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.5 - Amendments to the "B" Contract (Exhibit 10.2 to Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.6 - Gathering Charge Agreement dated January 20, 1985, as amended, with respect to the "B" Contract (Exhibit 10.3 to Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.7 - Agreement of Compromise and Settlement dated May 29, 1987, between the Partnership and Colorado Interstate Gas Company (Confidential Treatment Requested) (Exhibit 10[s] to the Partnership's Form 10-K dated December 31, 1987).
*10.8 - Agreement of Sale between Pioneer Corporation and Cabot Corporation dated August 29, 1984 (Exhibit 10.5 to Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.9 - Gas Purchase Contract dated June 27, 1949, as amended through October 3, 1985, between Amarillo Oil Company and Energas Company (Exhibit 10.6 to Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.10 - Settlement Agreement dated March 15, 1989, by and among Mesa Operating Limited Partnership and Mesa Limited Partnership, et al, Energas Company and the City of Amarillo (Exhibit 10[k] to the Partnership's Form 10-K dated December 31, 1990).
*10.11 - Gas Purchase Agreement dated December 1, 1989, between Williams Natural Gas Company and Mesa Operating Limited Partnership acting on behalf of itself and as agent for Mesa Midcontinent Limited Partnership (Exhibit 10.1 to Registration Statement of the Partnership on Form S-3, Registration No. 33-32978).
*10.12 - Third Amendment dated December 19, 1991, to the Hugoton (MTR) Gas Purchase Contract between The Kansas Power and Light Company, buyer, and Mesa Operating Limited Partnership, seller, dated effective January 1, 1990 (Exhibit 10[q] to the Company's Form 10-K dated December 31, 1991).
*10.13 - "B" Contract Production Allocation Agreement dated July 29, 1991, and effective as of January 1, 1991, between Colorado Interstate Gas Company and Mesa Operating Limited Partnership (Exhibit 10[r] to the Company's Form 10-K dated December 31, 1991).
*10.14 - Amendment to "B" Contract Production Allocation Agreement effective as of January 1, 1993, between Colorado Interstate Gas Company and Mesa Operating Limited Partnership (Exhibit 10.24 to the Company's Registration Statement on Form S-1, Registration No. 033-51909).
*10.15 - Amended Supplemental Stipulation and Agreement between Colorado Interstate Gas Company and Mesa Operating Limited Partnership dated June 19, 1991 (Exhibit 10[w] to the Company's Registration Statement on Form S-4, Registration No. 33-42102).
*10.16 - Amended Peak Day Gas Purchase Agreement dated effective June 19, 1991, between Colorado Interstate Gas Company and Mesa Operating Limited Partnership (Exhibit 10[t] to the Company's Form 10-K dated December 31, 1991).
*10.17 - Omnibus Amendment to Collateral Instruments to Supplemental Stipulation and Agreement dated June 19, 1991, between Colorado Interstate Gas Company and Mesa Operating Limited Partnership (Exhibit 10[u] to the Company's Form 10-K dated December 31, 1991).
*10.18 - First Amendment to Settlement and Interim Release Agreement between Hugoton Capital Limited Partnership, Mesa Operating Limited Partnership and The Kansas Power and Light Company dated December 19, 1991, (Exhibit 10[w] to the Company's Form 10-K dated December 31, 1991).
*10.19 - Engagement Agreement dated as of July 1, 1991, between Mesa Limited Partnership, Mesa Operating Limited Partnership, Mesa Holding Limited Partnership, Mesa Midcontinent Limited Partnership, Mesa Acquisition Limited Partnership, and BTC Partners, Inc. (Exhibit 10[v] to the Company's Registration Statement on Form S-4, Registration No. 33-42102).
*10.20 - Conversion Agreement dated as of December 31, 1991, between Mesa, Boone Pickens and Pickens Operating Co. (Exhibit 10[y] to the Company's Form 10-K dated December 31, 1991).
*10.21 - Amendment to the Gas Purchase Contract dated June 27, 1949, as amended, between Amarillo Oil Company and Energas Company dated June 4, 1992 (Exhibit 10[z] to the Company's Form 10-K dated December 31, 1992).
*10.22 - Agreement of Compromise and Settlement dated January 11, 1994, among Unocal Corporation, David Colan, MESA Inc. and certain other parties (Exhibit 10.25 to the Company's Registration Statement on Form S-1, Registration No. 033-51909).
*10.23 - Agreement of merger, dated as of January 5, 1994, entered into by and among the Company, Boone Pickens and certain other parties (Exhibit 10.27 to the Company's Form 10-K dated December 31, 1993).
10.24 - Gas Transportation Agreement dated June 14, 1994, between Western Resources, Inc. and Mesa Operating Co., acting on behalf of itself and as agent for Hugoton Capital Limited Partnership.
*10.25 - Incentive Bonus Plan of Mesa Operating Limited Partnership, as amended, dated effective January 1, 1986 (Exhibit 10[s] to the Partnership's Form 10-K dated December 31, 1990).
*10.26 - Performance Bonus Plan of Mesa Operating Limited Partnership dated effective January 1, 1990 (Exhibit 10[t] to the Partnership's Form 10-K dated December 31, 1990).
*10.27 - 1991 Stock Option Plan of Mesa (Exhibit 10[v] to the Company's Form 10-K dated December 31, 1991).
*10.28 - Split-Dollar Insurance Agreements dated June 29, 1992, by and between Mesa Operating Limited Partnership and Boone Pickens and Paul Cain, respectively, and Collateral Assignments dated as of June 29, 1992, by Boone Pickens and Paul Cain, respectively (Exhibit 10[aa] to the Company's Form 10-K dated December 31, 1992).
22 - List of Subsidiaries of the Company.
27 - Article 5 of Regulation S-X Financial Data Schedule for Year-End 1994 Form 10-K.
28 - Summary Report of the Company relating to proved oil and gas reserves at December 31, 1994.
(b) Reports on Form 8-K ------------------------
1. Current Report on Form 8-K dated February 17, 1995, regarding the Annual Meeting of Stockholders of the Company to be held May 17, 1995.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MESA INC.
By: /s/ Boone Pickens ------------------------------------ Date: March 30, 1995 (Boone Pickens, -------------- Chief Executive Officer) ----------
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ----
/s/ Boone Pickens ------------------------- Chief Executive Officer and March 30, 1995 (Boone Pickens) Chairman of the Board of Directors (Principal Executive Officer) /s/ Paul W. Cain ------------------------- President, Chief Operating March 30, 1995 (Paul W. Cain) Officer and Director
/s/ Stephen K. Gardner ------------------------- Vice President and Chief March 30, 1995 (Stephen K. Gardner) Financial Officer (Principal Financial Officer)
/s/ William D. Ballew ------------------------- Controller March 30, 1995 (William D. Ballew) (Principal Accounting Officer)
/s/ John L. Cox ------------------------- Director March 30, 1995 (John L. Cox)
/s/ John S. Herrington ------------------------- Director March 30, 1995 (John S. Herrington)
/s/ Wales H. Madden, Jr. ------------------------- Director March 30, 1995 (Wales H. Madden, Jr.)
/s/ Fayez S. Sarofim ------------------------- Director March 30, 1995 (Fayez S. Sarofim)
/s/ Robert L. Stillwell ------------------------- Director March 30, 1995 (Robert L. Stillwell)
/s/ J. R. Walsh, Jr. ------------------------- Director March 30, 1995 (J. R. Walsh, Jr.)
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA --------------------------------------------------------
Page in Form 10-K -----------------
Report of Independent Public Accountants................ Consolidated Statements of Operations................... Consolidated Balance Sheets............................. Consolidated Statements of Cash Flows................... Consolidated Statements of Changes in Stockholders' Equity............................... Notes to Consolidated Financial Statements.............. Supplemental Financial 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, 1994 and 1993, and the related consolidated statements of operations, cash flows and changes in stockholders' equity for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed further in Note 2 to the consolidated financial statements, the Company's current financial forecasts indicate that the Company will be unable to fund its principal and interest obligations in 1996 with cash flows from operating activities and available cash and securities balances. Also, as discussed further below, the Company would be required to post a bond in the event of an adverse decision in a lawsuit. This could result in accentuating the Company's forecasted inability to fund its principal and interest obligations in 1996. In December 1994 the Company announced its intent to sell all or a portion of its interests in the Hugoton field. In the first quarter of 1995 the Company began an auction process to sell such properties. Proceeds from such a sale would be used to retire long-term debt. If the Company does not sell its Hugoton properties, it would attempt to strengthen its financial position by other means, including the sale of additional equity or refinancing of its long-term debt. There can be no assurances that, in the absence of such a sale, the Company will be able to issue equity or refinance its debt.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of MESA Inc. and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed further in Note 9 to the consolidated financial statements, the Company is a defendant in a lawsuit alleging royalty underpayments relating to the Company s interest in an oil and gas lease. As discussed further in Note 2 to the consolidated financial statements, an unfavorable final judgment could have a material adverse effect on the Company s financial position and results of operations. The Company would be required to post a bond to appeal an adverse decision at the U.S. District Court. The Company believes it will have sufficient resources to post a bond requirement; however, the Company's cash position and financial flexibility could be adversely affected in 1996 by such a bond requirement. Although the Company does not expect the ultimate resolution of this lawsuit to have a material adverse effect on its financial position or results of operations, no determination can be made at this time as to the ultimate outcome of the litigation and no estimate of damages, if any, can be made. Accordingly, no provision for any liability that may result upon the adjudication has been made in the accompanying consolidated financial statements.
/s/ Arthur Andersen LLP ----------------------- ARTHUR ANDERSEN LLP Houston, Texas March 22, 1995
MESA Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS ------------------------------------- (in thousands, except per share data)
Years Ended December 31 ------------------------------- 1994 1993 1992 --------- --------- --------- Revenues: Natural gas........................... $ 139,580 $ 141,798 $ 157,672 Natural gas liquids................... 72,771 61,427 59,669 Oil and condensate.................... 7,877 12,428 18,701 Other................................. 8,509 6,551 1,070 --------- --------- --------- 228,737 222,204 237,112 --------- --------- --------- Costs and Expenses: Lease operating....................... 52,655 51,819 43,859 Production and other taxes............ 21,306 20,332 18,631 Exploration charges................... 5,157 2,705 10,008 General and administrative............ 28,649 25,237 24,460 Depreciation, depletion and amortization........................ 92,287 100,099 113,933 --------- --------- --------- 200,054 200,192 210,891 --------- --------- ---------
Operating Income........................... 28,683 22,012 26,221 --------- --------- ---------
Other Income (Expense): Interest income....................... 13,457 10,704 13,504 Interest expense...................... (144,757) (142,002) (143,392) Gains from futures and securities investments......................... 6,698 3,954 7,808 Gains from collections from Bicoastal Corporation............... 16,577 18,450 -- Gains on dispositions of oil and gas properties.................. -- 9,600 12,250 Litigation settlement................. -- (42,750) -- Gain from adjustment of contingency reserve............................. -- 24,000 -- Other................................. (4,011) (6,416) (5,623) --------- --------- --------- (112,036) (124,460) (115,453) --------- --------- ---------
Net Loss................................... $ (83,353) $(102,448) $ (89,232) ========= ========= =========
Net Loss Per Common Share.................. $ (1.42) $ (2.61) $ (2.31) ========= ========= =========
Weighted Average Common Shares Outstanding. 58,860 39,272 38,571 ========= ========= =========
(See accompanying notes to consolidated financial statements.)
MESA Inc.
CONSOLIDATED BALANCE SHEETS --------------------------- (in thousands, except share data)
December 31 ---------------------- 1994 1993 ---------- ---------- ASSETS
Current Assets: Cash and cash investments..................... $ 143,422 $ 138,709 Marketable securities and futures contracts... 19,112 11,319 Accounts and notes receivable................. 38,938 43,442 Other......................................... 3,372 2,732 ---------- ---------- Total current assets..................... 204,844 196,202 ---------- ----------
Property, Plant and Equipment: Oil and gas properties, wells and equipment, using the successful efforts method of accounting................ 1,867,842 1,846,237 Office and other.............................. 43,836 41,064 Accumulated depreciation, depletion and amortization............................ (781,230) (695,455) ---------- ---------- 1,130,448 1,191,846 ---------- ----------
Other Assets: Restricted cash of subsidiary partnership..... 61,299 62,649 Gas balancing receivable...................... 54,971 47,101 Other......................................... 32,397 35,584 ---------- ---------- 148,667 145,334 ---------- ---------- $1,483,959 $1,533,382 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities: Current maturities on long-term debt.......... $ 30,537 $ 67,657 Accounts payable and accrued liabilities...... 40,468 33,375 Interest payable.............................. 18,184 19,012 ---------- ---------- Total current liabilities................ 89,189 120,044 ---------- ---------- Long-Term Debt..................................... 1,192,756 1,173,637 ---------- ---------- Deferred Revenue................................... 21,900 22,707 ---------- ---------- Other Liabilities.................................. 55,542 104,865 ---------- ---------- Contingencies
Stockholders' Equity: Preferred stock, $.01 par value, authorized 10,000,000 shares; no shares issued and outstanding................................. -- -- Common stock, $.01 par value, authorized 100,000,000 shares; outstanding 64,050,009 and 46,511,439 shares, respectively......... 640 465 Additional paid-in capital.................... 398,965 303,344 Accumulated deficit........................... (275,033) (191,680) ---------- ---------- 124,572 112,129 ---------- ---------- $1,483,959 $1,533,382 ========== ==========
(See accompanying notes to consolidated financial statements.)
MESA Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS ------------------------------------- (in thousands)
Years Ended December 31 ----------------------------- 1994 1993 1992 -------- --------- -------- Cash Flows From Operating Activities: Net loss................................ $(83,353) $(102,448) $(89,232) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion and amortization..................... 92,287 100,099 113,933 Gains on dispositions of oil and gas properties........... -- (9,600) (12,250) Accreted interest on discount notes 79,352 49,160 -- Accrued interest exchanged for discount notes................... -- 15,395 -- Litigation settlement.............. (42,750) 42,750 -- Gain from adjustment of contingency reserves............. -- (24,000) -- Increase in gas balancing receivables...................... (7,840) (4,942) (17,772) Decrease in deferred natural gas revenue.......................... (785) (3,370) (10,287) Settlement of prior year tax claims -- (12,931) -- Natural gas hedging activities..... 9,715 324 (8,357) Sales of marketable securities and futures contracts............ 18,771 39,283 126,217 Purchases of marketable securities and futures contracts............ (19,866) (34,711) (102,161) Gains from futures and securities investments...................... (6,698) (3,954) (7,808) (Increase) decrease in accounts receivable.............. 5,934 1,986 (585) Decrease in payables and accrued liabilities.............. (3,142) (15,887) (7,814) Other.............................. 6,972 (4,662) 11,733 -------- -------- -------- Net cash provided by (used in) operating activities............. 48,597 32,492 (4,383) -------- -------- -------- Cash Flows From Investing Activities: Capital expenditures.................... (32,590) (29,636) (69,201) Proceeds from dispositions of oil and gas properties................ -- 26,118 11,424 Collection of notes receivable.......... -- 47,501 28,181 Other................................... (7,660) (6,461) (11,494) -------- -------- -------- Net cash provided by (used in) investing activities............. (40,250) 37,522 (41,090) -------- -------- -------- Cash Flows From Financing Activities: Issuance of common stock................ 93,067 -- -- Repayments of long-term debt............ (175,107) (80,102) (24,550) Long-term borrowings.................... 77,754 -- -- Debt issuance costs..................... -- (9,651) -- Other................................... 652 1,251 (4,935) -------- -------- -------- Net cash used in financing activities............. (3,634) (88,502) (29,485) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Investments........................... 4,713 (18,488) (74,958)
Cash and Cash Investments at Beginning of Year....................... 138,709 157,197 232,155 -------- -------- -------- Cash and Cash Investments at End of Year..... $143,422 $138,709 $157,197 ======== ======== ========
(See accompanying notes to consolidated financial statements.)
MESA Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY ---------------------------------------------------------- (in thousands)
Common Stock Additional -------------- Paid-in Accumulated Shares Amount Capital Deficit ------ ------ ---------- -----------
Balance, December 31, 1991.......... 38,571 $386 $273,198 $ -- Net loss....................... -- -- -- (89,232) ------ ---- -------- --------- Balance, December 31, 1992.......... 38,571 386 273,198 (89,232) Net loss....................... -- -- -- (102,448) Common stock issued for 0% convertible notes......... 7,523 75 29,239 -- Common stock issued for the partial conversion of the General Partner minority interest............ 417 4 907 -- ------ ---- -------- --------- Balance, December 31, 1993.......... 46,511 465 303,344 (191,680) Net loss....................... -- -- -- (83,353) Common stock issued for the conversion of the remaining General Partner minority interest..................... 1,251 13 2,716 -- Common stock issued in secondary public offering.... 16,288 162 92,905 -- ------ ---- -------- --------- Balance, December 31, 1994.......... 64,050 $640 $398,965 $(275,033) ====== ==== ======== =========
(See accompanying notes to consolidated financial statements.)
MESA Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ------------------------------------------
(1) Organization and Summary of Significant Accounting Policies ===========================================================
MESA Inc., a Texas corporation, was formed in connection with a transaction (the "Corporate Conversion") which reorganized the business of Mesa Limited Partnership (the "Partnership"). The Partnership was formed in 1985 to succeed to the business of Mesa Petroleum Co. ("Original Mesa"). Unless the context otherwise requires, as used herein the term "Company" refers to MESA Inc. and its subsidiaries taken as a whole and includes its predecessors.
Principles of Consolidation ---------------------------
The Company owns and operates its oil and gas properties and other assets through various direct and indirect subsidiaries. Pursuant to the Corporate Conversion, the Company obtained a 95.86% limited partnership interest and Boone Pickens (the "General Partner") obtained a 4.14% general partner interest in three direct subsidiary partnerships. The general partner interest was convertible into a total of 1,667,560 shares of common stock of the Company. On December 31, 1993, the General Partner converted approximately one-fourth of his general partner interests into common stock. In early 1994 the Company effected a series of merger transactions which resulted in the conversion of each of its direct subsidiary partnerships to corporate form (see Note 13). Pursuant to these mergers, the remaining general partner interests in the Company s subsidiary partnerships held directly or indirectly by the General Partner were converted into common stock, thereby eliminating the minority interest.
The accompanying consolidated financial statements reflect the consolidated accounts of the Company and its subsidiaries after elimination of intercompany transactions.
Certain reclassifications have been made to amounts reported in previous years to conform to 1994 presentation.
Statements of Cash Flows ------------------------
For purposes of the statements of cash flows, the Company classifies all cash investments with original maturities of three months or less as cash and cash investments.
Investments -----------
On January 1, 1994, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity Securities," which addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities. The Company s portfolio of securities is classified as "trading securities" under the provisions of SFAS No. 115 and is reported at fair value, with unrealized gains and losses included in net income (loss) for the current period. The cost of securities sold is determined on the first-in, first-out basis. Prior to January 1, 1994, investments in marketable securities were stated at the lower of cost or market. The adoption of SFAS No. 115 did not have a material effect on the financial position or results of operations of the Company.
The Company enters into various futures contracts which are not intended to be hedges of future natural gas or crude oil production. Investments in such contracts are periodically adjusted to market prices and gains and losses are included in gains from futures and securities investments in the statements of operations.
Oil and Gas Properties ----------------------
Under the successful efforts method of accounting, all costs of acquiring unproved oil and gas properties and drilling and equipping exploratory wells are capitalized pending determination of whether the properties
have proved reserves. If an exploratory well is determined to be nonproductive, the drilling and equipment costs of the well are expensed at that time. All development drilling and equipment costs are capitalized. Capitalized costs of proved properties and estimated future dismantlement and abandonment costs are amortized on a property-by-property basis using the unit-of-production method. Geological and geophysical costs and delay rentals are expensed as incurred.
Unproved properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment. The aggregate carrying value of proved properties is periodically compared with the undiscounted future net cash flows from proved reserves, determined in accordance with Securities and Exchange Commission (the "Commission") regulations, and a loss is recognized if permanent impairment of value is determined to exist. A loss is recognized on proved properties expected to be sold in the event that carrying value exceeds expected sales proceeds.
Net Loss Per Common Share -------------------------
The computations of net loss per common share are based on the weighted average number of common shares outstanding during each period.
Fair Value of Financial Instruments -----------------------------------
The Company's financial instruments consist of cash, marketable securities, short-term trade receivables and payables, restricted cash, and long-term debt. The carrying values of cash, marketable securities, short- term trade receivables and payables, and restricted cash approximate fair value. The fair value of long-term debt is estimated based on the market prices for the Company's publicly traded debt and on current rates available for similar debt with similar maturities and security for the Company's remaining debt (see Note 4).
Gas Revenues ------------
The Company recognizes its ownership interest in natural gas production as revenue. Actual production quantities sold by the Company may be different than its ownership share of production in a given period. If the Company's sales exceed its ownership share of production, the differences are recorded as deferred revenue. Gas balancing receivables are recorded when the Company's ownership share of production exceeds sales. The Company also accrues production expenses related to its ownership share of production. At December 31, 1994, the Company had produced and sold a net 19.2 billion cubic feet ("Bcf") of natural gas less than its ownership share of production and had recorded gas balancing receivables, net of deferred revenues, of approximately $36.1 million. Substantially all of the Company's gas balancing receivables and deferred revenue are classified as long-term.
The Company periodically enters into natural gas futures contracts as a hedge against natural gas price fluctuations. Gains or losses on such futures contracts are deferred and recognized as natural gas revenue when the hedged production occurs. The Company recognized net gains of $5.6 million and $895,000 in 1992 and 1994, respectively, and a net loss of $324,000 in 1993 related to hedging activities. At December 31, 1994, the Company had deferred gains of $9.7 million resulting from hedging a substantial portion of the Company s anticipated natural gas production for the first three quarters of 1995. These deferred gains and any increases or decreases in 1995 in the value of open hedge contracts related to such production periods will be recognized as natural gas revenues when the hedged production occurs.
Taxes -----
The Company provides for income taxes using the asset and liability method under which deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted
statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The effect on deferred taxes of a change in tax laws or tax rates is recognized in income in the period that includes the enactment date.
(2) Resources and Liquidity =======================
The Company is highly leveraged with over $1.2 billion of long-term debt, including current maturities (see Note 4). Hugoton Capital Limited Partnership ("HCLP") is the obligor on approximately 44% of the Company's consolidated long-term debt. HCLP, an indirect, wholly owned subsidiary of the Company was formed in 1991 to issue long-term debt which is secured by the Company's Hugoton field properties which represent approximately 65% of the Company's total proved oil and gas reserves. The assets and cash flows of HCLP that are subject to the mortgage securing HCLP's debt are dedicated to service such debt and are not available to pay creditors of the Company or its subsidiaries other than HCLP. Approximately 88% of the Company's remaining debt, excluding HCLP's debt, does not require cash interest payments until December 31, 1995. On this date, and until the debt is repaid, the Company is required to make semiannual cash interest payments at a 12-3/4% annual rate. If the Company had been required to make cash interest payments on this debt in 1994, the interest payments would have totaled $70.6 million. Such payments would have exceeded the Company's 1994 consolidated cash flows from operating activities which totaled $48.6 million. The Company also has significant debt principal payments due in 1996 through 1998.
The Company's cash flows from operating activities are substantially dependent on the amount of oil and gas produced and the price received for such production. The Company expects that cash generated by its 1995 production, together with available cash and securities balances, will be sufficient to cover its debt principal and interest obligations and capital expenditures through December 31, 1995.
The Company s current financial forecasts indicate that it will be unable to fund its principal and interest obligations in 1996 with cash flows from operating activities and available cash and securities balances. To address this situation and to position the Company for expansion through exploration and development, in December 1994 the Company announced its intent to sell all or a portion of its interests in the Hugoton field. In the first quarter of 1995 the Company began an auction process to sell such properties. Proceeds from such a sale would be used to retire long-term debt. If the Company does not sell its Hugoton properties, it would attempt to strengthen its financial condition by other means, including the sale of additional equity or refinancing of its long-term debt. There can be no assurance that the Company will sell its Hugoton properties or that, in the absence of such a sale, the Company will be able to issue equity or refinance its debt.
Excluding the Hugoton properties, the Company had approximately 648 billion cubic feet of proved equivalent natural gas reserves ("Bcfe") at December 31, 1994, and had approximately 55 Bcfe of oil and gas production in 1994. Excluding Hugoton, the Company generated approximately $40 million of cash flows from sales of oil and gas production, net of operating and administrative expenses, in 1994. The Company expects to record a gain from the sale.
The Company is a defendant in a lawsuit brought by the lessors of a portion of the Company's interest in the West Panhandle field. The plaintiffs are seeking approximately $500 million for alleged underpayments of royalties. In March 1995 the court made certain pretrial rulings that eliminated approximately $400 million of the plaintiffs' claims, but which also reduced a number of the Company's defenses. The Company would be liable for between 50% and 60% of any damages in the event of an adverse judgment. The trial began on March 22, 1995. (See Note 9 for additional information regarding the lawsuit.) The Company does not expect the ultimate resolution of this lawsuit to have a material adverse effect on its financial position or results of operations. However, no determination can be made at this time as to the ultimate outcome and a significant
final judgment for the plaintiffs could have such a material adverse effect. The Company would expect to appeal any adverse decision reached by the U.S. District Court and would expect to argue on appeal many of the defenses which were ruled against by the court. In the event of an adverse decision at the U.S. District Court, the Company would be required to post a bond to appeal. The Company believes that it has sufficient resources to post such a bond and to pursue an appeal. The Company's financial flexibility could be adversely affected in 1996 because of the bonding requirements.
(3) Marketable Securities and Futures Contracts ===========================================
The value of marketable securities and futures contracts are as follows (in thousands):
December 31 -------------------- 1994 1993 ------- ------- Equity securities: Cost...................................... $ 9,489 $11,156 Unrealized loss........................... (1,381) (469)
Futures contracts: Margin cash............................... 1,337 656 Unrealized gain in hedge contracts........ 6,823 -- Unrealized gain (loss) in investment contracts............................... 2,844 (24) ------- ------- Total market value........................ $19,112 $11,319 ======= =======
In 1994 the Company recognized net gains of approximately $6.7 million from its investments in securities and futures contracts compared with net gains in 1993 of $4.0 million and in 1992 of $7.8 million. These gains and losses do not include gains or losses from natural gas futures contracts accounted for as hedges of natural gas production. Hedge gains or losses are included in natural gas revenue in the period in which the hedged production occurs (see Note 1).
The net securities and futures contracts gains and losses recognized during a period include both realized and unrealized gains and losses. The Company realized net gains from securities transactions and futures contracts of $4.7 million in 1994, $2.3 million in 1993, and $10.0 million in 1992.
(4) Long-term Debt ==============
Long-term debt and current maturities are as follows (in thousands):
December 31 ------------------------ 1994 1993 ---------- ----------
HCLP Secured Notes.......................... $ 520,180 $ 541,600 Credit Agreement............................ 71,131 59,148 12-3/4% secured discount notes.............. 581,942 472,939 12-3/4% unsecured discount notes............ 37,345 148,576 12% subordinated notes...................... -- 6,336 13-1/2% subordinated notes.................. 7,390 7,390 Other....................................... 5,305 5,305 ---------- ---------- 1,223,293 1,241,294 Current maturities.......................... (30,537) (67,657) ---------- ---------- Long-term debt.............................. $1,192,756 $1,173,637 ========== ==========
HCLP Secured Notes ------------------
In 1991 HCLP issued $616 million of secured notes (the "HCLP Secured Notes") in a private placement with a group of institutional lenders. The issuance also funded a $66 million restricted cash balance within HCLP, which is available to supplement cash flows from the HCLP properties in the event such cash flows are not sufficient to fund principal and interest payments on the HCLP Secured Notes when due. As the HCLP Secured Notes are repaid, the required restricted cash balance is reduced. HCLP holds substantially all of the Company s Hugoton field natural gas properties.
The HCLP Secured Notes were issued in 15 series and have final stated maturities extending through 2012 but can be retired earlier. The HCLP Secured Notes outstanding at December 31, 1994, bear interest at fixed rates ranging from 8.80% to 11.30% per annum (weighted average 10.27%). Principal payments, if required, and interest payments are made semiannually. Provisions in the HCLP Secured Note agreements require interest rate premiums to be paid to the noteholders in the event that the HCLP Secured Notes are repaid more rapidly or slowly than under the initial scheduled amortization. Beginning in August 1994, HCLP elected to make principal payments on the HCLP Secured Notes based on actual production, rather than according to the initial scheduled amortization. As a result, interest rate premiums at a rate of 1.5% per annum will be applied to those principal amounts not paid according to the initial scheduled amortization. Such premiums have increased the effective weighted average interest rate payable on the remaining HCLP Secured Notes outstanding to 10.33% per annum at December 31, 1994. According to current expectations, principal payments based on actual production and prices could reduce principal payments from the initial scheduled amortization by approximately $50 million through 1996.
The HCLP Secured Note agreements contain various covenants which, among other things, limit HCLP's ability to sell or acquire oil and gas property interests, incur additional indebtedness, make unscheduled capital expenditures, make distributions of property or funds subject to the mortgage, or enter into certain types of long-term contracts or forward sales of production. The agreements also require HCLP to maintain separate existence from the Company and its other subsidiaries. The assets of HCLP that are subject to the mortgage securing the HCLP Secured Notes are dedicated to service HCLP's debt and are not available to pay creditors of the Company or its subsidiaries other than HCLP. Any cash not subject to the mortgage is available for distribution to the Company's subsidiaries which own HCLP's equity.
Revenues received from production from HCLP's Hugoton properties are deposited in a collection account maintained by a collateral agent (the "Collateral Agent"). The Collateral Agent releases or reserves funds, as appropriate, for the payment of royalties, taxes, operating costs, capital expenditures and principal and interest on the HCLP Secured Notes. Only after all required payments have been made may any remaining funds held by the Collateral Agent be released from the mortgage.
The restricted cash balance and cash held by the Collateral Agent for payment of interest and principal on the HCLP Secured Notes are invested by the Collateral Agent under the terms of a guaranteed investment contract (the "GIC") with Morgan Guaranty Trust Co. of New York ("Morgan"). Morgan was paid $13.9 million at the date of issuance of the HCLP Secured Notes to guarantee that funds invested under the GIC would earn an interest rate equivalent to the weighted average coupon rate on the outstanding principal balance of the HCLP Secured Notes (10.27% at December 31, 1994). A portion of this amount may be refunded if the HCLP Secured Notes are repaid earlier than if HCLP had produced according to its scheduled production, depending primarily on prevailing interest rates at that time.
In February 1994 the Company contributed $5.8 million to HCLP which, along with $10.3 million of HCLP cash not subject to the mortgage, was used to supplement HCLP s cash flows in order to make the February 1994 scheduled principal payment. In the third quarter of 1994 HCLP distributed $10 million of cash not subject to the mortgage to the Company's subsidiaries which own HCLP's equity.
HCLP's cash balances were as follows (in thousands):
December 31 ---------------- 1994 1993 ------- -------
Subject to the mortgage.............................. $48,087 $30,595 Not subject to the mortgage.......................... 1,551 9,851 ------- ------- Cash included in current assets...................... $49,638 $40,446 ======= ======= Restricted cash included in noncurrent assets........ $61,299 $62,649 ======= ======= Refundable GIC fee included in noncurrent assets..... $10,295 $11,400 ======= =======
Mesa Operating Co. ("MOC"), a Company subsidiary which owns substantially all of the limited partnership interests of HCLP, is party to a services agreement with HCLP. MOC provides services necessary to operate the Hugoton field properties and market production therefrom, process remittances of production revenues and perform certain other administrative functions in exchange for a services fee. The fee totaled approximately $12.8 million in 1994, $11.4 million in 1993, and $10.7 million in 1992.
Credit Agreement ----------------
In the fourth quarter of 1994 the Company negotiated an amendment to its bank credit agreement (the "Credit Agreement") which extended its final maturity date from June 1995 until June 1997 and increased the amount that may be borrowed from the then outstanding $47.5 million to $82.5 million, including letters of credit. The terms of the amendment require principal payments of $10 million in December 1995, $22.5 million in 1996, and the remainder in June 1997 (including cash collateralization of letters of credit outstanding at that time). The amendment also eliminated a covenant requiring a specified ratio of cash flow and available cash to debt service. As of December 31, 1994, the Company had outstanding borrowings of approximately $71.1 million and letter of credit obligations of $11.4 million under the amended Credit Agreement.
The rate of interest payable on borrowings under the amended Credit Agreement is the Eurodollar rate plus 2-1/2% or the prime rate plus 1/2%. Obligations under the Credit Agreement are secured by a first lien on the Company's West Panhandle field properties, the Company's equity interest in MOC and a 76% limited partner interest in HCLP.
The amended Credit Agreement requires the Company to maintain tangible adjusted equity, as defined, of $50 million and available cash, as defined, of $32.5 million. At December 31, 1994, the Company's tangible adjusted equity, as defined, was approximately $125 million and available cash, as defined, was $105 million.
The Credit Agreement also restricts, among other things, the Company's ability to incur additional indebtedness, create liens, pay dividends, acquire stock or make investments, loans and advances.
Discount Notes --------------
In conjunction with a debt exchange transaction consummated on August 26, 1993, (the "Debt Exchange"), the Company issued approximately $435.5 million initial accreted value, as defined, of 12-3/4% secured discount notes due June 30, 1998 and $136.9 million initial accreted value, as defined, of 12-3/4% unsecured discount notes due June 30, 1996 (together, the "Discount Notes") in exchange for $293.7 million aggregate principal amount of 12% subordinated notes and $292.6 million aggregate principal amount of 13-1/2% subordinated notes (together with the $28.6 million of accrued interest claims thereon). The Company
also issued $29.3 million principal amount of 0% convertible notes due June 30, 1998, which were converted into approximately 7.5 million shares of common stock by the end of 1993. The Discount Notes, which rank pari passu with each other, are senior in right of payment to the remaining 13-1/2% subordinated notes due 1999 and subordinate to all permitted first lien debt, as defined, including obligations under the Credit Agreement.
On March 2, 1994, the Company issued $48.2 million face amount of additional 12-3/4% secured discount notes due June 30, 1998. The proceeds of $42.8 million were used to pay the settlement amount arising from the early 1994 settlement of a lawsuit with Unocal Corporation ("Unocal"). The additional indebtedness incurred to settle the Unocal lawsuit was specifically permitted under the terms of the indentures governing the Discount Notes and under the Credit Agreement. (See Note 9 for additional discussion of the Unocal litigation.)
The Discount Notes will not accrue interest through June 30, 1995; however, the accreted value, as defined, of both series increases at a rate of 12-3/4% per year, compounded semiannually, until June 30, 1995. After June 30, 1995, each series will accrue interest at an annual rate of 12-3/4%, payable in cash semiannually in arrears, with the first payment due December 31, 1995.
In the second quarter of 1994 the Company completed a public offering in which 16.3 million shares of the Company's common stock were sold for net proceeds of $93 million ($6 per share) (the "Equity Offering"). The Company used approximately $87 million of the proceeds to redeem or repurchase $87 million accreted value ($99.1 million face amount at maturity) of 12-3/4% unsecured discount notes which were due in 1996.
In the fourth quarter of 1994 the Company used proceeds from increased borrowings under its amended Credit Agreement to redeem $37.6 million accreted value ($40.0 million face amount at maturity) of 12-3/4% unsecured discount notes which were due in 1996.
The 12-3/4% secured discount notes are secured by second liens on the Company's West Panhandle field properties and a 76% limited partner interest in HCLP, both of which also secure obligations under the Credit Agreement. The Company's right to maintain first lien debt, as defined, is limited by the terms of the Discount Notes to $82.5 million.
The indentures governing the Discount Notes restrict, among other things, the Company's ability to incur additional indebtedness, pay dividends, acquire stock or make investments, loans and advances.
Subordinated Notes ------------------
The 13-1/2% subordinated notes are unsecured and mature in 1999. Interest on these notes is payable semiannually in cash. The 12% subordinated notes outstanding as of December 31, 1993, were redeemed on May 31, 1994, with proceeds from the Equity Offering.
Interest and Maturities -----------------------
The aggregate interest payments made during 1994, 1993, and 1992 were $62.2 million, $89.4 million and $142.7 million, respectively. Payment of approximately $70.6 million and $64.6 million of interest incurred during 1994 and 1993, respectively, has been deferred under the terms of the Debt Exchange until the repayment dates of the Discount Notes. Such interest is included in interest expense in the 1994 and 1993 consolidated statements of operations.
The scheduled principal repayments on long-term debt for the next five years are as follows (in millions):
1995 1996 1997 1998 1999 ------ ------ ------ ------ ------
HCLP Secured Notes................. $ 15.2 $ 32.3 $ 35.8 $ 37.0 $ 39.8 Credit Agreement(a)................ 10.0 22.5 38.6 -- -- 12-3/4% secured discount notes..... -- -- -- 617.4 -- 12-3/4% unsecured discount notes... -- 39.7 -- -- -- 13-1/2% subordinated notes......... -- -- -- -- 7.4 Other.............................. 5.3 -- -- -- -- ------ ------ ------ ------ ------ Total......................... $ 30.5 $ 94.5 $ 74.4 $654.4 $ 47.2 ====== ====== ====== ====== ====== ---------- (a) Excludes approximately $11.4 million in letter of credit obligations currently outstanding and required to be cash collateralized in June 1997.
Fair Value of Long-term Debt ----------------------------
The following is a summary of estimated fair value of the Company's long-term debt for the years ended (in thousands):
1994 1993 ------------------ ------------------ Carrying Fair Carrying Fair Amount Value Amount Value -------- -------- -------- --------
HCLP Secured Notes.............. $520,180 $535,135 $541,600 $614,716 Credit Agreement................ 71,131 71,131 59,148 59,148 12-3/4% secured discount notes.. 581,942 528,688 472,939 486,732 12-3/4% unsecured discount notes 37,345 37,591 148,576 141,731 13-1/2% subordinated notes...... 7,390 7,390 7,390 7,390
The fair value of long-term debt is estimated based on the market prices for the Company's publicly traded debt and on current rates available for similar debt with similar maturities and security for the Company's remaining debt. Based on the current financial condition of the Company, there is no assurance that the Company could obtain borrowings under long- term debt agreements with terms similar to those described above and receive proceeds approximating the estimated fair values.
Proposed Hugoton Properties Sale --------------------------------
In the first quarter of 1995 the Company began an auction process to sell its interest in the Hugoton field by approaching a select group of prospective buyers which have the financial means to complete a purchase of the Company's entire interest. The Company hopes to complete a sale by mid- 1995.
The Company will use proceeds from a sale to retire debt. Any sales proceeds must first be applied against the outstanding balances related to the HCLP Secured Notes, which are secured by the Hugoton properties. Such balances include note principal, accrued interest and any premiums due, including premiums for early retirement of the notes. As of December 31, 1994, such premiums for early retirement of the notes would have totaled approximately $42 million. The actual premiums due in the event of a redemption of the HCLP Secured Notes will depend upon the prevailing interest rates at the date of redemption. The restricted cash held at HCLP would be available to repay obligations under the HCLP Secured Notes. Sales proceeds remaining after satisfying the HCLP Secured Note obligations would be applied to the amounts outstanding under the amended Credit Agreement, including outstanding letters of credit, and the Discount Notes.
(5) Income Taxes ============
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires the asset and liability method under which deferred tax assets and liabilities are recognized by applying the enacted statutory tax rates applicable to future years to temporary differences between the financial statement and tax bases of existing assets and liabilities. The Company elected to adopt the change in method of accounting for income taxes prospectively in 1993. After consideration of offsetting valuation allowances, there was no cumulative effect on prior years of adopting SFAS No. 109.
The tax basis of the Company's consolidated net assets is greater than the financial basis of those net assets; therefore a net deferred tax asset has been recorded. However, due to the Company's history of net operating losses and its current financial condition, a valuation allowance has been recorded which offsets the entire net deferred tax asset. A summary of the Company's net deferred tax asset is as follows (in millions):
December 31 --------------- 1994 1993 ------ ------
Deferred tax asset................................... $ 240 $ 208 Deferred tax liability............................... -- (1) Valuation allowance.................................. (240) (207) ------ ------ Net deferred tax asset.......................... $ -- $ -- ====== ======
The principal components of the Company's net deferred tax asset (utilizing a 39% combined federal and state income tax rate) and the valuation allowance are as follows (in millions):
December 31 --------------- 1994 1993 ------ ------ Tax basis of oil and gas properties in excess of financial basis.......................... $ 80 $ 91 Regular tax net operating loss carryforward.......... 156 114 Other, net........................................... 4 2 Valuation allowance.................................. (240) (207) ------ ------ Net deferred tax asset.......................... $ -- $ -- ====== ======
At December 31, 1994, the Company had a regular tax net operating loss carryforward of approximately $400 million. Additionally, the Company had an alterative minimum tax loss carryforward available to offset future alternative minimum taxable income of approximately $370 million. If not used, these carryforwards will expire between 2007 and 2009.
The Company assumed from the Partnership any tax liabilities or refunds which may arise as a result of any changes to Original Mesa's taxable income or loss for open tax years. During 1993, the Internal Revenue Service (the "IRS") completed two field examinations of the tax returns filed by Original Mesa for the tax years 1984 through 1987. In December 1993 the Company made a payment to the IRS of approximately $13 million, which payment includes interest, in full settlement of all claims for these years. The Company was fully reserved for the additional tax assessment relating to the tax years 1984 through 1987. As of January 1, 1994, there are no remaining open tax years for Original Mesa for federal income tax purposes.
(6) Property Sales ==============
See Notes 2 and 4 for discussion of the proposed sale of the Company's interests in the Hugoton field.
In April 1993 the Company sold a portion of its Rocky Mountain area properties for approximately $7.1 million, after adjustments, and recorded a gain on the sale of approximately $4.1 million. The Company also retained a reversionary interest in the properties under which the Company will receive a 50% net profits interest in the properties after the purchaser has recovered its investment and certain other costs and expenses.
In June 1993 the Company sold its interest in the deep portion of the Hugoton field not owned by HCLP for approximately $19.0 million, after adjustments, and recorded a gain on the sale of approximately $5.5 million.
In June 1992 the Company sold all of its Canadian interests (consisting of overriding royalty interests in producing and nonproducing acreage) for approximately $12 million in cash and recognized an approximate $12 million gain.
(7) Stockholders' Equity ====================
At December 31, 1993, the Company had outstanding 46.5 million shares of common stock and owned a 97.38% interest in its direct subsidiaries; the General Partner owned a 2.62% interest. In January 1994 the remaining general partner interest was converted into common stock. See Note 1 for further discussion of the conversion in 1994 of the remaining general partner interest into common stock of the Company. In the second quarter of 1994 the Company completed the Equity Offering (see Note 4) which resulted in the issuance of an additional 16.3 million shares of common stock. Proceeds from the Equity Offering increased stockholders' equity by approximately $93 million and were used to reduce long-term debt. At December 31, 1994, the Company had outstanding 64.1 million shares of common stock.
The Company has authorized 10 million shares of preferred stock. No shares of preferred stock have been issued as of December 31, 1994.
(8) Notes Receivable ================
Prior to 1992 the Company had notes receivable totaling $68 million, exclusive of interest, from Bicoastal Corporation ("Bicoastal") which was in bankruptcy. Because of the uncertainty of collection, the Company did not record interest on these notes. A plan of reorganization for Bicoastal was approved by the Bankruptcy Court in September 1992. During 1992 and 1993, the Company collected approximately $28 million and $46 million, respectively, from Bicoastal, representing all of the Company's principal amount of allowed claims in the bankruptcy reorganization plan, plus an additional amount representing a portion of its interest claims. As a result, the Company recorded gains of $18.5 million in 1993 relating to collections in excess of the recorded receivable. In 1994 the Company recorded gains of $16.6 million from additional interest claims collected from Bicoastal.
(9) Contingencies =============
Masterson ---------
In February 1992 the current lessors of an oil and gas lease (the "Gas Lease") dated April 30, 1955, between R. B. Masterson, et al., as lessor, and Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in Federal District Court in Amarillo, Texas, claiming that CIG had underpaid royalties due under the Gas Lease. The Company owns an interest in the Gas Lease. The plaintiffs, in their Second Amended Complaint, included the Company as a defendant. The plaintiffs allege that the underpayment was the result of CIG's use of an improper gas sales price upon which to calculate royalties and that the proper price should have been determined pursuant to a "favored nations" clause in a July 1, 1967 amendment to the Gas Lease (the "Gas Lease Amendment"). The plaintiffs also sought a declaration by the court as to the proper price to be used for calculating future royalties.
In August 1992 CIG filed a third-party complaint against the Company for any such royalty underpayments which may be allocable to the Company's interest in the Gas Lease.
The plaintiffs subsequently dismissed their claims against the Company for reasons relating to the jurisdiction of the federal court; however, the third-party complaint by CIG against the Company is not affected by the dismissal.
The plaintiffs allege royalty underpayments of approximately $500 million (including interest at 10%) covering the period July 1, 1967 to the present. In addition, the plaintiffs seek exemplary damages. Management believes that the Company has several defenses to the plaintiffs' claims, including (i) that the royalties for all periods were properly computed and paid, (ii) that plaintiffs' claims with respect to all periods prior to October 1, 1989 (which appear to account for approximately $400 million of the claims) were explicitly released by a 1988 written settlement agreement among plaintiffs, CIG and the Company and are further barred by the statute of limitations, and (iii) that from October 1, 1988 and thereafter the "favored nations" clause was suspended and that "in lieu of" such "favored nations" clause, CIG and the Company would pay royalties based upon the Federal Energy Regulatory Commission rate or market value rate set forth in the 1988 royalty agreements.
In March 1995 the court ruled (1) that all claims for royalty underpayments for the periods prior to October 1, 1989, were released by the plaintiffs in the 1988 settlement agreement, (2) plaintiffs are not entitled to exemplary damages, and (3) that the "favored nations" clause in the Gas Lease Amendment has not been eliminated or suspended by the "in lieu of" provision to the 1988 royalty agreements. The court has also made certain other rulings adverse to the defendants covering certain other defenses. The Company and CIG have filed stipulations with the court whereby the Company will be liable for between 50% and 60%, depending upon the time period covered, of any adverse judgment against CIG for post-February 1988 underpayment of royalties, if any, depending upon the time period covered by an adverse judgment against CIG. The court's rulings have eliminated approximately $400 million of the plaintiff's original $500 million of claims but have also reduced a number of CIG's and the Company's defenses. The trial began March 22, 1995.
See Note 2 for a discussion of the potential effect on the Company of an adverse decision in this lawsuit.
Preference Unitholders ----------------------
The Company is a defendant in lawsuits related to the Corporate Conversion filed in the U.S. District Court for the Northern District of Texas--Dallas Division. Plaintiffs allege, among other things, that (i) the proxy materials delivered to unitholders in connection with the Corporate Conversion contained material misstatements and omissions, (ii) the General Partner of the Partnership breached fiduciary duties to the preference unitholders in structuring the transaction and allocating the common stock of the Company and (iii) the Corporate Conversion was implemented in breach of the partnership agreement of the Partnership because defendants allegedly did not obtain the requisite opinion of independent counsel regarding certain tax effects of the transaction. The Company and the other defendants have denied the allegations and believe they are without merit. Plaintiffs seek a declaration declaring the Corporate Conversion void and rescinding it, an order requiring payment of $164 million to the former preference unitholders in respect of the preferential distribution rights of their units, unspecified compensatory and punitive damages and other relief.
On August 12, 1994, the Court entered an order denying plaintiff's motion for a summary judgment and granted the Company's motion for a summary judgment. A final judgment was entered dismissing the case. A notice of appeal was filed August 19, 1994, by plaintiffs. Oral arguments in the case have been scheduled before the Fifth Circuit Court of Appeals in May 1995.
The Company does not expect the resolution of this lawsuit to have a material adverse effect on its financial position or results of operations.
Unocal ------
The Company was subject to a lawsuit relating to a 1985 investment in Unocal which asserted that certain profits allegedly realized by the Company and other defendants upon the disposition of Unocal common stock in 1985 were recoverable by Unocal pursuant to Section 16(b) of the Securities Exchange Act of 1934. On January 11, 1994, the Company and the other defendants entered into a settlement agreement (the "Settlement Agreement") whereby they agreed to pay Unocal an aggregate of $47.5 million, of which $42.75 million was to be paid by the Company and $4.75 million by the other defendants. The Settlement Agreement was approved by the court on February 28, 1994. The Company funded its share of the settlement amount with proceeds from issuance of additional long-term debt. (See Note 4 for discussion of the issuance of the additional long-term debt.)
As a result of the settlement, the Company recognized a $42.8 million loss in the fourth quarter of 1993.
Other -----
The Company is also a defendant in other lawsuits and has assumed liabilities relating to Original Mesa and the Partnership. The Company does not expect the resolution of these other matters to have a material adverse effect on its financial position or results of operations.
(10) Employee Benefit Plans ======================
Retirement Plans ----------------
The Company maintains two defined contribution retirement plans for the benefit of its employees. The Company expensed $3.3 million in 1994, $3.2 million in 1993, and $3.3 million in 1992 in connection with these plans.
Option Plan -----------
In December 1991 the stockholders of the Company approved the 1991 Stock Option Plan of the Company (the "Option Plan"), which authorized the grant of options to purchase up to two million shares of common stock to officers and key employees. In May 1994 the stockholders of the Company approved an amendment to the Option Plan which increased the number of shares of common stock authorized from two million to four million. The exercise price for each share of common stock placed under option cannot be less than 100% of the fair market value of the common stock on the date the option is granted. Upon exercise, the grantee may elect to receive either shares of common stock or, at the discretion of the Option Committee of the Board of Directors, cash or certain combinations of stock and cash in an amount equal to the excess of the fair market value of the common stock at the time of exercise over the exercise price. At December 31, 1994, the following stock options were outstanding:
Number of Options ---------
Outstanding at December 31, 1993............................ 1,933,050 Granted................................................ 1,075,000 Exercised.............................................. (41,720) Forfeited.............................................. (39,870) --------- Outstanding at December 31, 1994............................ 2,926,460 =========
The outstanding options at December 31, 1994, are detailed as follows:
Number of Date of Exercise Price Options Grant Per Share Exercisable --------- -------- -------------- -----------
1,126,000................... 01/10/92 $ 6.8125 900,800 142,500................... 10/02/92 11.6875 114,000 107,960................... 05/18/93 5.8125 59,378 475,000................... 11/10/93 7.3750 261,250 75,000................... 06/06/94 6.1875 22,500 1,000,000................... 12/01/94 4.2500 -- --------- --------- 2,926,460 1,357,928 ========= =========
Options are exercisable from the date of grant as follows: after six months, 30%; after one year, 55%; after two years, 80%; and after three years, 100%. At December 31, 1994, options for 1,010,820 shares were available for grant.
Postretirement Benefits -----------------------
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which requires that the costs of such benefits be recorded over the periods of employee service to which they relate. For the Company, this standard primarily applies to postretirement medical benefits for retired and current employees. The liability for benefits existing at the date of adoption (the "Transition Obligation") will be amortized over the remaining life of the retirees or 20 years, whichever is shorter.
The Company maintains two separate plans for providing postretirement medical benefits. One plan covers the Company's retirees and current employees (the "Mesa Plan"). The other plan relates to the retirees of Pioneer Corporation ("Pioneer") which was acquired by the Company in 1986 (the "Pioneer Plan"). Under the Mesa Plan, employees who retire from the Company and who have had at least ten years of service with the Company after attaining age 45 are eligible for postretirement health care benefits. These benefits may be subject to deductibles, copayment provisions, retiree contributions and other limitations and the Company has reserved the right to change the provisions of the plan. The Pioneer Plan is maintained for Pioneer retirees and dependents only and is subject to deductibles, copayment provisions and certain maximum payment provisions. The Company does not have the right to change the Pioneer Plan or to require retiree contributions. Both plans are self-insured indemnity plans and both coordinate benefits with Medicare as the primary payer. Neither plan is funded.
The following table reconciles the status of the two plans with the amount included under other liabilities in the consolidated balance sheet at December 31, 1994, (in thousands):
Mesa Pioneer Plan Plan Total ------ ------- ------- Accumulated Postretirement Benefit Obligation ("APBO"): Retirees and dependents............ $ 983 $11,347 $12,330 Actives - fully eligible........... 327 -- 327 Other actives...................... 588 -- 588 ------ ------- ------- Total APBO.................... 1,898 11,347 13,245 Unrecognized Transition Obligation...... (1,503) (2,503) (4,006) ------ ------- ------- Accrued Postretirement Benefit Obligation.................... $ 395 $ 8,844(a) $ 9,239 ====== ======= =======
---------- (a) The Company established an accrued liability associated with the Pioneer Plan in conjunction with its acquisition of Pioneer in 1986.
For measurement purposes, the 1994 annual rate of increase in per capita cost of covered health care benefits was assumed to be 11% for those participants under age 65 and 10% for those participants over age 65. The rates were assumed to decrease gradually to 5.0% by the year 2000 and to remain at that level thereafter. The health care cost trend rate assumption affects the amount of the Transition Obligation and periodic cost reported. An increase in the assumed health care cost trend rates by 1% in each year would increase the APBO as of December 31, 1994, by approximately $735,000 and the net periodic postretirement benefit cost for the year ended December 31, 1994, by approximately $77,000. The net periodic postretirement benefit cost for the year ended December 31, 1994, was approximately $1.4 million based on the assumptions used.
The discount rate used in determining the APBO as of December 31, 1994, was 8%.
The following table presents the Company's cost of postretirement benefits other than pensions for the years ended December 31 (in thousands):
1994 1993 1992 ------ ------ ------ Net periodic postretirement benefit cost: Service cost............................ $ 110 $ 96 $ -- Interest cost........................... 988 988 -- Amortization of Transition Obligation... 276 276 -- ------ ------ ------ $1,374 $1,360 $ -- (a) ====== ====== ====== Actual costs of providing benefits: Mesa Plan(b)............................ $ 120 $ 123 $ 205 Pioneer Plan(c)......................... 666 909 1,356 ------ ------ ------ $ 786 $1,032 $1,561 ====== ====== ====== ---------- (a) SFAS No. 106 was adopted effective January 1, 1993.
(b) Actual costs of providing benefits in 1992 under the Mesa Plan were recorded to expense in the consolidated statements of operations. Actual costs of providing benefits in 1993 and 1994 under the Mesa Plan were applied as incurred against the accrued postretirement benefit obligation.
(c) Actual costs of providing benefits in 1992 under the Pioneer Plan were applied as incurred against the previously accrued liability. Actual costs of providing benefits in 1993 and 1994 under the Pioneer Plan were applied as incurred against the accrued postretirement benefit obligation.
Deferred Compensation ---------------------
The Company had agreements with two officers to provide postretirement deferred compensation at a rate of one-half of the participant's final rate of compensation (subject to minimum amounts specified in the agreements) for a period of ten years following the date of retirement or death. In 1992 in order to terminate the deferred compensation agreements, the Company established life insurance plans, executed agreements with the two officers and purchased insurance policies at an aggregate cost of $4.9 million. At the time they were terminated, approximately $3.9 million had been accrued under the deferred compensation agreements. The Company fully funded the life insurance policies and has no further obligations under such policies or under the deferred compensation agreements.
(11) Major Customers ===============
In 1994 revenues include sales to Mapco Oil and Gas Company ("Mapco") of $70.9 million (31.4%), Western Resources, Inc. ("WRI") of $37.4 million (16.6%), and Energas Company ("Energas") of $22.8 million (10.1%). In 1993 revenues included sales to Mapco of $60.2 million (27.5%), WRI of $51.8 million (23.6%) and Natural Gas Clearinghouse of $23.1 million (10.5%). In 1992 revenues included sales to Mapco of $45.7 million (19.4%), WRI of $39.7 million (16.8%) and Energas of $23.7 million (10.0%).
(12) Concentrations of Credit Risk =============================
Substantially all of the Company's accounts receivable at December 31, 1994, result from oil and gas sales and joint interest billings to third party companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred by the Company on receivables have not been significant.
(13) Condensed Consolidating Financial Statements ============================================
The Company conducts its operations through various direct and indirect subsidiaries. On December 31, 1994, the Company's direct subsidiaries were MOC, Mesa Holding Co. ("MHC") and Hugoton Management Co. ("HMC"). MOC owns all of the Company's interest in the West Panhandle field of Texas, the Gulf Coast and the Rocky Mountain areas, as well as an approximate 99% limited partnership interest in HCLP. MHC owns cash and securities, an approximate 1% limited partnership interest in HCLP and 100% of MESA Environmental Ventures Co. ("Mesa Environmental"), a company established to compete in the natural gas vehicle market. HMC owns the general partner interest of HCLP. See discussion below for 1994 changes in subsidiaries and HCLP ownership. HCLP owns substantially all of the Company's Hugoton field natural gas properties and is liable for the HCLP Secured Notes (see Note 4). The assets and cash flows of HCLP that are subject to the mortgage securing the HCLP Secured Notes are dedicated to service the HCLP Secured Notes and are not available to pay creditors of the Company or its subsidiaries other than HCLP. MOC and the Company are liable for the Credit Agreement, the 13-1/2% subordinated notes and the Discount Notes. Mesa Capital Corp. ("Mesa Capital"), a wholly owned financing subsidiary of MOC, is also an obligor under the 13-1/2% subordinated notes and the Discount Notes. Mesa Capital, which has insignificant assets and results of operations, is included with MOC in the condensed consolidating financial statements. Other Company subsidiaries in the condensed consolidating financial statements include MHC, HMC, and Mesa Environmental.
In early 1994 the Company effected a series of merger transactions which resulted in the conversion of the predecessors of MOC, MHC, and the other subsidiary partnerships, other than HCLP, to corporate form and eliminated all of the General Partner's minority interests in the subsidiaries.
As of December 31, 1993, MHC had intercompany payables to MOC of approximately $123 million. On February 28, 1994, MHC assigned an 18% limited partnership interest in HCLP (out of its total interest of approximately 19%) to MOC in satisfaction of $90 million of intercompany payables. Provisions of the Discount Note indentures required the repayment of intercompany indebtedness to specified levels and provided that any HCLP limited partnership interests transferred in satisfaction of intercompany debt would be valued at $5 million for each one percent of interest assigned. MHC has also repaid an additional $33 million of intercompany debt to MOC in cash during 1994. As a result of these transactions, MOC now owns 99% of the limited partnership interest in HCLP, and all of MHC's intercompany debt to MOC which was outstanding at December 31, 1993, has been eliminated.
The following are condensed consolidating financial statements of MESA Inc., HCLP, MOC, and the Company's other direct and indirect subsidiaries combined (in millions):
Condensed Consolidating Balance Sheets -------------------------------------- Other Consol. The MESA Company and Company December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Assets: Cash and cash investments....... $ - $ 50 $ 24 $ 70 $ - $ 144 Other current assets............ - 16 39 6 - 61 ------ ------ ------ ------ ------ ------ Total current assets.......... - 66 63 76 - 205 ------ ------ ------ ------ ------ ------ Property, plant and equipment, net............... - 626 503 1 - 1,130 Investment in subsidiaries...... 134 - 126 10 (270) - Intercompany receivables....... - - 9 - (9) - Other noncurrent assets............ - 88 58 3 - 149 ------ ------ ------ ------ ------ ------ $ 134 $ 780 $ 759 $ 90 $ (279) $1,484 ====== ====== ====== ====== ====== ====== Liabilities and Equity: Current liabilities....... $ - $ 47 $ 41 $ 1 $ - $ 89 Long-term debt..... - 505 688 - - 1,193 Intercompany payables.......... 9 - - - (9) - Other noncurrent liabilities....... - - 73 4 - 77 Partners'/Stock- holders' equity (deficit)......... 125 228 (43) 85 (270) 125 ------ ------ ------ ------ ------ ------ $ 134 $ 780 $ 759 $ 90 $ (279) $1,484 ====== ====== ====== ====== ====== ======
Other Consol. The MESA Company and Company December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Assets: Cash and cash investments....... $ - $ 40 $ 16 $ 83 $ - $ 139 Other current assets............ - 23 22 12 - 57 ------ ------ ------ ------ ------ ------ Total current assets.......... - 63 38 95 - 196 ------ ------ ------ ------ ------ ------ Property, plant and equipment, net............... - 656 535 1 - 1,192 Investment in subsidiaries...... 121 - 44 189 (354) - Intercompany receivables....... - - 113 - (113) - Other noncurrent assets............ - 87 55 3 - 145 ------ ------ ------ ------ ------ ------ $ 121 $ 806 $ 785 $ 288 $ (467) $1,533 ====== ====== ====== ====== ====== ====== Liabilities and Equity: Current liabilities....... $ - $ 73 $ 46 $ 1 $ - $ 120 Long-term debt..... - 499 675 - - 1,174 Intercompany payables.......... 9 - - 123 (132) - Other noncurrent liabilities....... - - 120 4 3 127 Partners'/Stock- holders' equity (deficit)......... 112 234 (56) 160 (338) 112 ------ ------ ------ ------ ------ ------ $ 121 $ 806 $ 785 $ 288 $ (467) $1,533 ====== ====== ====== ====== ====== ======
Condensed Consolidating Statements of Operations ------------------------------------------------ Years Ended: ------------ Other Consol. The MESA Company and Company December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 113 $ 116 $ - $ - $ 229 ------ ------ ------ ------ ------ ------ Costs and Expenses: Operating, exploration and taxes............. - 30 49 - - 79 General and administrative.... - - 26 3 - 29 Depreciation, depletion and amortization...... - 37 55 - - 92 ------ ------ ------ ------ ------ ------ - 67 130 3 - 200 ------ ------ ------ ------ ------ ------
Operating Income (Loss).............. - 46 (14) (3) - 29 ------ ------ ------ ------ ------ ------ Interest expense, net of interest income.. - (47) (87) 3 - (131) Losses on dispositions of oil and gas properties.......... - - - (91)(d) 91 - Equity in loss of subsidiaries........ (83) - (1) - 84 - Other................ - - 22 15 (18) 19 ------ ------ ------ ------ ------ ------ Net Loss............. $ (83) $ (1) $ (80) $ (76) $ 157 $ (83) ====== ====== ====== ====== ====== ======
Other Consol. The MESA Company and Company December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 103 $ 120 $ (1) $ - $ 222 ------ ------ ------ ------ ------ ------ Costs and Expenses: Operating, exploration and taxes............. - 27 48 - - 75 General and administrative.... - - 23 2 - 25 Depreciation, depletion and amortization...... - 35 65 - - 100 ------ ------ ------ ------ ------ ------ - 62 136 2 - 200 ------ ------ ------ ------ ------ ------
Operating Income (Loss).............. - 41 (16) (3) - 22 ------ ------ ------ ------ ------ ------ Interest expense, net of interest income.. - (50) (83) 2 - (131) Intercompany interest income (expense).... - - 16 (16) - - Gains on dispositions of oil and gas properties.......... - - 10 - - 10 Equity in loss of subsidiaries........ (102) - (7) (2) 111 - Other................ - - (42) 29 10 (3) ------ ------ ------ ------ ------ ------ Net Income (Loss).... $ (102) $ (9) $ (122) $ 10 $ 121 $ (102) ====== ====== ====== ====== ====== ======
Other Consol. The MESA Company and Company December 31, 1992 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 88 $ 149 $ - $ - $ 237 ------ ------ ------ ------ ------ ------ Costs and Expenses: Operating, exploration and taxes............. - 22 51 - - 73 General and administrative.... - - 24 - - 24 Depreciation, depletion and amortization...... - 34 80 - - 114 ------ ------ ------ ------ ------ ------ - 56 155 - - 211 ------ ------ ------ ------ ------ ------ Operating Income (Loss).............. - 32 (6) - - 26 ------ ------ ------ ------ ------ ------ Interest expense, net of interest income.. - (52) (80) 2 - (130) Intercompany interest income (expense).... - - 18 (18) - - Gains of dispositions of oil and gas properties.......... - - 12 - - 12 Equity in loss of subsidiaries........ (87) - (16) (4) 107 - Other................ (2) - (21) 9 17 3 ------ ------ ------ ------ ------ ------ Net Loss............. $ (89) $ (20) $ (93) $ (11) $ 124 $ (89) ====== ====== ====== ====== ====== ======
Condensed Consolidating Statements of Cash Flows ------------------------------------------------ Years Ended: ------------ Other Consol. The MESA Company and Company December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from Operating Activities $ - $ 41 $ (15) $ 23 $ - $ 49 ------ ------ ------ ------ ------ ------ Cash Flows from Investing Activities: Capital expenditures...... - (7) (26) - - (33) Contributions to subsidiaries...... (93) - (5) (1) 99 - Distributions from subsidiaries...... - - 10 - (10) - Other.............. - - 28 (2) (33) (7) ------ ------ ------ ------ ------ ------ (93) (7) 7 (3) 56 (40) ------ ------ ------ ------ ------ ------ Cash Flows from Financing Activities: Issuance of common stock...... 93 - - - - 93 Repayments of long-term debt.... - (21) (154) - - (175) Long-term borrowings........ - - 78 - - 78 Contributions from equity holders.... - 6 93 - (99) - Distribution to partners.......... - (10) - - 10 - Other.............. - 1 (1) (33) 33 - ------ ------ ------ ------ ------ ------ 93 (24) 16 (33) (56) (4) ------ ------ ------ ------ ------ ------ Net Increase (Decrease) in Cash and Cash Investments......... $ - $ 10 $ 8 $ (13) $ - $ 5 ====== ====== ====== ====== ====== ======
Other Consol. The MESA Company and Company December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from Operating Activities $ - $ 21 $ 16 $ (4) $ - $ 33 ------ ------ ------ ------ ------ ------ Cash Flows from Investing Activities: Capital expenditures...... - (8) (21) (1) - (30) Proceeds from dispositions of oil and gas properties........ - - 26 - - 26 Other.............. - - 30 46 (35) 41 ------ ------ ------ ------ ------ ------ - (8) 35 45 (35) 37 ------ ------ ------ ------ ------ ------ Cash Flows from Financing Activities: Repayments of long-term debt.... - (39) (41) - - (80) Other.............. - 2 (10) (35) 35 (8) ------ ------ ------ ------ ------ ------ - (37) (51) (35) 35 (88) ------ ------ ------ ------ ------ ------ Net Increase (Decrease) in Cash and Cash Investments......... $ - $ (24) $ - $ 6 $ - $ (18) ====== ====== ====== ====== ====== ======
Other Consol. The MESA Company and Company December 31, 1992 Inc. HCLP MOC Subs. Elimin. Consol'd ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from Operating Activities $ - $ 16 $ (52) $ 32 $ - $ (4) ------ ------ ------ ------ ------ ------ Cash Flows from Investing Activities: Capital expenditures...... - (3) (66) - - (69) Proceeds from dispositions of oil and gas properties........ - - 11 - - 11 Contributions to subsidiaries...... - - (25) (7) 32 - Other.............. - - 23 25 (31) 17 ------ ------ ------ ------ ------ ------ - (3) (57) 18 1 (41) ------ ------ ------ ------ ------ ------ Cash Flows from Financing Activities: Repayments of long-term debt.... - (25) - - - (25) Contributions from equity holders.... - 32 - - (32) - Other.............. - (1) (1) (34) 31 (5) ------ ------ ------ ------ ------ ------ - 6 (1) (34) (1) (30) ------ ------ ------ ------ ------ ------ Net Increase (Decrease) in Cash and Cash Investments......... $ - $ 19 $ (110) $ 16 $ - $ (75) ====== ====== ====== ====== ====== ======
Notes to Condensed Consolidating Financial Statements -----------------------------------------------------
(a) These condensed consolidating financial statements should be read in conjunction with the consolidated financial statements of the Company and notes thereto of which this note is an integral part.
(b) As of December 31, 1994, the Company owns 100% interest in each of MOC, MHC, and HMC. These condensed consolidating financial statements present the Company's investment in its subsidiaries and MOC's and MHC's investments in HCLP using the equity method. Under this method, investments are recorded at cost and adjusted for the parent company's ownership share of the subsidiary's cumulative results of operations. In addition, investments increase in the amount of contributions to subsidiaries and decrease in the amount of distributions from subsidiaries.
(c) The consolidation and elimination entries (i) eliminate the equity method investment in subsidiaries and equity in income (loss) of subsidiaries, (ii) eliminate the intercompany payables and receivables, (iii) eliminate other transactions between subsidiaries including contributions and distributions, and (iv) establish the General Partner's minority interest in the consolidated results of operations and financial position of the Company.
(d) The condensed consolidating statement of operations of MHC for the year ended December 31, 1994, reflects a $91 million loss from its disposition of an 18% equity interest in HCLP. The HCLP interest was used to repay a portion of MHC's intercompany payable to MOC and was valued, in accordance with the provisions of the Discount Note indentures, at $5 million for each one percent of interest assigned. A loss was recognized for the difference between the carrying value of the HCLP interest assigned to MOC and the $90 million value attributed to such interests which reduced the intercompany payable. The loss recognized by MHC is eliminated in consolidation.
SUPPLEMENTAL FINANCIAL DATA ===========================
Oil and Gas Reserves and Cost Information ----------------------------------------- (Unaudited)
Net proved oil and gas reserves as of December 31, 1994, were estimated by Company engineers. Net proved oil and gas reserves as of December 31, 1993 and 1992, associated with the Company s two most significant natural gas producing fields were estimated by independent petroleum engineering consultants. These two fields, the Hugoton and West Panhandle fields, represented over 95% of the Company s net proved equivalent natural gas reserves as of the dates estimated by the independent petroleum engineers. All of the Company s reserves at December 31, 1994, 1993, and 1992, were in the United States. In accordance with regulations established by the Commission, the reserve estimates were based on economic and operating conditions existing at the end of the respective years.
Future prices for natural gas were based on market prices as of each year end and contract terms, including fixed and determinable price escalations. Market prices as of each year end were used for future sales of oil, condensate and natural gas liquids. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year end, with no escalation.
Over 70% of the Company's equivalent proved reserves (based on a factor of six thousand cubic feet ["Mcf"] of gas per barrel of liquids) at December 31, 1994, are natural gas. The natural gas prices in effect at December 31, 1994, (having a weighted average of $1.66 per Mcf) were used in accordance with Commission regulations but may not be the most appropriate or representative prices to use for estimating reserves since such prices were influenced by the seasonal demand for natural gas and contractual arrangements at that date. The average price received by the Company for sales of natural gas in 1994 was $1.66 per Mcf. Assuming all other variables used in the calculation of reserve data are held constant, the Company estimates that each $.10 change in the price per Mcf for natural gas production would affect the Company's estimated future net cash flows and present value thereof, both before income taxes, by $119 million and $51 million, respectively. At December 31, 1994, the Company's standardized measure of future net cash flows from proved reserves (the "Standardized Measure") and the pretax Standardized Measure were less than the net book value of oil and gas properties by approximately $180 million and $126 million, respectively. The Company believes that the ultimate value to be received for production from its oil and gas properties will be greater than the current net book value of its oil and gas properties.
At December 31, 1993 and 1992, the Company's internal estimates of proved reserves for the Hugoton and West Panhandle properties were greater than the estimates prepared by independent petroleum engineers as of such dates. The Company's proved reserve estimates as of December 31, 1994, for the Hugoton and West Panhandle fields are approximately 241 Bcfe greater than the reserves reported at December 31, 1993, adjusted for 1994 production, for the same properties. In the Hugoton field, the primary difference reflects increased reserves for properties on which the Company drilled 381 infill wells since 1987 resulting from the Company's internal interpretation of pressure and cumulative production data. In the West Panhandle field, the reserve differences result from the interpretation of cumulative production data on producing wells and in the estimates of proved undeveloped reserves. The Company operates the producing wells and the natural gas processing plants on each of these properties and, based on its knowledge of the properties, believes that its proved reserve estimates are more reflective of future production than those estimates previously reported by independent petroleum engineers.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Estimates prepared by other engineers might be materially different from those set forth herein. Moreover, the Standardized Measure should not be construed as the current market value of the proved oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (i) anticipated future changes in oil and gas prices, and production and development costs; (ii) an allowance for return on investment; (iii) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities; and (iv) other business risks.
Capitalized Costs and Costs Incurred ------------------------------------ (Unaudited)
Capitalized costs relating to oil and gas producing activities at December 31, 1994, 1993, and 1992 and the costs incurred during the years then ended are set forth below (in thousands):
1994 1993 1992 ---------- ---------- ---------- Capitalized Costs: Proved properties................ $1,865,004 $1,845,483 $1,850,793 Unproved properties.............. 2,838 754 762 Accumulated depreciation, depletion and amortization..... (753,827) (670,706) (589,720) ---------- ---------- ---------- Net......................... $1,114,015 $1,175,531 $1,261,835 ========== ========== ========== Costs Incurred: Exploration and development: Proved properties........... $ 523 $ 73 $ 64 Unproved properties......... 2,425 17 63 Exploration costs........... 5,157 2,705 15,157 Development costs........... 14,043 2,381 6,911 ---------- ---------- ---------- Total exploration and development.......... 22,148 5,176 22,195 ---------- ---------- ---------- Plants and facilities: Processing plants........... 3,248 17,501 44,716 Field compression facilities 3,129 4,387 1,509 Other....................... 5,168 2,257 3,301 ---------- ---------- ---------- Total plants and facilities........... 11,545 24,145 49,526 ---------- ---------- ---------- Total costs incurred............. $ 33,693 $ 29,321 $ 71,721 ========== ========== ==========
Depreciation, depletion and amortization............... $ 89,413 $ 96,774 $ 110,340 ========== ========== ==========
Estimated Quantities of Reserves -------------------------------- (Unaudited) Years Ended December 31 ------------------------------------ Natural Gas (MMcf) 1994 1993 1992 ----------- ---------- ---------- ----------
Proved Reserves: Beginning of year................ 1,202,444 1,276,049 1,367,968 Extensions and discoveries.. 6,211 5,132 37,100 Purchases of producing properties................ 822 166 583 Revisions of previous estimates................. 176,049 7,284 (24,462) Sales of producing properties................ - (6,367) (15,613) Production.................. (82,339) (79,820) (89,527) ---------- ---------- ---------- End of year...................... 1,303,187 1,202,444 1,276,049 ========== ========== ========== Proved Developed Reserves: Beginning of year................ 1,159,453 1,223,672 1,338,856 ========== ========== ========== End of year...................... 1,257,883 1,159,453 1,223,672 ========== ========== ==========
Years Ended December 31 Natural Gas Liquids, Oil ------------------------------------ and Condensate (MBbls) 1994 1993 1992 ------------------------ ---------- ---------- ----------
Proved Reserves: Beginning of year................ 82,446 87,392 83,225 Extensions and discoveries.. 491 778 7,591 Purchases of producing properties................ 1 - 9 Revisions of previous estimates................. 13,947 3,083 3,028 Sales of producing properties................ - (3,019) (637) Production.................. (7,457) (5,788) (5,824) ---------- ---------- ---------- End of year...................... 89,428 82,446 87,392 ========== ========== ========== Proved Developed Reserves: Beginning of year................ 79,294 82,439 82,406 ========== ========== ========== End of year...................... 85,656 79,294 82,439 ========== ========== ==========
* Proved natural gas liquids, oil and condensate reserve quantities include oil and condensate reserves at December 31 of the respective years as follows: 1994, 5,031 MBbls; 1993, 3,296 MBbls; and 1992, 7,268 MBbls.
* In addition to the proved reserves disclosed above, the Company owned proved helium and carbon dioxide ("CO2") reserves at December 31 of the respective years as follows: 1994, 4,457 MMcf of helium and 46,459 MMcf of CO2; 1993, 5,198 MMcf of helium and 46,376 MMcf of CO2; and 1992, 5,634 MMcf of helium and 46,457 MMcf of CO2.
Standardized Measure of Future Net Cash Flows from Proved Reserves ------------------------------------------------------------------ (Unaudited) December 31 ------------------------------------ 1994 1993 1992 ---------- ---------- ---------- (in thousands)
Future cash inflows................... $3,513,282 $3,723,760 $3,802,614 Future production and development costs: Operating costs and production taxes............... (1,192,005) (1,337,224) (1,271,799) Development and abandonment costs.............. (95,441) (80,310) (122,860) Future income taxes................... (211,076) (240,017) (302,492) ---------- ---------- ---------- Future net cash flows................. 2,014,760 2,066,209 2,105,463 Discount at 10% per annum........ (1,080,578) (1,079,278) (1,068,282) ---------- ---------- ---------- Standardized Measure.................. $ 934,182 $ 986,931 $1,037,181 ========== ========== ========== Future net cash flows before income taxes................. $2,225,836 $2,306,226 $2,407,955 ========== ========== ========== Standardized Measure before income taxes................. $ 988,325 $1,068,740 $1,167,694 ========== ========== ========== ---------- * The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses.
Changes in Standardized Measure ------------------------------- (Unaudited) Years Ended December 31 ------------------------------------ 1994 1993 1992 ---------- ---------- ---------- (in thousands)
Standardized Measure at beginning of year................... $ 986,931 $1,037,181 $ 995,214 ---------- ---------- ---------- Revisions of reserves proved in prior years: Changes in prices and production costs............... (121,300) 6,178 (77,527) Changes in quantity estimates.... 151,538 17,616 (3,995) Changes in estimates of future development and abandonment costs.............. (27,343) 8,054 (2,468) Net change in income taxes....... 27,666 48,703 55,287 Accretion of discount............ 106,874 116,769 118,101 Other, primarily timing of production.................. (80,650) (108,371) 12,687 ---------- ---------- ---------- Total revisions............. 56,785 88,949 102,085 Extensions, discoveries and other additions, net of future production and development costs.... 8,075 4,456 65,737 Purchases of proved properties........ 463 138 457 Sales of oil and gas produced, net of production costs............. (146,267) (143,502) (173,552) Sales of producing properties......... - (26,907) (14,473) Previously estimated development and abandonment costs incurred during the period................... 28,195 26,616 61,713 ---------- ---------- ---------- Net changes in Standardized Measure... (52,749) (50,250) 41,967 ---------- ---------- ---------- Standardized Measure at end of year... $ 934,182 $ 986,931 $1,037,181 ========== ========== ==========
Quarterly Results ----------------- (Unaudited) Quarters Ended(2) ------------------------------------------------- March 31 June 30 September 30 December 31 -------- -------- ------------ ----------- (in thousands, except per share data) 1994: ---- Revenues............ $ 61,084 $ 53,361 $ 45,725 $ 68,567 ======== ======== ======== ======== Gross profit(1)..... $ 42,214 $ 34,462 $ 28,713 $ 49,387 ======== ======== ======== ======== Operating income (loss)............ $ 10,176 $ 4,867 $ (2,065) $ 15,705 ======== ======== ======== ======== Net loss............ $(17,766) $(25,338) $(25,907) $(14,342) ======== ======== ======== ======== Net loss per common share...... $ (.37) $ (.43) $ (.40) $ (.22) ======== ======== ======== ======== 1993: ---- Revenues............ $ 63,826 $ 50,826 $ 42,377 $ 65,175 ======== ======== ======== ======== Gross profit(1)..... $ 44,644 $ 32,009 $ 26,782 $ 46,618 ======== ======== ======== ======== Operating income (loss)............ $ 10,032 $ 4,904 $ (510) $ 7,586 ======== ======== ======== ======== Net loss............ $(17,088) $(14,445) $(27,480) $(43,435) ======== ======== ======== ======== Net loss per common share...... $ (.44) $ (.37) $ (.71) $ (1.06) ======== ======== ======== ========
---------- (1) Gross profit consists of total revenues less lease operating expenses and production and other taxes.
(2) See Notes 5 and 9 to the Company's consolidated financial statements for information on items affecting fourth quarter 1993 results.
INDEX TO EXHIBITS -----------------
Exhibit No. Description ----------- -----------
4.7 Third Amended and Restated Credit Agreement dated as of November 29, 1994, among the Company, Mesa Operating Co., and the Banks named in this Credit Agreement and Societe Generale, Southwest Agency, as Agent.
10.24 Gas Transportation Agreement dated June 14, 1994, between Western Resources, Inc. and Mesa Operating Co., acting on behalf of itself and as agent for Hugoton Capital Limited Partnership.
22 MESA Inc. Subsidiaries
27 Article 5 of Regulation S-X Financial Data Schedule for Year-End 1994 Form 10-K
28 Summary Report of the Company relating to proved oil and gas reserves at December 31, 1994.