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EXHIBIT 28
SUMMARY REPORT
DATED
FEBRUARY 28, 1994
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1993
FROM
CERTAIN PROPERTIES
OWNED BY THE
MESA OPERATING CO.
AND
MESA HOLDING CO.
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SUMMARY REPORT
DATED
FEBRUARY 28, 1994
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1993
FROM
CERTAIN PROPERTIES
OWNED BY THE
MESA OPERATING CO.
AND
MESA HOLDING CO.
MESA Inc. and DeGolyer and MacNaughton have prepared estimates, as of December
31, 1993, of the extent and value of the proved crude oil, condensate, natural
gas liquids, natural gas, helium, and carbon dioxide reserves of certain
properties owned by Mesa Operating Co. (MOC), successor to Mesa Operating
Limited Partnership (MOLP), and Mesa Holding Co. (MHC), successor to Mesa
Midcontinent Limited Partnership (MMLP). MESA Inc., a Texas corporation, is
the sole owner of two subsidiary corporations as of the date hereof. These two
subsidiaries are:
1. MOC, which holds title to most of the appraised
properties and an 98.6 percent interest in Hugoton
Capital Limited Partnership (HCLP); and
2. MHC, which holds .9 percent of HCLP.
Together, MOC and MHC own 99.5 percent of HCLP, which owns most of the
appraised properties in the Hugoton and Panoma fields. Tabulations of reserves
and revenue from the Texas Panhandle properties, all minor properties, and Mesa
Offshore Trust properties included in this report show the interest of MESA
Inc. while tabulations of reserves and revenue from the Hugoton Area and the
Mesa Royalty Trust properties show the collective interests of Hugoton Capital
Limited Partnership hereinafter referred to as "HCLP." On January 5, 1994,
(after the as-of-date of this report), MESA Inc.'s subsidiary limited
partnerships, excluding HCLP, were converted to corporate form and the related
general partner interests were converted to common stock. The properties
appraised are in the four property groups listed below.
Properties Appraised by DeGolyer and MacNaughton
1. Major Properties:
The HCLP Hugoton Area -- Kansas Hugoton and Panoma Fields
The Texas Panhandle -- Contract "B"
The Texas Panhandle -- Other
2. HCLP Share -- Mesa Royalty Trust Properties
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PROPERTIES APPRAISED BY MESA
3. Minor Properties:
The Gulf Coast Area
The Hugoton Area (non-HCLP Royalties)
The Rocky Mountain Area
4. Remaining MESA interests in the Mesa
Offshore Trust Properties.
The HCLP share -- Mesa Royalty Trust Properties are located in the Hugoton and
Panoma fields in Kansas. These properties are burdened by a 10.2986 percent net
royalty interest owned by the Mesa Royalty Trust and a .0057 percent overriding
royalty interest owned by others. The remaining MESA Inc. interests in the Mesa
Offshore Trust Properties consist of the remaining interests of MESA Inc. after
the transfer (effective December 1, 1982) to the Mesa Offshore Royalty
Partnership, a partnership owned 99.99 percent by the Mesa Offshore Trust, of a
90 percent net profits interest in 10 MESA Inc. leases located in the Gulf of
Mexico offshore from Louisiana and Texas.
The reserve estimates are based on a detailed study of MESA Inc.'s properties
and were prepared by the use of standard geological and engineering methods
generally accepted by the petroleum industry. The method or combination of
methods utilized in the analysis of each reservoir was tempered by experience
in the area, quality and completeness of basic data, and production history.
Reserves in this report are expressed as net reserves. Gross reserves are
defined as the total estimated petroleum hydrocarbons remaining to be produced
after December 31, 1993. Net reserves are defined as that portion of the gross
reserves attributable to the interest owned by MESA Inc. after deducting
royalties and other interests owned by others. In making these reserve
estimates, all interest reversions were taken into account.
Values shown herein are expressed in terms of future gross revenue, future net
revenue, and present worth. Future gross revenue is that revenue which will
accrue to the appraised interests from the production and sale of the estimated
net reserves. Future net revenue is calculated by deducting estimated
production taxes, ad valorem taxes, operating expenses, and capital costs from
the future gross revenue. Future income tax expenses were not taken into
account in the preparation of these estimates. Present worth is defined as
future net revenue discounted at a specified arbitrary discount rate compounded
monthly over the expected period of realization. In this report, present worth
values using a discount rate of 10 percent are reported.
Estimates of reserves and future net revenue should be regarded only as
estimates that may change as further production history and additional
information become available. Not only are such reserve and revenue estimates
based on that information which is currently available, but such estimates are
also subject to the uncertainties inherent in the application of judgmental
factors in interpreting such information.
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Data used in the preparation of DeGolyer and MacNaughton's portion of this
report were obtained from records of MESA Inc., from reports filed with the
appropriate regulatory agencies, and from their files. In the preparation of
this report they have relied, without independent verification, upon
information furnished by MESA Inc. with respect to property interests being
appraised, production from such properties, current costs of operation and
development, current prices for production, agreements relating to current and
future operations and sale of production, and various other information and
data that were accepted as represented. DeGolyer and MacNaughton did not
consider it necessary to make a field examination of the physical condition and
operation of the properties which they evaluated.
Data used in the preparation of MESA Inc.'s portion of this report were
obtained from MESA Inc.'s records and from reports filed with the regulatory
agencies of the states or areas in which the properties are located.
The development status shown herein represents the status applicable on
December 31, 1993. In the preparation of the study, data available from wells
drilled on the appraised properties through December 10, 1993 were used in
estimating gross ultimate recovery. Gross production estimated to December 31,
1993, was deducted from gross ultimate recovery to arrive at the estimates of
gross reserves. In most fields, this required that the production rates be
estimated for up to seven months since production data for certain properties
were available only through May 1993.
Reserves and revenue values shown in this report for the HCLP Share - Mesa
Royalty Trust Properties and the Remaining MESA Inc. Interests in the Mesa
Offshore Trust Properties were estimated from projections of reserves and
revenue attributable to the combined HCLP Share and Mesa Royalty Trust
interests or the combined Remaining MESA Inc. and Mesa Offshore Royalty
Partnership interests. Reserves attributable to the trust interests in each of
the royalty trusts were estimated by allocating a portion of the estimated
combined net reserves of each of the property groups based on future net
revenue. The estimated reserves for each of the trusts were subtracted from the
combined net reserves for each trust to arrive at the estimated reserves of
MESA Inc. and HCLP in the trust properties.
Since the reserve volumes attributable to the MESA Inc. interests in the trust
properties are estimated using an allocation of reserves based on estimates of
future revenue, a change in prices or costs will result in changes in the
estimated reserves of MESA Inc. and HCLP.
Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs
under existing economic and operating conditions and assuming continuation of
current regulatory practices using conventional production methods and
equipment. In the analyses of production-decline curves, reserves were
estimated only to the limit of economic rates of production under existing
economic and operating conditions using prices and costs as of the date the
estimate is made, including consideration of changes in existing prices
provided only by
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contractual arrangements but not including escalations based upon future
conditions. The petroleum reserves are classified as follows:
Proved - Reserves that have been proved to a high degree of certainty
by analysis of the producing history of a reservoir and/or by
volumetric analysis of adequate geological and engineering data.
Commercial productivity has been established by actual production,
successful testing, or in certain cases by favorable core analyses and
electrical-log interpretation when the producing characteristics of
the formation are known from nearby fields. Volumetrically, the
structure, areal extent, volume, and characteristics of the reservoir
are well defined by a reasonable interpretation of adequate subsurface
well control and by known continuity of hydrocarbon-saturated material
above known fluid contacts, if any, or above the lowest known
structural occurrence of hydrocarbons.
Developed - Reserves that are recoverable from existing wells with
current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells
producing from present completion intervals with normal operating
methods and expenses. Developed nonproducing reserves are in
reservoirs behind the casing or at minor depths below the producing
zone and are considered proved by production from other wells in the
field, by successful drill-stem tests, or by core analyses from the
particular zones. Nonproducing reserves require only moderate expense
to be brought into production.
Undeveloped - Reserves that are recoverable from additional wells yet
to be drilled.
Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves
requires drilling of additional wells, major deepening of existing
wells, or installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending upon
the extent to which such enhanced recovery methods are in operation. These
reserves are considered to be proved only in cases where a successful
fluid-injection program is in operation, a pilot program indicates successful
fluid injection, or information is available concerning the successful
application of such methods in the same reservoir and it is reasonably certain
that the program will be implemented.
Nonhydrocarbon helium and carbon dioxide reserves were classified using the
same standards as those described in the foregoing definitions of petroleum
reserves. Because
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these two gases are mixed in and produced with the natural gas reserves, the
term gas as used herein applies to all three gases, where appropriate, and the
term natural gas is used to refer to hydrocarbon gas.
Estimates of the net proved reserves of MESA Inc, as of December 31, 1993, are
as follows:
Total
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TOTAL PROVED RESERVES
Natural Gas (MMcf) .............. 1,202,444
Oil and Condensate (Mbbl) ....... 3,296
Natural Gas Liquids (Mbbl) ...... 79,150
Helium (MMcf) ................... 5,198
Carbon Dioxide (MMcf) ........... 46,376
PROVED DEVELOPED RESERVES
Natural Gas (MMcf) .............. 1,159,453
Oil and Condensate (Mbbl) ....... 3,068
Natural Gas Liquids (Mbbl) ...... 76,226
Helium (MMcf) ................... 5,112
Carbon Dioxide (MMcf) ........... 16,225
Significant proved natural gas liquids reserves and helium reserves are
included herein for the recently completed Satanta plant in the Hugoton field
in Kansas. Proved helium reserves also are included for a helium recovery unit
recently added at the Fain gas processing plant in the Panhandle field in
Texas.
Substantial volumes of gas and natural gas liquids reserves are included for
properties owned by MESA Inc. in the Kansas Hugoton field. A state order has
been issued that permits an optional second well on each 640 acre proration
unit (480 acres minimum) in this field. MESA Inc., as the operator, has drilled
or participated in 381 such working interest wells, and projections of reserves
and revenue in this report were based on the assumption that this development
will continue on the MESA Inc. Hugoton properties and be completed in 1995.
MESA Inc. plans to drill or participate in about 20 additional working interest
infill wells in this field. A portion of the reserves included for these wells
would be produced by existing wells if the infill wells are not drilled; only
the estimated incremental portion of reserves to be recovered from the
undrilled infill wells are classified as undeveloped.
Under the Kansas Hugoton field rules in effect on December 31, 1993, MESA Inc.
has reinstated 62 percent of its 34 Bcf of operated remaining wet gas "canceled
allowable underage" and has determined that the remainder, as well as
additional underage on nonoperated leases, can be reinstated at the appropriate
time. Approximately 8 Bcf of this reinstatement has been incorporated in this
report. The underage represents gas
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allowables for previous years that were not produced; this applies primarily to
certain non MESA Inc. Royalty Trust wells (former Tema and other acquisitions).
The rules provide that, after reinstatement, the operator has up to 5 years to
make up this underage in addition to its regular allowables. This report was
prepared using the Hugoton field rules in effect on the "as-of" date, December
31, 1993. New field rules that were issued on February 2, 1994, effective April
1, 1994, were not considered herein.
Production from the Kansas Hugoton field has been curtailed for several years,
but in the last four years has increased by about 25 percent. MESA Inc.
estimates the market for gas from this field will continue to increase by a
total of about 33 percent over the next four years. The estimates of MESA
Inc.'s allowables are based on this estimation of increasing demand.
MESA Inc. also estimates that there is adequate demand for its share of the gas
to allow marketing of the increased gas volumes discussed in the preceding
paragraphs without a material negative impact on its annual average gas price
in this field. These increasing volumes have been included in the rates
projected in this report to the extent that each well is deemed capable by
performance analysis. MESA Inc. has installed 66 portable lateral pipeline and
wellhead compressors in the Kansas Hugoton field to facilitate the production
of these gas volumes. MESA Inc. also is continuing to upgrade the well
gathering system, which improves deliverability of the wells. This increase in
deliverability and the associated costs have been incorporated in the estimates
included herein.
With the exception of a few properties in this report known as the "Texas
Panhandle - Other," the West Panhandle field properties are subject to an
operating agreement with Colorado Interstate Gas Company, hereinafter referred
to as "CIG." The properties subject to this agreement are collectively referred
to as the "B" Contract area. MESA Inc.'s share of the "B" Contract area gas is
processed through MESA Inc.'s Fain gasoline plant in Potter County, Texas, and
is subject to special royalty payments. An agreement effective January 1,
1991, allocates 77 percent of the remaining production from the "B" Contract
properties to MESA Inc. and the remaining 23 percent to CIG. A new helium
recovery unit at the Fain plant began operations in early 1993. CIG receives a
20-percent overriding royalty interest on MESA Inc.'s share of the helium
produced at this plant.
New agreements reached by MESA Inc. and CIG during 1993 provide that MESA Inc.
is entitled to a maximum of 32 Bcf at the Fain plant inlet for each of the
years 1994, 1995, and 1996, with CIG having the rights to the remainder of the
"B" Contract production in these years. CIG is entitled to a maximum of 8.5
Bcf for each of the years 1997, 1998, and 1999, with MESA Inc. being entitled to
take the rest of the "B" Contract production in these years. CIG's maximum take
for the year 2000 is 7.56 Bcf, with a maximum of 7.0 Bcf in years thereafter,
until it has produced the full 23 percent of the January 1, 1991, reserves to
which it is entitled. In addition to its gas take limitations, CIG has the
right to take gas for use as field fuel until July 2000. The projected volumes
in this report assume that MESA Inc. will take the maximum volume to which it
is entitled under the contract, for as long as the projection of allowables and
deliverability will permit, after which the projected deliverability is used.
One of the provisions of the new agreement eliminates the previous requirement
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that MESA Inc. had to take, use, process, and sell its gas within the "City of
Amarillo, Texas, and its environs." MESA Inc. can now sell its share of the "B"
Contract gas to markets anywhere, whether inside or outside of the City of
Amarillo or inside or outside of the State of Texas.
Since January 1, 1991, CIG has overproduced its 23 percent share of the gas.
This over production of gas by CIG and the subsequent gas balancing has been
accounted for in this report by adjusting MESA Inc.'s gas interests in the "B"
Contract Area over time. For accounting purposes, the CIG gas imbalance
discussed above is treated as production income to MESA Inc. at the time CIG
produced the gas; this revenue is then recorded as an account receivable from
CIG. This difference in treatment must be considered when using this report
with the accounting records. The cumulative gas imbalance as of December 31,
1993 is tabulated below. These amounts have not been deducted from this report.
Net Salable Gas, Mcf ............ 12,345,442
Net Natural Gas Liquids, Bbl...... 1,749,033
Net Condensate, Bbl ............. 6,941
Net Helium, Mcf ................. 69,545
Under a workover plan in the "B" Contract Area, approximately 300 wells were
worked over, deepened, or redrilled during the past four years. The workover
plan, a continuing project, is reevaluated each year to determine the following
years work. In this report, the assumption is made that 10 wells will be
redrilled and 5 deepened in 1994, followed by the deepening of 13 wells in 1995
and 15 wells in 1996. In addition, MESA Inc. expects to do 19 workovers in
1994, and routine maintenance workovers are scheduled for future years. MESA
Inc. expects that numerous compressors will be installed on the gathering
system for this field near the wellheads to improve gas deliverability; we have
assumed that 280 wells will receive such additional compression during the next
seven years. Additional wells may need compression, but certain of the
compression needs can be met by grouping two or more wells into a cluster, and
by moving compressors from abandoned sites to new locations.
The expected acceleration of production from these programs has been
incorporated in the estimated production rates. The expense of these programs
initially will be paid by CIG but will be repaid by MESA Inc. As provided by
the operating agreement between MESA Inc. and CIG, this repayment has been
amortized herein over the remaining lives of the properties on a
unit-of-production basis.
Future oil and gas producing rates estimated for this report are based on
production rates considering the most recent figures available or, in certain
cases, are based on estimates provided by MESA Inc. The rates used for future
production are rates that we feel are within the capacity of the well or
reservoir to produce. Information on curtailment of gas production and on the
anticipated resumption of normal producing rates in certain areas has been
considered in arriving at the rates projected.
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Gas volumes are expressed at a temperature of 60 degrees Fahrenheit and at the
legal pressure base of the states in which the gas reserves are located. Gross
volumes are reported as wet gas and the net volumes are reported as salable
gas; however, neither the gross nor net volumes were reduced for plant fuel
usage, which is estimated to be 36.9 billion cubic feet of gross wet gas. The
value of this fuel is deducted as part of the plant operating costs. Condensate
reserves estimated herein are those to be obtained by conventional lease
separation.
Revenue values in this report were estimated using current prices and costs.
Future prices were estimated using guidelines established by the Securities and
Exchange Commission and the Financial Accounting Standards Board. The initial
and future prices and producing rates used in this report are those that MESA
Inc. can reasonably expect to be received over the life of the properties. The
assumptions used for estimating future prices and costs are as follows.
OIL AND CONDENSATE PRICES
Initial oil and condensate prices were held constant for the life of the
properties.
NATURAL GAS, HELIUM, AND CARBON DIOXIDE PRICES
Natural gas prices were held constant for the life of the properties except for
some 40 percent of the gas in the Texas Panhandle field.
Under existing contractual arrangements in the Panhandle properties, about 40
percent of the total gas is sold to Energas under a long-term contract. In
1992, MESA Inc. and Energas negotiated a new pricing formula for the next five
years of gas sales to Energas. Seventy percent of the gas sold to Energas will
be sold at a fixed price that escalates by a total of $0.75 per thousand cubic
feet from 1993 to 1997. The remaining 30 percent of such gas will be sold at
the "spot-market" gas price plus $0.10 per thousand cubic feet. The pricing
formula will be renegotiated for periods after 1997. In this report, the
prices applicable under the current contract pricing formula were used through
1997. Beginning in 1998, the 1994 weighted average price was applied to the
subsequent Energas sales.
Helium and carbon dioxide prices were held constant for the life of the
properties.
NATURAL GAS LIQUIDS PRICES
Natural gas liquids prices were held constant for the life of the properties
except that prices were changed in consideration of a new sales contract for
the Panhandle properties effective May 1, 1994.
OPERATING AND CAPITAL COSTS
Estimates of operating costs based on current costs were used for the life of
the properties with no increases in the future based on inflation. Future
capital expenditures were
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estimated using 1993 values and were not adjusted for inflation.
Oil and condensate production taxes were calculated using net removal prices
after deducting transportation charges.
Economic estimates were made, as of December 31, 1993, under the aforementioned
assumptions concerning future prices and costs and are summarized as follows:
Total
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Future Gross Revenue (M$) .................. 3,723,760
Production Taxes (M$) ....................... 200,670
Ad Valorem Taxes (M$) ....................... 239,310
Operating Costs (M$) ....................... 897,244
Capital Costs (M$) ......................... 80,310
Future Net Revenue (M$)(1) ................. 2,306,226
Present Worth at 10 Percent (M$)(1) ......... 1,068,740
(1) Future income tax expenses were not taken into account in the
preparation of these estimates.
Included above is revenue from nonhydrocarbon reserves (helium and carbon
dioxide) that will be produced with and separated from certain natural gas as
it is produced. It is estimated that about 4 percent of the present worth shown
above is attributable to this planned helium and carbon dioxide recovery.
The information relating to estimated proved reserves, estimated future net
revenue from proved reserves, and present worth of estimated future net revenue
from proved reserves of oil, condensate, natural gas liquids, and gas contained
in this report has been prepared in accordance with Paragraphs 10-13, 15 and
30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982)
of the Financial Accounting Standards Board and Rules 4-10(a)(1)-(13) of
Regulation S-X and Rule 302(b) of Regulation S-K of the Securities and Exchange
Commission; provided, however, (i) certain estimated data have not been
provided with respect to changes in reserve information, (ii) future income tax
expenses have not been taken into account in estimating the future net revenue
and present worth values set forth herein, and (iii) minor amounts of revenue
from nonhydrocarbon gases are included herein.
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To the extent the above-enumerated rules, regulations, and statements require
determinations of an accounting or legal nature or information beyond the scope
of this report, MESA Inc. is necessarily unable to express an opinion as to
whether the above described information is in accordance therewith or
sufficient therefor.
Submitted,
/s/ DENNIS E. FAGERSTONE
Dennis E. Fagerstone
Vice President-Exploration and Production