March 17, 1997
Mesa Inc.
1400 Williams Square West
5202 North O'Connor Blvd.
Irving, Texas 75039
Attention Mr. Dennis E. Fagerstone
Gentlemen:
Subject: Evaluation and Review
of Oil and Gas Reserves
to the Interests of Mesa Inc.
in the Hugoton Area, Various
Counties, Kansas and West Panhandle
Area, Various Counties, Texas
Effective December 31, 1996
for Disclosure to the
Securities and Exchange Commission
Williamson Project 6.8421
Williamson Petroleum Consultants, Inc. (Williamson) has performed an
engineering evaluation to estimate proved gross 8/8 gas reserves from
properties in the Kansas Hugoton (Chase) and Panoma Gas Area (Council
Grove) fields in various counties in Kansas (the Hugoton area) and the
Panhandle West (Brown Dolomite) and Panhandle West (Red Cave) fields in
various counties in Texas (the West Panhandle area). Williamson also
reviewed in detail the Mesa Inc. (Mesa) in-house programs and methodology
used to convert gross gas reserves to net gas residue and plant products
and to generate future net revenue to the interests of Mesa. This
evaluation and review (the evaluation) were authorized by Mr. Dennis E.
Fagerstone of Mesa.
Projections of the reserves and future net revenue to the evaluated
interests were based on economic parameters and operating conditions
considered applicable as of December 31, 1996. This evaluation, in
conjunction with other documents and data, is being used by Mesa for annual
corporate purposes. This evaluation may be used in disclosure to the
Securities and Exchange Commission (SEC). Data after December 31, 1996 were
utilized by Williamson in evaluating the properties in this report. These
data are described later in this letter report. Following is a summary of
the results of the evaluation effective December 31, 1996:
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
----------- ----------- -----------
Net Reserves to the
Evaluated Interests:
Oil, BBL 20,088 0 20,088
Condensate, BBL 3,602,190 348,888 3,951,078
Plant Products, BBL 84,180,172 3,735,950 87,916,122
Gas, MCF 956,983,080 22,873,675 979,856,755
Helium, MCF 4,621,586 148,986 4,770,572
Future Net Revenue, $:
Undiscounted 4,114,727,295 154,027,679 4,268,754,974
Discounted Per Annum
at 10.00 Percent 1,693,922,051 47,203,819 1,741,125,880
Note: Totals are affected by the rounding utilized in the OGRE software.
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 2
The work performed under the subject project is defined by the two phases
discussed below. All computer processing was performed by Mesa personnel to
utilize the Mesa in-house well reserve model and field/plant models.
Essentially all work by Williamson was accomplished in the Mesa offices in
Irving, Texas.
Under Phase 1, engineering personnel from Williamson worked directly with
the Mesa staff engineers and geologists to assign gross 8/8 gas reserves to
wells in the Hugoton and West Panhandle areas. Williamson also assigned or
reviewed and approved all forecast parameters to be used in the Mesa well
reserve model. Results of the well reserve model were then input into an
Ogre format and economic gross gas reserves were determined on a well level
considering only direct well costs.
Under Phase 2, the gross gas reserves were summarized on a group or field
basis and input into the field/plant models. These programs convert the
gross gas streams into net gas, net natural gas liquids (NGL), and net
helium to the interests of Mesa and calculate the associated future net
revenue. In the case of the West Panhandle area, there is also a relatively
minor volume of oil and condensate. The field/plant models consider
compression and gathering operating costs and fuel needs, plant shrinkage,
NGL and helium yields, and various sharing arrangements and costs. These
calculations are done on a total system basis. Williamson reviewed various
documents, agreements, and other data relative to these costs and sharing
arrangements and reviewed the outputs generated by Mesa for reasonableness
and consistency.
The properties evaluated are located in the Kansas Hugoton (Chase) and
Panoma Gas Area (Council Grove) fields in Grant, Hamilton, Haskell,
Kearney, Morton, Seward, Stanton, and Stevens Counties, Kansas and the West
Panhandle (Brown Dolomite) and West Panhandle (Red Cave) fields in Carson,
Hartley, Hutchinson, Moore, Oldham, and Potter Counties, Texas. A total of
2,483 properties are included in these fields. Lists of properties are
included for the Hugoton area and the West Panhandle area. Approximately
64.89 percent of the total future net revenue discounted at 10.00 percent
per annum (DFNR) is contributed by the Hugoton area with the remainder by
the West Panhandle area. Summary reserves and economics projections for
each area are attached.
Net income to the evaluated interests is the future net revenue after
consideration of royalty revenue payable to others, taxes, operating
expenses, investments, salvage values, abandonment costs, and net profit
interests, as applicable. The future net revenue is before federal income
tax and excludes consideration of any encumbrances against the properties
if such exist.
The future net revenue values presented in this report were based on
projections of oil and gas production. It was assumed there would be no
significant delay between the date of oil and gas production and the
receipt of the associated revenue for this production.
Unless specifically identified and documented by Mesa as having curtailment
problems, gas production trends have been assumed to be a function of well
productivity and not of market conditions.
Oil and gas reserves were evaluated for the proved developed producing,
proved developed nonproducing, and proved undeveloped categories. The
summary classification of proved developed reserves combines the proved
developed producing and proved developed nonproducing categories. No
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 3
separate summary of proved developed nonproducing is included due to the
minor volumes of these reserves and in accordance with the request of Mesa.
In preparing this evaluation, no attempt has been made to quantify the
element of uncertainty associated with any category. Reserves were assigned
to each category as warranted. The attached Definitions describe all
categories of proved reserves.
Oil, condensate, and NGL reserves are expressed in United States (U.S.)
barrels of 42 U.S. gallons. Gas volumes are expressed in thousands of cubic
feet (MCF) at 60 degrees Fahrenheit and at the legal pressure base that
prevails in the state in which the reserves are located. No adjustment of
the individual gas volumes to a common pressure base has been made.
The future net revenue was discounted at an annual rate of 10.00 percent.
Future net revenue was also discounted at secondary rates of 8.00, 12.00,
15.00, 20.00, and 25.00 percent per annum. These additional discounted
amounts are displayed as totals only. The 10.00 percent rate was included
in accordance with the reporting requirements of the SEC. No opinion is
expressed by Williamson in this report as to a fair market value of the
evaluated properties.
This report includes only those costs and revenues which are considered by
Mesa to be directly attributable to individual leases and areas. There
could exist other revenues, overhead costs, or other costs associated with
Mesa which are not included in this report. Such additional costs and
revenues are outside the scope of this report. This report is not a
financial statement for Mesa and should not be used as the sole basis for
any transaction concerning Mesa or the evaluated properties.
The reserves projections in this evaluation are based on the use of the
available data and accepted industry engineering methods. Future changes in
any operational or economic parameters or production characteristics of the
evaluated properties could increase or decrease their reserves. Unforeseen
changes in market demand or allowables set by various regulatory agencies
could also cause actual production rates to vary from those projected. The
dates of first production for nonproducing properties were based on
estimates by Mesa or Williamson and the actual dates may vary from those
estimated. Williamson reserves the right to alter any of the reserves
projections and the associated economics included in this evaluation in any
future evaluations based on additional data that may be acquired.
Williamson is an independent consulting firm and does not own any interests
in the oil and gas properties covered by this report. No employee, officer,
or director of Williamson is an employee, officer, or director of Mesa.
Neither the employment of nor the compensation received by Williamson is
contingent upon the values assigned to the properties covered by this
report.
All data utilized in the preparation of this report with respect to
interests, reversionary status, oil and gas prices, gas categories, gas
contract terms, operating expenses, investments, salvage values,
abandonment costs, net profit interests, well information, and current
operating conditions, as applicable, were provided by Mesa. Data obtained
after the effective date of the report but prior to the completion of the
report were used and were applied consistently. These data consisted of
daily well gauges in January 1997 on wells which may have been recently
completed or acutest or had a pumping unit or compression installed. In
addition, inlet gas volumes and plant recoveries for the Fain plant, Potter
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 4
County, Texas for January 1997 were reviewed to observe liquid and helium
recovery yields after all West Panhandle gas production was transferred to
the Fain plant in late December 1996. The reserves category assignments
reflect the status of the wells as of the effective date. Production data
were provided by Mesa from public record. If public records were not
available, Mesa provided internal estimates. The production data were
generally updated through November or December 1996 for operated properties
and October 1996 for outside operated properties. All data have been
reviewed for reasonableness and, unless obvious errors were detected, have
been accepted as correct. It should be emphasized that revisions to the
projections of reserves and economics included in this report may be
required if the provided data are revised for any reason. No inspection of
the properties was made as this was not considered within the scope of this
evaluation. No investigation was made of any environmental liabilities that
might apply to the evaluated properties. Mesa has included certain
operating costs designated for environmental purposes.
Mesa represented to Williamson that is has, or can generate, the financial
and operational capabilities to accomplish those projects evaluated by
Williamson which require capital expenditures.
The estimates of reserves contained in this report were determined by
accepted industry methods and in accordance with the attached Definitions
of Oil and Gas Reserves. Methods utilized in this report include
extrapolation of historical production trends, material balance
determinations, and analogy to similar properties.
Where sufficient production history and other data were available, reserves
for producing properties were determined through the use of material
balance determinations or by extrapolation of historical production trends.
Analogy to similar properties was used for nonproducing properties and
those producing properties which lacked sufficient production history and
other data to yield a definitive estimate of reserves. Reserves projections
based on analogy are subject to change due to subsequent changes in the
analogous properties or subsequent production from the evaluated
properties.
Prices for oil/condensate sold during December 1996 were provided by Mesa
and were used as effective date prices. After the effective date, prices
were held constant for the life of the properties. No attempt has been made
to account for oil price fluctuations which have occurred in the market
subsequent to the effective date of this report.
Prices for gas sold during December 1996 were provided by Mesa. Gas prices
were adjusted by Mesa as necessary for any transportation charges or other
fees and were used as effective date prices. Residue gas from the Fain
plant in the West Panhandle area is sold to several purchasers. The
December 1996 gas price was a weighted average price based on the percent
of volume taken by each purchaser and the December 1996 gas price paid by
each purchaser. After the effective date, prices were held constant for the
life of the properties.
Prices for NGL were based on prices for NGL products sold in December 1996.
After the effective date, prices were held constant for the life of the
properties. The price for helium is contractual for the year 1997 and was
set at $26.84 per MCF for both the Satanta plant in the Hugoton area and
the Fain plant in the West Panhandle area. On January 1, 1998, the Satanta
plant price was reduced to $19.72 per MCF and held constant thereafter. For
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 5
the Fain plant, the price was set at $23.00 per MCF from January 1, 1998
through December 31, 2004. Beginning January 1, 2005, the price was set at
$19.72 per MCF and held constant thereafter.
It should be emphasized that with the current economic uncertainties,
fluctuation in market conditions could significantly change the economics
of the properties included in this report.
Operating expenses were provided by Mesa and represented, when possible,
the latest available 12-month average of all recurring expenses which are
billable to the working interest owners or other participants. Both the
Hugoton and West Panhandle area properties process gas through the Satanta
plant (Hugoton) or Fain plant (West Panhandle). Operating costs included
direct well expenses, wellhead compression costs, lateral or station
compression costs, gathering costs, plant operating costs, field or plant
overhead costs, and fuel volumes/costs for irrigation, compression, and
plant operations, as applicable. Any ad valorem taxes not deducted
separately were also included in the operating expenses. Where additional
compression was scheduled for installation in 1997 and 1998, adjustments
were made to increase compression costs and fuel requirements.
Base operating costs were held constant for the life of the properties.
Variable operating costs such as wellhead or lateral compression costs,
engine or compressor overhaul costs, and plant operating costs were
adjusted to take into account increasing or decreasing gas production and
the varying need for compressors, fuel, and maintenance. Mesa provided a
schedule of costs based on the projected total gas volumes.
For non-Mesa operated nonprocessed properties, operating costs were based
on expenses billed to Mesa.
Each well was projected to an economic lifetime using direct well costs.
Individual well projections were then combined into area or field groupings
and the overall economic lifetime was determined for each group considering
all costs from the wells through the plants discharge. In the Hugoton area,
wells were divided into four groups - MTR, WNG (or Satanta), CIG, and
Nonprocessed. In the West Panhandle area all wells were combined together.
State production taxes and ad valorem taxes have been deducted at rates
specified by Mesa, as applicable.
All capital costs for drilling and completion of wells, recurring well
workovers, and property abandonment costs in excess of any salvage value
have been deducted as applicable. Capital costs were also included for
pumping unit installations, lateral compression installations, Satanta
plant modifications, and other scheduled or anticipated well, field, and
plant needs. These costs were provided by Mesa. No adjustments were made to
account for the potential effect of inflation on these costs.
Property abandonment costs were provided by Mesa.
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 6
PROPERTY REVIEW
HUGOTON AREA
General
- -------
The Hugoton area includes a total of 1,461 wells producing from the Kansas
Hugoton (Chase) field and the Panoma Gas Area (Council Grove) field. Total
reserves for the area amount to 691,412,382 MCF net, 45,417,928 net barrels
of NGL, and 3,180,397 MCF of helium. Total DFNR for the area is
$1,129,731,081.
Reserves for the Chase wells were based primarily on area or group
composite shut-in tubing pressure versus cumulative gas production
(pressure-cumulative) curves. Projected estimates of remaining original gas
in place (OGIP) were allocated to each well in the group based on the
current pseudo-stabilized producing rate of a well to the total rate
for all wells in the group. Wells that were not in a contiguous area
were projected on the bases of the pressure cumulative-curve and rate
versus time performance curve analysis of the individual well.
Nonoperated-nonprocessed wells were forecast using the pressure-cumulative
curve extrapolation established on the original well prior to infill
drilling in the late 1980's, and the resulting remaining OGIP for the
proration unit for the original well was allocated to the original well and
its infill well based on current stabilized producing rates. Remaining
reserves for the proration unit considered cumulative gas from both the
original and infill wells.
Reserves for the Council Grove wells were based on individual well
pressure-cumulative curves. No infill drilling has been performed in the
Panoma Gas Area (Council Grove) field and wells are on 640-acre spacing.
HUGOTON
MTR
- ---
MTR includes 465 operated wells in the Chase or Council Grove formations.
These wells are in a contiguous area in the middle of the Kansas Hugoton
field trend. This is the most significant value group in the Hugoton area
with $587,339,207 DFNR. The MTR base royalty is determined in accordance
with what is termed the Larrabee Royalty Agreement which is governed by the
1975 Settlement Agreement between Mesa and the royalty owners. In essence
the royalty owners share in income from residue gas sales and plant
products. In return, the royalty owners pay certain costs and expenses
downstream of the wellhead. Hence, the royalty owners share is adjusted
downward from their base royalty interest to account for their share of
costs. This revised interest or Larrabee Factor is applied to the plant
output streams to determine the net interest for Mesa after royalty.
The MTR group is also subject to an overriding royalty conveyance
established in 1979 (the MTR Trust). Originally, Mesa established the Mesa
Royalty Trust Indenture. This indenture was subsequently converted to the
MTR Trust in which the royalty owners converted their overriding royalty
interest to a net profits interest. The net profits are determined on the
basis of the future net revenue for the aggregate of the combined Mesa and
MTR Trust interests in the MTR Trust properties less overhead charges, less
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 7
100.0 percent plant and gathering expenses, and less 35.0 percent of NGL
revenue. The MTR Trust share is equal to 10.29282 percent of the adjusted
net revenue. The adjustment to Mesa net reserves for the MTR Trust is made
after the Larrabee adjustment.
HUGOTON
WNG
- ---
The WNG, or Satanta, group is the second most valuable with DFNR of
$425,365,103. This group includes 348 Mesa-operated wells and is in a
contiguous area to the east and northeast of the MTR area. Production is
from the Chase and Council Grove formations. Royalty deduction for this
group is based on the Larrabee Royalty Agreement. WNG is not subject to the
MTR Trust.
HUGOTON
CIG
- ---
The CIG group is the third most valuable with DFNR of $65,742,841. This
group includes 142 wells which are operated primarily by Mesa. Production
is from the Chase and Council Grove formations. The CIG wells are located
in two contiguous areas which are north of MTR and WNG. Royalty deduction
for this group is based on the Larrabee Royalty Agreement. CIG is not
subject to the MTR Trust.
HUGOTON
Nonprocessed
- ------------
The Nonprocessed group has DFNR of $51,283,939 and includes 203 working
interest wells and 303 royalty interest wells. Essentially all except
approximately 30 of these wells are outside operated. Production is from
the Chase and Council Grove formations and other stray formations. All gas
from these wells is processed through other facilities and, therefore, Mesa
receives income on the basis of wellhead gas sales only.
WEST PANHANDLE AREA
General
- -------
The West Panhandle area has a total of $611,394,799 DFNR. Included in this
area are the "B" Contract area wells consisting of 594 gas wells producing
from the Brown Dolomite and the Red Cave formations. The Brown Dolomite is
the primary producing formation. Gas wells are drilled on 640-acre spacing.
Reserves for established producing wells were based on individual
pressure-cumulative curves. Reserves for recently drilled wells with
limited history were based on available test or production data and analogy
decline trends. Reserves for undrilled locations were based on analogy to
offsetting wells or wells in close proximity.
Mesa also retains an interest in 419 oil wells and nine gas wells that are
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 8
referred to as the "Texas Panhandle-Other". These are minor-value
properties that are not included in the "B" Contract area. Reserves for
these minor-value properties were determined by performance analysis.
The "B" Contract area wells are subject to an operating agreement with
Colorado Interstate Gas Company (CIG). All of the "B" Contract area gas is
processed through the Mesa Fain gasoline plant, and the Mesa share is
subject to special royalty payments. An agreement effective January 1, 1991
allocates 77.0 percent of the remaining production from the "B" Contract
properties to Mesa and the remaining 23.0 percent to CIG. CIG receives a
20.0 percent overriding royalty interest on the Mesa share of the helium
produced at the Fain plant.
As of December 31, 1996, CIG has produced 37.98 percent of the net "B"
Contract gas produced since 1991. The summary reserves and economics
projection for the West Panhandle area includes future recovery of this
excess gas produced by CIG. The imbalance as of December 31, 1996 is
approximately 42,986,000 MCF. Mesa has advised that, for accounting
purposes, this CIG gas imbalance is also treated as production income to
Mesa at the time CIG produced the gas; the revenue is then recorded as an
accounts receivable from CIG. Therefore, this should be considered when
using the attached reserves and economics projections with Mesa financial
data.
Agreements reached by Mesa and CIG, ending with the 1996 Fain Gas
Processing Agreement dated June 1, 1996, provide for CIG to take a maximum
of 8.5 billion cubic feet (BCF) per year for each of the years 1997, 1998,
and 1999 with Mesa being entitled to take the rest of the "B" Contract
production. The CIG maximum take in the year 2000 is 7.5 BCF, with a
maximum of 7.0 BCF in years thereafter, until such time that CIG has
produced 23.0 percent of the reserves remaining after January 1, 1991.
Included in these volumes is the CIG share of fuel gas. Until July 2000,
CIG has the right to take gas for use as fuel at 100.0 percent of fuel
usage. After July 2000, fuel volumes are shared proportionately by Mesa and
CIG. Also, CIG must take all their allowed gas during the seven month
period from April through October of each year at a rate not to exceed 40.0
million cubic feet per day (MMPD). Beginning on July 1, 2000 the CIG
maximum daily rate reduces to 35.0 MMPD. Under the current evaluation, it
is projected that CIG will have recovered their 23.0 percent of the
reserves to be recovered after January 1, 1991 in the year 2007.
Another aspect of the 1996 Fain Gas Processing Agreement is that Mesa will
retain 100.0 percent of the CIG share of ethane and 50.0 percent of the CIG
share of propane. In return, CIG will receive an equivalent volume on a
British Thermal Unit basis of residue gas from Mesa. These adjustments are
included in the West Panhandle area field/plant model.
Scheduled work in the field includes drilling of 57 proved undeveloped
locations, installation of additional wellhead compressors, and the
installation of a Nitrogen Recovery Unit at the Fain plant in mid-1998.
Results of these projects have been included in the reserve projections as
well as capital costs and additional operating expenses. In the year 2045,
the Fain plant is no longer economical and is projected to be shut in.
Beginning in 2046, all gas was projected to be sold directly to the
pipeline.
Mesa Inc.
Mr. Dennis E. Fagerstone
March 17, 1997
Page 9
It has been a pleasure to serve you by preparing this engineering
evaluation. All related data will be retained in our files and are
available for your review.
Yours very truly,
/s/ Williamson Petroleum Consultants, Inc.
WILLIAMSON PETROLEUM CONSULTANTS, INC.
JJK/jlb
Attachments
DEFINITIONS OF OIL AND GAS RESERVES(1)
PROVED RESERVES(1)
Proved reserves are the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under the economic criteria employed and existing operating
conditions, i.e., prices and costs as of the date the estimate is made.
Prices and costs include consideration of changes provided only by
contractual arrangements but not on escalations based upon an estimate of
future conditions.
A. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes:
1. that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
2. the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
B. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
C. Estimates of proved reserves do not include the following:
1. oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";
2. crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;
3. crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
4. crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal(1), gilsonite, and other such
sources.
Proved Developed Reserves(4)
Proved developed reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of
fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as
"proved developed reserves" only after testing by a pilot project or after
the operation of an installed program has confirmed through production
response that increased recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped reserves are reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled.
Proved reserves for other undrilled units can be claimed only where it can
be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates
for proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
..........
(1) For evaluations prepared for disclosure to the Securities and Exchange
Commission, see SEC Accounting Rules. Commerce Clearinghouse, Inc. October
1981, Paragraph 290, Regulation 210. 4-10, p. 3229.
(2) Any variation to these definitions will be clearly stated in the
report.
(3) According to Staff Accounting Bulletin 85, excluding certain coalbed
methane gas
(4) Williamson Petroleum Consultants, Inc. separates proved developed
reserves into proved developed producing and proved developed nonproducing
reserves. This is to identify proved developed producing reserves as those
to be recovered from actively producing wells; proved developed
nonproducing reserves as those to be recovered from wells or intervals
within wells, which are completed but shut in waiting on equipment or
pipeline connections, or wells where a relatively minor expenditure is
required for recompletion to another zone.