SUPPLEMENTAL INFORMATION TO THE PROSPECTUS
DATED JUNE 19, 1998, ON POTENTIAL
GREATER GREEN RIVER BASIN DRILLING
DATE OF THIS SUPPLEMENT -- NOVEMBER 30, 1998
Introduction
The Program intends to expand the potential drilling areas that
are available to the Partnerships. By this supplement, the
Program is including Colorado to the list of states where
Partnership activities may take place. To accomplish this
extension, the Program is amending paragraph 5.02 (a) (i) (y) of
the limited partnership agreement attached to the Prospectus to
specify Colorado as a state where Partnership activities may
occur.
The Lewis Shale and Mesaverde Group natural gas plays in the
Greater Green River Basin (GGRB) in Wyoming and Colorado are
two of the most underdeveloped plays in the U.S. While they
have cumulatively produced over 2.2 TCF of gas, they have
remaining reserves estimated at 31 TCF. As of 1996, over 1000
wells were producing from these reservoirs. Increasing numbers
of new wells are being drilled as this play expands. The Lewis
Shale and Mesaverde Group reservoirs were deposited in a wide
variety of depositional environments ranging from fluvial to
coastal to deep marine. During recent years of accelerated
activity, drilling and completion techniques have been improved,
costs have been reduced, completion success rates are higher and
average reserves per well have increased.
If the Partnership drills in the GGRB, the initial wells drilled
would be exploratory. Drilling depths might range from 4,000 feet
to over 14,000 feet and may have multiple zones to complete. The
Managing General Partner estimates that intangible dry hole costs
would range from $490,000 to $620,000 per well and that intangible
drilling and completion costs would range from $840,000 to
$1,060,000 per well. Costs for pipeline gathering, processing,
compression and other facilities are not included.
Lewis Shale and Mesaverde Group Development History
The oil and gas industry in the Greater Green River Basin got its
start in 1916 with the discovery of oil in a Cretaceous aged
reservoir from a depth of 265 feet. Predictably, this discovery
was made on a surface mapped structure. Since that time, the
drilling depths have increased, the remaining undiscovered fields
have become more difficult to find and there has been an increase
in focus on gas production. The majority of drilling effort in the
past two decades has focused on deeper gas-bearing stratigraphic
traps. Many of these are low-permeability reservoirs which have
recently become economic through improvements in drilling and
completion technology. Pipeline infrastructure has improved and
what was historically a predominantly oil producing region has
become one of the most active natural gas exploration and
development plays in the U.S.
Regional Setting and Geology
The GGRB is located in southwestern Wyoming and northwestern
Colorado. This irregularly shaped basin is a composite of several
smaller subbasins and intervening uplifts. Gas production comes
from reservoir rocks ranging in age from Mississippian to
Tertiary. All types of hydrocarbon traps are represented in the
GGRB. Many Cretaceous and Tertiary reservoirs are
overpressured and have low-permeability. The source rock for
much of the Upper Cretaceous hydrocarbons is the Mowry Shale,
the Cody Shale and in some areas, interbedded coals.
Several thousand feet of Upper Cretaceous sediments were
deposited in a narrow seaway that extended from the Gulf Coast to
the Arctic. Uplifted areas along the seaway's flanks provided
large volumes of clastics that were transported into varying
environments of fluvial, coastal and deep marine deposition. The
processes of deposition and the progressive filling of the
Cretaceous seaway resulted in a myriad of sandstone geometries:
deep sea fans, delta front sands, offshore shelf bars, barrier
bars, point bars, all kinds of deltaic complexes and fluvial
channels, flood plains, and eolian plains.
Although there are more than 100 local names for the sandstones
comprising the Mesaverde Group, the main subdivisions are based
upon times of major transgression and regression of the Upper
Cretaceous seaway. Generally, the Mesaverde Group sandstones
were deposited in thick fluvial packages on the flank of the
seaway in south central Wyoming and as marine sandstones
interfingering with marine shales to the east in the more central
portions of the seaway. The Almond Formation is the uppermost
formation of the Upper Cretaceous Mesaverde Group. It consists
of a lower regressive fluvial and alluvial facies sometimes referred
to as the main Almond or Williams Fork Formation. The fluvial
facies is capped by the onset of transgression of the Lewis
seaway. The first sediments deposited were transgressive coastal
marine sediments referred to as the upper Almond. These upper
Almond sandstones were deposited in depositional environments
ranging from estuarine to coastline to open marine deltaic. The
transgression of the Lewis sea was not continuous but was instead
marked by a series of pauses or "stillstands," of active delta
building during which the shoreline briefly prograded. In most
cases progradation resulted in sandstone bodies with good
continuity along the shoreline trend but very limited in
depositional dip. These sandstones are discontinuous and become
progressively younger to the west. They have been described as
"chains of barrier islands with closely spaced and highly active
tidal inlets." As a whole, these upper Almond shoreline
sandstone bodies deposited in this way constitute one or more
backward-stepping trends.
The transgressive event resulting in the deposition of the upper
Almond also led to the deposition of the Lewis Shale, the youngest
of the major, westward thinning tongues of Cretaceous marine
shale. During the above mentioned "stillstands", Lewis sandstone
turbidites were deposited down the basin slope onto the floor of
the Lewis sea resulting in submarine fan deposits with
discontinuous discrete lobe shape geometries.
Drilling depths for these reservoirs range from 4,000 feet to over
14,000 feet depending upon the location within the basin.
Mesaverde Group and Lewis Shale Production and Reserves
Sandstone reservoirs within the Upper Cretaceous Lewis Shale and
Mesaverde Formations of the GGRB contain a significant
underdeveloped resource. Although they have cumulatively
produced 2.2 TCF, or 32% of the total natural gas produced in the
basin, recent resource estimates of remaining reserves and
undiscovered resources are 31 TCF (Doelger, M.J., and J.A. Barlow,
Jr., 1997, in GRI Gas Tips, Vol. 3, No. 3). In 1996, 132 wells were
completed in these reservoirs. New well drilling permits issued
for these reservoirs increasingly comprise a larger percentage of
total permits in the GGRB.
Lewis Shale sandstone reservoirs have produced a total of 0.6 TCF
of gas. In 1996, there were 174 wells producing from the Lewis.
They had a reported total annual production of 20 BCF, averaging
350 mcfd/well. The average estimated reserves per Lewis Shale
sandstone reservoir were 1.6 BCF.
Mesaverde Group reservoirs have produced a total of 1.6 TCF of
gas. Of that total, the Almond subplay has produced more than 1
TCF. In 1996, there were 840 wells producing from the Mesaverde.
They had a reported total annual production of 134 BCF,
averaging 440 mcfd/well. The average estimated reserves per
Mesaverde Group reservoir were 1.3 BCF.
The production profiles for these reservoirs are hyperbolic with a
majority of reserves produced within the first few years of
production life. The productive life of these wells can be 15 to 20
years or more. Many variables including reservoir characteristics,
drilling and completion methods and well spacing affect the
ultimate recovery per well. Recent technological improvements in
drilling and completion practices have not only helped to reduce
costs, but have increased production and reserves on an average
per well basis.
Nonetheless, because the Partnership will participate in new wells,
there can be no assurance of the actual level of Partnership
production or reserves.
Participation by the Partnership in Greater Green River Basin
Prospects
In the event a Partnership participates in a GGRB project well,
the Partnership will acquire less than a 100% working interest,
with PDC and/or other parties participating for the balance of the
project. It is estimated that the Partnership will acquire 90% or
less of the working interest. As provided in the Prospectus, such
partners will pay a pro rata share of development costs for their
interest. (See "Acquisition of Undeveloped Prospects".)
Each Partnership will bear its proportionate share of the cost of
drilling and completing or drilling and abandoning GGRB wells,
where the Managing General Partner serves as operator as follows:
The Cost of the Prospect, as defined; and
For intangible well Costs:
For each well completed and placed in production, an
amount equal to the depth of the well in feet at
its deepest penetration as recorded by the
drilling contractor multiplied by $112 per foot,
plus the actual extra completion cost of zones
completed in excess of the cost of the first zone
and actual additional costs for work required by
state law in the event an intermediate or third
string of surface casing is run, plus the actual
extra costs for directional drilling services, if
required; and
For each well which the Partnership elects not to
complete, an amount equal to $65 per foot, to
the deepest penetration of the well, as specified
above and actual additional costs for work
required by state law in the event an
intermediate or third string of surface casing is
run, plus the actual costs for directional
drilling services, if required; and
The tangible Costs of drilling and completing the Partnership
wells.
To the extent that a Partnership acquires less than 100% of a
Prospect, its Drilling and Completion Costs of that Prospect will be
proportionately decreased.
The estimated costs of Lewis Shale and Mesaverde Group wells vary
substantially depending upon drilling depth and the number of zones
completed. Drilling depths can vary from 4,000 feet to over 14,000
feet and have multiple zones to complete. It is expected that the
initial projects will have drilling depths in the range of 7500 to 9500
feet with a maximum of three zones for completion. Intangible dry
hole cost estimates range from $490,000 to $620,000 per well. The
estimated drilling and completion costs range from $840,000 to
$1,060,000 per well. Costs for pipeline gathering, processing,
compression and other facilities are not included. These facilities are
expected to be provided by an unaffiliated gas transmission company
with terms negotiated in a gas gathering and purchase agreement,
as is customary for the area. Western Gas Resources operates an
extensive pipeline system in the area and has capacity to gather and
transport produced gas from successful Partnership wells for
redelivery to Colorado Interstate Gas Company (CIG). CIG markets
gas throughout the western United States. It is anticipated that
Partnership gas will be marketed at approximately the NYMEX
monthly index less an estimated gathering, transportation and
compression cost of approximately $0.26 per Mcf. If the Managing
General Partner utilizes an outside contractor for drilling and
completion operations the applicable average monthly drilling
overhead rate will be $5,515 per month per well. This represents
the average monthly drilling overhead rate for gas wells as
published in the most recent edition of Ernst & Young, LLP "Fixed
Rate Overhead Survey" for the Rocky Mountain, northern Great
Plains areas. (See "Drilling and Completion Phase" and
"Compensation of the Managing General Partner".)
Development Plan
Petroleum Development Corporation is currently negotiating a farmout
and purchase option on approximately 387,000 acres in the GGRB
prospective for Lewis Shale sandstone and Mesaverde Group
exploration and development. The farmout will provide the
opportunity to drill multiple exploratory wells and earn an interest
in acreage for further development, if warranted. At least three
exploratory prospects have been identified on the subject leasehold.
The initial well on each prospect will be exploratory. It is
anticipated that the viability of successfully completing these wells
can be determined by examination of open-hole wireline well logs and
drill cuttings and fluid analysis mud logs. If the prediction is made
that the well will not be capable of economic production, the well can
be plugged and abandoned at that time and it will not be necessary
to run production casing and attempt a completion. It is expected
that each successful exploratory well will prove from four to ten
development locations for future drilling.
Leases in this area may have a total royalty and override burden
ranging from 12.5% to 20%; average royalty and override per well on
a program basis shall not exceed 16.125% as specified in the
Prospectus. We anticipate that Farmount obligations will provide for
an after payout working interest backin of 25%, payable to
unaffiliated third parties, after recovery of 125% of the cost to drill
and complete the well(s). (See "Acquisition of Undeveloped
Prospects".) PDC shall retain no royalty or overriding interest. PDC
is currently negotiating its lease position in the area. At this time,
no GGRB prospects have been selected for drilling by future
Partnerships, nor is it certain that any GGRB wells will ultimately be
drilled by any Partnership.
Drilling and Operating Agreement
Upon funding of each Partnership, the particular Partnership will
enter into the Drilling and Operating Agreement (herein, the
"Agreement") with the Managing General Partner as operator (herein,
the "Operator"). The Agreement (filed as Exhibit 10(a) to the
Registration Statement) provides that the Operator will conduct and
direct and have full control of all operations on the Partnership's
Prospects. The Operator will have no liability as operator to the
Partnership for losses sustained or liabilities incurred, except as
may result from the Operator' negligence or misconduct. Under the
terms of the Agreement, the Managing General Partner may
subcontract certain of those responsibilities as Operator for
Partnership wells. It is anticipated that the Managing General
Partner will utilize an independent, third party contractor for well
tending services. The direct cost to the Partnership for these
services is estimated to be approximately $600 per month. It is
anticipated that the Managing General Partner will provide these
services in the future, at rates competitive with those of unaffiliated
third party contractors in the area. The Managing General Partner
will retain responsibility for work performed by subcontractors as
set forth in this Prospectus. It is possible that the Managing
General Partner will not be selected as operator on those Prospects
in which the Partnership owns less than a 50% Working Interest.
The Managing General Partner hereby amends paragraph 5.02 (a) (i)
(y) as follows:
The Managing General Partner shall establish a program of
operations for the Partnership which shall be in conformance
with the following policies: (x) . . . ; (y) the Partnership
shall drill its wells in West Virginia, Ohio, Pennsylvania, New
York, Kentucky, Michigan, Indiana, Kansas, Montana, Wyoming,
Oklahoma and/or Colorado.
