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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT - NOVEMBER 25, 1997
(DATE OF EARLIEST EVENT REPORTED)
HS RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
COMMISSION FILE NO. 0-18886
DELAWARE 94-303-6864
(STATE OF INCORPORATION) (I.R.S. EMPLOYER
IDENTIFICATION NO.)
ONE MARITIME PLAZA, 15TH FLOOR, SAN FRANCISCO, CALIFORNIA 94111
(ADDRESS OF PRINCIPAL (ZIP CODE)
EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (415) 433-5795
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FORM 8-K
HS RESOURCES, INC.
November 25, 1997
ITEM 5. OTHER EVENTS
On November 25, 1997, HS Resources, Inc., a Delaware corporation ("HSR" or the
"Company"), entered into a definitive agreement (the "Asset Purchase Agreement")
with Amoco Production Company ("Amoco") to purchase Amoco's producing and
non-producing properties (the "Amoco Properties") in the Wattenberg Field area
of the Denver-Julesburg ("D-J") Basin in northeastern Colorado (the "Amoco
Acquisition"). In connection with the Amoco Acquisition, the Company will (i)
pay $290 million in cash, (ii) issue to Amoco 1.2 million shares (the "Amoco
Shares") of the Company's common stock, par value $0.001 per share (the "Common
Stock"), and (iii) transfer to Amoco certain Mid-Continent producing properties
(the "Transferred Properties"). The Amoco Acquisition is expected to close on or
about December 15, 1997, with an effective date of December 1, 1997. Certain
terms relating to the oil and gas industry are defined in "Certain Definitions"
in the Company's Annual Report on Form 10-K for the year ended December 31,
1996; this section of the Form 10-K is incorporated by reference herein and
filed as Exhibit 99.1 hereto pursuant to Rule 12b-23 under the Securities
Exchange Act of 1934, as amended. The following is a summary description of the
Amoco Acquisition and the Amoco Properties.
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THE AMOCO ACQUISITION
The Amoco Acquisition is a strategic acquisition that will position HSR as
the leading producer in the D-J Basin with total production of over 100 MMcf of
gas and 6,700 Bbls of oil per day. The Amoco Properties have substantial
geographic and geological overlap with HSR's existing D-J Basin assets and
provide the Company with over 2,100 development and exploitation projects, many
of which can be completed with a significantly lower capital investment than
that which would be required for development by HSR or Amoco independently. The
Amoco Properties present the Company with over $400 million of development and
exploitation capital expenditure opportunities that greatly enhance its reserve
and production growth potential. Upon completion of the Amoco Acquisition, HSR
will have an inventory of over 3,600 development, exploitation and exploration
opportunities along with over 1.2 million gross undeveloped acres.
The Amoco Properties contain estimated proved reserves of 70.2 MMBoe at
December 1, 1997, and include interests in 2,051 wells, of which 804
(representing approximately 89% of the proved developed producing reserves) were
operated by Amoco (454 of the remaining wells were and continue to be operated
by the Company). Approximately 78% of the proved reserves included in the Amoco
Properties consist of gas and 55% are classified as proved developed. The Amoco
Properties include 410,000 gross (311,000 net) acres, all of which are held by
production, with an average working interest of approximately 91% and an average
net revenue interest of approximately 79%.
KEY FEATURES OF THE AMOCO ACQUISITION
The geographic and geological overlap of the Amoco Properties with the
Company's existing D-J Basin assets provides HSR with a unique opportunity to
significantly expand within its principal operating area, add an extensive
inventory of development and exploitation opportunities, and increase production
and reserves at attractive finding and development costs. In many cases,
development and exploitation projects can access multiple production zones
through existing wellbores at attractive rates of return. Some of the specific
benefits of the Amoco Acquisition include (i) over 2,100 development and
exploitation opportunities in the Wattenberg Field area (many of which are
relatively low-cost and low-risk as a result of the overlap of HSR's existing
properties and the Amoco Properties), (ii) the ability to produce HSR
hydrocarbons that were economically inaccessable ("stranded reserves") to HSR
prior to the Amoco Acquisition, (iii) the addition of recoverable reserves from
currently producing formations by adding production from other formations, thus
extending the economic life of wells and adding reservoir and wellbore energy to
lift produced liquids, and (iv) operating efficiencies achieved through
elimination of redundant field activities and surface equipment. HSR plans to
spend over $400 million developing and exploiting the Amoco Properties, with the
potential to add substantial proved reserves and production.
Development and Exploitation Opportunities
The Wattenberg Field is characterized by multiple production zones,
principally the Sussex/Shannon, Codell/Niobrara, J-Sand and Dakota formations.
Several production zones can often be accessed with one wellbore, thereby
commingling the production and reducing total capital and operating costs per
unit of production.
In the Wattenberg Field area, working interests in individual producing
horizons underlying the same surface tract are often held by different
operators. This vertical severance of working interests in producing formations
has led to production and development inefficiencies. The reaggregation of the
ownership of formations accomplished in the Amoco Acquisition will enable HSR to
recover reserves more efficiently and economically.
For example, the majority of HSR's reserves in the Wattenberg Field area
are attributable to the Codell/Niobrara formations, while Amoco's reserves are
primarily located in the deeper J-Sand formation. Combining Amoco's and HSR's
wells and reserves results in opportunities to enhance returns by producing
Amoco reserves through HSR wellbores and producing HSR reserves through Amoco
wellbores. The Company intends to execute a detailed, well-specific program for
developing and exploiting the Amoco Properties. This program includes
approximately 415 J-Sand infill wells, 296 recompletions in the J-Sand,
Codell/Niobrara formations or Sussex/
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Shannon formations, 222 deepenings to the Dakota or Codell/Niobrara formations,
148 refracs of existing J-Sand wells, and over 1,200 new J-Sand and
Codell/Niobrara wells under existing spacing.
J-Sand Infills. J-Sand infill wells to be drilled on 80-acre spacing
provide some of the most promising opportunities on the Amoco Properties. The
J-Sand lies approximately 400 feet below the Codell formation and is currently
developed on 160-acre spacing. There are 415 potential J-Sand infill locations
on the Amoco Properties. The J-Sand infill program benefits are enhanced by the
fact that approximately one-third of the infill locations can be drilled by
deepening existing HSR Codell/Niobrara wells at approximately one-half the cost
of drilling a new J-Sand infill well. The Company currently plans to drill 62
J-Sand infill wells in 1998, some of which are expected to be Codell/Niobrara
deepenings.
The Company's extensive reservoir analysis supports J-Sand infill drilling
on a field-wide basis. Applications by various operators, including the Company,
for 13 pilot program J-Sand wells have been submitted to and approved by the
Colorado Oil and Gas Conservation Commission ("COGCC"). The Company believes
that significant additional hydrocarbons attributable to the J-Sand infill wells
satisfy the engineering criteria to be classified as proved reserves, and would
be categorized as proved reserves as the COGCC authorizes drilling of the
additional infill locations.
Recompletions. The Amoco Properties also provide 296 opportunities to
recomplete Amoco J-Sand wells in the J-Sand, Codell/Niobrara, or Sussex/Shannon
formations. The projects are expected to access 6.1 MMBoe of proved reserves at
a total capital cost of approximately $15.9 million. The Company currently plans
to conduct 231 such recompletions in 1998 for a total cost of approximately
$15.5 million.
Deepenings. The Amoco Acquisition provides 222 identified opportunities to
deepen existing wells to new producing horizons. Ninety-one of these involve
deepening J-Sand wells approximately 200 feet to the Dakota formation at an
average cost of approximately $65,000 per well. The Dakota formation is a
relatively new exploration play in the D-J Basin. The industry success rate for
Dakota wells has been approximately 58%, based on the 47 deepenings performed in
the last two years. HSR has recently completed a Dakota deepening with initial
flow rates in excess of 2 MMcf of gas per day. Reserves in successful Dakota
wells have ranged from approximately 40,000 to 670,000 Boe. HSR estimates that
it can complete these 91 deepenings at a total capital cost of approximately
$5.9 million. There are also 131 opportunities to deepen Sussex/Shannon wells to
the Codell/Niobrara formations at an average cost of approximately $136,000 per
well (for a total capital cost of approximately $17.8 million). The Company
intends to deepen 28 J-Sand wells to the Dakota formation in 1998 at a total
capital cost of approximately $1.8 million and 10 Sussex/Shannon wells to the
Codell/Niobrara formations at a total capital cost of approximately $1.4
million.
Refracs. The Amoco Properties include 148 opportunities to refrac existing
J-Sand wells. J-Sand refracs are a relatively new activity focused on improving
production where the initial frac job did not adequately stimulate the
formation. Each refrac costs approximately $130,000. Based on its analysis of
industry results to date, the Company believes that a J-Sand refrac will likely
result in a significant increase in production and total recoverable reserves
per well. The Company estimates the total capital cost of the 148 planned
refracs to be approximately $19.2 million. The Company currently intends to
conduct 40 J-Sand refracs in 1998 with a total capital cost of approximately
$5.2 million.
New Wells. Under existing spacing rules there are over 1,200 new J-Sand and
Codell/Niobrara drilling opportunities on the Amoco Properties. Over 200 such
locations are proved, containing estimated reserves of 8.8 MMBoe. The Company
intends to drill 24 such J-Sand wells on the Amoco Properties in 1998 at a total
capital cost of approximately $6.2 million.
Stranded HSR Reserves
Another important benefit of combining the Amoco Properties with the
Company's is that it unlocks HSR stranded reserves. Because of the historical
difference of working interest ownership in different producing formations, the
economics associated with developing certain of the Company's hydrocarbons were
unattractive without the ability to utilize Amoco wellbores, creating stranded
non-proved reserves. However, the acquisition
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of Amoco wellbores will permit access to the stranded reserves, creating a
significant number of attractive development opportunities. The Company
estimates that there are approximately 350 opportunities to recomplete Amoco
wells, at an average cost of approximately $82,000 per well, into HSR-owned
formations that otherwise would likely not have been developed, including
approximately 100 Codell/Niobrara recompletions and 235 Sussex/Shannon
recompletions.
Operating Efficiencies
The Company expects to realize significant operating efficiencies by
consolidating the Amoco Properties with the Company's existing D-J Basin
operations. Increasing production by commingling production from multiple
formations in existing wellbores, as discussed above, generally can be
accomplished without an increase in production costs per well, thereby resulting
in lower average costs per unit of production. The Company expects to reduce
total costs by eliminating redundant field operations, consolidating pumper
routes and applying its lower cost structure to the Amoco Properties.
Additionally, consolidating redundant assets, such as production equipment and
tank batteries, will result in further operating efficiencies. The redundant
equipment then can be re-deployed as the Company executes its operational plan
in the D-J Basin.
Other Benefits
The Company believes that the Amoco Acquisition may provide additional
benefits to the Company including (i) extending the economic life of existing
wells, (ii) contributing reservoir energy to the wellbores to lift produced
fluids by developing new formations through existing wells, (iii) the creation
of opportunities for additional reaggregation transactions with other operators
whose properties overlap with the Amoco Properties, (iv) enhancement of its gas
marketing strategy because of HSR's increasing share of D-J Basin gas production
(approximately 41% of total Wattenberg Field area gas production), and (v) more
favorable arrangements with oil field suppliers because of the anticipated
increased operating activities.
In addition, the Amoco Properties generate COPAS overhead reimbursement
revenue from third parties, which amounted to $830,000 in 1996. The Amoco
Properties also generate Section 29 income tax credits that the Company
estimates will average $2.5 million annually, net to the Company after
monetization.
OTHER RESERVE AND PRODUCTION DATA
The following table summarizes the estimated net reserves attributable to
the Amoco Properties as of December 1, 1997:
<TABLE>
<CAPTION>
OIL GAS TOTAL
(MMBBL) (BCF) (MMBOE)
-------- ----- -------
<S> <C> <C> <C>
Proved
Developed:
Producing.............................................. 4.3 174.4 33.4
Non-Producing.......................................... 1.5 22.0 5.2
Undeveloped............................................... 9.4 133.4 31.6
---- ----- ----
Total Proved.............................................. 15.2 329.8 70.2
</TABLE>
The Company estimates that current net average daily production from the
Amoco Properties is approximately 44.1 MMcf of gas and 1,400 Bbls of oil (or 8.8
MBoe). Net average daily production from the Amoco Properties for the nine
months ended September 30, 1997, was 47.3 MMcf of gas and 1,642 Bbls of oil (or
9.5 MBoe). The foregoing estimate of production was prepared by the Company and
is based on information provided by Amoco. Estimates of gross and net proved
reserves of the Amoco Properties were prepared by the Company's engineers, and
estimates of gross reserves pertaining to the Amoco Properties representing
approximately 80% of the total proved value of such reserves, as determined
solely by the Company, have been reviewed by Williamson Petroleum Consultants,
Inc. ("Williamson"), independent petroleum engineers to the Company.
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FINANCING
The Company will purchase the Amoco Properties for $290 million in cash,
1,200,000 shares of Common Stock and the conveyance to Amoco of the Transferred
Properties, for a total purchase price of approximately $333 million. HSR will
finance the cash portion of the Amoco Purchase Price primarily through
borrowings under its revolving credit facility with The Chase Manhattan Bank, as
agent, which will be amended in connection with the Amoco Acquisition (the
"Proposed Chase Facility"). To reduce such indebtedness, the Company intends to
use the net proceeds from an offering of one or more types of equity securities
(the "Proposed Offering") combined with the proceeds from the monetization of
Section 29 tax credits and the sale or monetization of non-strategic properties.
There can be no assurance that the Company will be successful in consummating
the Proposed Offering, or that the timing, terms and conditions of any such
offering will be favorable to it.
OTHER MATTERS
Amoco has agreed not to sell any of the Amoco Shares until after the
consummation of the Proposed Offering, and not to sell 1,000,000 of such shares
for a period of 90 days after the closing of the Amoco Acquisition. The Company
has agreed to register the Amoco Shares after the consummation of the Proposed
Offering. Amoco has informed the Company that it intends to hold the Amoco
Shares for investment purposes.
As part of the consideration for the Amoco Properties, HSR conveyed to
Amoco the ownership of the Transferred Properties, which were attributed a value
in the Amoco Acquisition of $23.0 million. Net production from the Transferred
Properties as of December 1, 1997, is estimated by the Company to have been 8.8
MMcf of gas per day and 16 Bbls of oil (or 1.5 MBoe) per day.
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EFFECT OF THE AMOCO ACQUISITION
The Amoco Acquisition provides a portfolio of opportunities that will lead
to (i) a significant increase in oil and gas production (adding current net
daily production of 44.1 MMcf of gas and 1,400 Bbls of oil (or 8.8 MBoe) from
the Amoco Properties), (ii) a reduction in unit operating costs due in part to
increased production per wellbore, (iii) an increase in budgeted D-J Basin
capital spending to approximately $80 million for 1998 due to the addition of
infill, recompletion, deepening, refrac and drilling projects and the
anticipated increase in production and reserves, (iv) a decrease in general and
administrative expense on a per unit of production basis, and (v) an increase in
the monetization of Section 29 income tax credits generating approximately $2.5
million per year, net to the Company. The increase in production from the Amoco
Properties is partially offset by the current net production of 8.8 MMcf of gas
per day and 16 Bbls of oil (or 1.5 MBoe) per day attributable to the Transferred
Properties.
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Pursuant to the terms of the Amoco Acquisition, the Company is required to
deliver approximately $290 million in cash, 1,200,000 shares of Common Stock and
the Transferred Properties, valued at $23 million. Upon executing the definitive
agreement, the Company paid Amoco $33 million in cash as a deposit, which it
borrowed under the Company's existing credit facility (the "Chase Facility"),
with the remaining $257 million to be paid at closing. On November 10, 1997, the
Company received a commitment from Chase to amend the terms of the Chase
Facility, which is subject to completion of the Amoco Acquisition. The terms of
the Proposed Chase Facility would increase the maximum credit amount and the
Borrowing Base to $450 million and revise the interest rates to the Base Rate
plus 0.0% to 0.625% or LIBOR plus 0.75% to 1.625%. HSR intends to finance
substantially all of the remaining cash portion of the Amoco Purchase Price
through borrowings under the Proposed Chase Facility. The outstanding balance
under the Proposed Chase Facility is expected to be approximately $412 million
upon the closing of the Amoco Acquisition (after giving effect to the
monetization of certain Section 29 tax credits acquired in connection with the
Amoco Acquisition), leaving approximately $38 million available under the
Proposed Chase Facility.
The Company also maintains an arrangement with a Trust Company of the
West-related entity covering a $90 million non-recourse, volumetric overriding
royalty facility (the "TCW Facility") of which approximately $80 million is
available. The proceeds from the TCW Facility may be used by the Company at its
discretion for a variety of corporate purposes, including acquisitions of new
properties, exploration and development drilling and monetization of existing
corporate properties.
The Company anticipates that proceeds from the Proposed Offering as well as
from an anticipated offering of long-term senior subordinated notes will be
applied to repay outstanding borrowings under the Proposed Chase Facility.
Thereafter, the Company believes that available borrowing capacity under the
Proposed Chase Facility, combined with operating cash flow, the TCW Facility,
the monetization of Section 29 tax credits and sales or monetization of
non-strategic assets will provide it with the financial resources and
flexibility to fund current and ongoing development activities and to meet other
financial obligations. The Company's ability to realize the reserve and
production growth potential provided by the Amoco Acquisition is dependent in
large part upon its ability to obtain capital from the foregoing sources. There
can be no assurance that the Company will be successful in obtaining such
capital, or that the timing, terms and conditions applicable to any such sources
of capital will be favorable to it.
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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Report includes statements that are not purely historical and are
"forward-looking statements" within the meaning of Section 27A of the
Securities Act and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"), including statements regarding the Company's
expectations, hopes, beliefs, intentions or strategies regarding the future.
All statements other than statements of historical facts included herein,
regarding the Amoco Acquisition, reserves and their values (including reserves
acquired in the Amoco Acquisition), planned capital expenditures, financing
plans, increases in oil and gas production, the availability of financing, the
number and prospective nature of anticipated wells to be drilled in 1998 and
thereafter, development and exploitation potential, refrac potential,
recompletion potential, infill potential and expected regulatory approval
thereof, drillsite prospects, deepening potential, the potential to unlock
stranded reserves, reserve and production growth potential, potential,
anticipated operating efficiencies, anticipated finding, development, operating
and other cost savings, marketing benefits, extended reserve life and
additional lifting pressure, and the Company's financial position, business
strategy and other plans and objectives for future operations, potential
liabilities or the expected absence thereof, the potential outcome of
environmental matters, litigation and other proceedings, are forward-looking
statements. All forward-looking statements included herein are based on
information available to the Company on the date hereof, and the Company
assumes no obligation to update such forward-looking statements. Although the
Company believes that the assumptions and expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct or that the Company will take any
actions that may presently be planned. There are numerous uncertainties
inherent in estimating quantities of proved oil and gas reserves and projecting
future rates of production and timing of development expenditures, including
many factors beyond the control of the Company.
Many factors may affect the Company's expectations and plans. Capital
expenditure and financing plans may change in connection with the success of
drilling activities, the general availability of capital, interest rates,
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and cash flow available from operations. Cash flow available from operations may
change depending on costs of materials and services, regulatory burdens and
commodity prices. Oil and gas prices are volatile, and there are several
potentially significant adverse effects to the Company that can result if
product prices decline materially. First, lower product prices will adversely
impact the Company's cash flow and could cause the Company to (i) curtail its
capital program, (ii) borrow additional amounts under its revolving credit
agreement, or (iii) issue additional debt or equity securities. Second, lower
product prices could cause the borrowing base under the Company's bank credit
agreement to be reduced and certain covenant tests to be adversely affected.
Third, under rules promulgated by the Securities and Exchange Commission,
companies that follow the full cost accounting method are required to make
quarterly "ceiling test" calculations. Lower product prices adversely affect the
ceiling calculation. Should the Company realize sustained lower product prices,
it could be required to write down its oil and gas properties, resulting in a
non-cash charge against earnings.
Certain additional important factors that could cause actual results to
differ materially from the Company's forward-looking statements are disclosed
in the Company's Current Report on Form 8-K filed February 26, 1997. All
subsequent written or oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned hereunto duly authorized.
HS RESOURCES, INC.
By: /s/ JAMES M. PICCONE
---------------------------
James M. Piccone
Vice President
Dated: November 25, 1997.
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INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
23.1 Consent of Williamson Petroleum Consultants, Inc.
99.1 Certain Definitions
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EXHIBIT 23.1
CONSENT OF INDEPENDENT ENGINEERS
Williamson Petroleum Consultants, Inc. (Williamson) hereby consents to the
references to Williamson and our preliminary review entitled "Preliminary
Review of Reserves Assignment Methodologies and Gross Reserves Estimates
Prepared by HS Resources, Inc. on the Amoco Production Company DJ Basin Sales
Package, Williamson Project 7.8544" in the HS Resources, Inc. Registration
Statement on Form 8-K to be filed on December 9, 1997 with the Securities and
Exchange Commission.
/s/ WILLIAMSON PETROLEUM CONSULTANTS, INC.
Houston, Texas
December 9, 1997
<PAGE> 1
EXHIBIT 99.1
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Behind-pipe reserves. Proved reserves in a formation through which production
casing has already been set in the wellbore, but from which production has not
commenced.
Boe. Barrels of oil equivalent, determined using the ratio of six Mcf of
natural gas (including natural gas liquids) to one Bbl of crude oil or
condensate.
Btu. British thermal unit or units. One Btu is the heat required to raise the
temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
COPAS charge. A charge made by the operator of a well for the account of all
working interests, the payment of which constitutes reimbursement for the
operator's administrative costs attributable to operating the well.
Development location. A location on which a development well can be drilled.
Development well, development drilling. Drilling of a well within the proved
area of an oil or gas reservoir to the stratigraphic depth of a horizon known
to be productive in an attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or natural gas
in sufficient quantities to justify completion as an oil or gas well.
Estimated future net revenues. Revenues from production of oil and natural
gas, net of all production-related taxes, lease operating expenses and capital
costs.
Exploitation well or exploitation drilling. Drilling of wells in areas of
known production. However, because of geologic, reservoir and other
characteristics it is possible that an exploitation well may not encounter
commercial quantities of reserves. Therefore such wells carry somewhat greater
risk than development drilling. Oil and gas reserves associated with
exploitation wells are not typically considered to be proved.
Exploratory well or exploratory drilling. A well drilled to find and produce
oil or gas in an unproved area, to find a new reservoir in a field previously
found to be productive of oil or gas in another reservoir, or to extend a known
reservoir beyond existing defined limits.
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Farmout. An assignment of an interest in a drilling location and related
acreage, typically conditional upon the drilling of a well on that drilling
location.
Finding Cost. The capital costs associated with finding and developing oil and
natural gas reserves.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Held by production. Acreage covered by an oil and gas lease which has a
producing well on it, or which is pooled with a lease or leases having one or
more producing wells on them, so the lease is maintained in effect for the
duration of such production.
Henry Hub. The delivery point of the NYMEX natural gas contract, located in
southern Louisiana.
Horizontal drilling. Horizontal drilling involves deviating the angle of a
wellbore approximately 90 degrees from vertical to near horizontal in the
formation of interest. Horizontal drilling permits the wellbore to contact and
intersect a larger portion of the producing horizon than is permitted by
conventional vertical drilling techniques and can result in increased
production rates and greater ultimate recovery of hydrocarbons.
Hydraulic fracturing. A mechanical technique used to enhance productivity and
ultimate reserve recovery. Fluids and a proppant are injected into a particular
reservoir at rates and pressure sufficient to create a series of fractures or
cracks in that reservoir.
Increased density, or infill, drilling. Somewhat similar to development
drilling, increased density drilling involves wells drilled within the proved
area of an oil or gas reservoir to a zone known to be productive. However,
infill drilling generally involves an increase in well density based on
engineering and geological studies which demonstrate that the existing well
density does not adequately drain the reservoir.
Lead. An area with respect to which the Company has very preliminary
information warranting further geoscientific investigation and analysis with
the hope that one or more prospects may be developed.
Lease operating expense. All direct costs associated with and necessary to
operate a producing property.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent.
MBtu. One thousand Btus.
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent.
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MMBtu. One million Btus.
MMcf. One million cubic feet of natural gas.
Multi-pay horizons. A well bore with more than one zone that may potentially
produce oil and/or natural gas.
Net acres or net wells. The sum of the working interests owned in gross acres
or gross wells.
Present value of estimated future net revenues, pretax present value at
constant prices of estimated future net revenues. Estimated future net
revenues before income taxes, discounted by a factor of ten percent per annum
and with no price or cost escalation or de-escalation in accordance with
guidelines promulgated by the Commission.
Productive well. A well that is producing or that is capable of producing oil
or natural gas.
Prospect. An area with respect to which the Company has geologic and possibly
geophysical information and analysis indicating the possible presence of
producible hydrocarbons at one or more reasonably focused locations. The term
prospect refers to many types of areas with a wide range of completeness of
concept, information and analysis but, in any event, is based on more complete
information than a lead.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves. 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 existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be drilled
consistent with local spacing rules for the purpose of recovering proved
reserves.
Proved undeveloped reserves. 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.
Recompletions. Within an existing wellbore, a recompletion involves completion
for production of a formation other than those which have previously been
productive. It is the mechanism by which behind-pipe reserves become
productive.
Reserve replacement costs. Total costs incurred for exploration and
development, divided by reserves added from all sources, including reserve
discoveries, extensions and improved recovery additions, net of revisions to
reserve estimates and purchases of reserves in place.
Royalty interest, overriding royalty interest. An interest in an oil and
natural gas property entitling the owner to a share of oil and natural gas
production free of costs of drilling, completion and production.
Tcf. One trillion cubic feet of natural gas.
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3-D seismic projects. 3-D seismic projects involve the use of seismic
reflections to assist in mapping in three dimensions the structural and
stratigraphic aspects of certain reservoirs lending themselves to the
application of this advanced technology. Particularly when coupled with
advanced processing, interpretation, geostatistical techniques and interpretive
geology, this technology can materially reduce the risk associated with some
types of drilling.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Waterflood. A waterflood is the injection of water into a reservoir to (i)
fill pores vacated by produced fluids or (ii) push hydrocarbons from the
injector well to another wellbore from which reserves can be produced.
Waterfloods are intended to maintain reservoir pressure, assist production and
enhance reservoir recovery rates.
Wattenberg. The geographic region in the D-J Basin located approximately 35
miles north of Denver, where the J-Sand formation is productive, as well as
adjacent areas where the Codell, Niobrara, Sussex and Shannon formations are
productive.
Wellbore extension. A wellbore extension involves deepening an existing
wellbore to a new and deeper formation.
Working interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and entitles it
to ownership of a share of production.
